VALERO ENERGY CORP/TX - Quarter Report: 2014 March (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the Quarterly Period Ended March 31, 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 April 30, 2014 was 533,624,161.

VALERO ENERGY CORPORATION

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	Page
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of March 31, 2014 and December 31, 2013	1
Consolidated Statements of Income for the Three Months Ended March 31, 2014 and 2013	2
Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2014 and 2013	3
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 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	31
Item 3. Quantitative and Qualitative Disclosures About Market Risk	45
Item 4. Controls and Procedures	47
PART II – OTHER INFORMATION
Item 1. Legal Proceedings	47
Item 1A. Risk Factors	48
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	48
Item 6. Exhibits	49
SIGNATURE	50

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

VALERO ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars, Except Par Value)



	March 31, 2014			December 31, 2013
	(Unaudited)
ASSETS
Current assets:
Cash and temporary cash investments	$	3,647		$	4,292
Receivables, net	7,783			8,751
Inventories	7,106			5,758
Income taxes receivable	104			72
Deferred income taxes	256			266
Prepaid expenses and other	134			138
Total current assets	19,030			19,277
Property, plant, and equipment, at cost	34,235			33,933
Accumulated depreciation	(8,469		)	(8,226		)
Property, plant, and equipment, net	25,766			25,707
Deferred charges and other assets, net	2,303			2,276
Total assets	$	47,099		$	47,260
LIABILITIES AND EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	704		$	303
Accounts payable	9,617			9,931
Accrued expenses	488			522
Taxes other than income taxes	1,139			1,345
Income taxes payable	667			773
Deferred income taxes	311			249
Total current liabilities	12,926			13,123
Debt and capital lease obligations, less current portion	5,860			6,261
Deferred income taxes	6,615			6,601
Other long-term liabilities	1,290			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	7,134			7,187
Treasury stock, at cost; 140,081,386 and 137,932,138 common shares	(7,168		)	(7,054		)
Retained earnings	19,665			18,970
Accumulated other comprehensive income	277			350
Total Valero Energy Corporation stockholders’ equity	19,915			19,460
Noncontrolling interests	493			486
Total equity	20,408			19,946
Total liabilities and equity	$	47,099		$	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 March 31,
	2014			2013
Operating revenues	$	33,663		$	33,474
Costs and expenses:
Cost of sales	30,630			30,685
Operating expenses:
Refining	973			876
Retail	—			169
Ethanol	129			77
General and administrative expenses	160			176
Depreciation and amortization expense	421			430
Total costs and expenses	32,313			32,413
Operating income	1,350			1,061
Other income, net	15			14
Interest and debt expense, net of capitalized interest	(100		)	(83		)
Income before income tax expense	1,265			992
Income tax expense	429			340
Net income	836			652
Less: Net income (loss) attributable to noncontrolling interests	8			(2		)
Net income attributable to Valero Energy Corporation stockholders	$	828		$	654

Earnings per common share	$	1.55		$	1.18
Weighted-average common shares outstanding (in millions)	531			550

Earnings per common share – assuming dilution	$	1.54		$	1.18
Weighted-average common shares outstanding – assuming dilution (in millions)	536			556
Dividends per common share	$	0.25		$	0.20

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 March 31,
	2014			2013
Net income	$	836		$	652

Other comprehensive income (loss):
Foreign currency translation adjustment	(74		)	(204		)
Net gain (loss) on pension and other postretirement benefits	(2		)	336
Net gain (loss) on derivative instruments designated and qualifying as cash flow hedges	4			(2		)
Other comprehensive income (loss) before income tax expense	(72		)	130
Income tax expense related to items of other comprehensive income (loss)	1			117
Other comprehensive income (loss)	(73		)	13

Comprehensive income	763			665
Less: Comprehensive income (loss) attributable to noncontrolling interests	8			(2		)
Comprehensive income attributable to Valero Energy Corporation stockholders	$	755		$	667

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of Dollars)

(Unaudited)



	Three Months Ended March 31,
	2014			2013
Cash flows from operating activities:
Net income	$	836		$	652
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	421			430
Deferred income tax expense	88			173
Changes in current assets and current liabilities	(1,088		)	255
Changes in deferred charges and credits and other operating activities, net	(13		)	39
Net cash provided by operating activities	244			1,549
Cash flows from investing activities:
Capital expenditures	(388		)	(577		)
Deferred turnaround and catalyst costs	(129		)	(287		)
Other investing activities, net	(41		)	4
Net cash used in investing activities	(558		)	(860		)
Cash flows from financing activities:
Repayment of debt	—			(180		)
Proceeds from the exercise of stock options	24			38
Purchase of common stock for treasury	(226		)	(304		)
Common stock dividends	(133		)	(111		)
Contributions from noncontrolling interests	—			13
Distributions to public unitholders of Valero Energy Partners LP	(1		)	—
Other financing activities, net	24			22
Net cash used in financing activities	(312		)	(522		)
Effect of foreign exchange rate changes on cash	(19		)	(33		)
Net increase (decrease) in cash and temporary cash investments	(645		)	134
Cash and temporary cash investments at beginning of period	4,292			1,723
Cash and temporary cash investments at end of period	$	3,647		$	1,857

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 months ended March 31, 2014 and 2013 included in these Condensed Notes to Consolidated Financial Statements is derived from our unaudited financial statements. Operating results for the three months ended March 31, 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.

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.

New Accounting Pronouncement

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

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.


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. VLP’s assets include 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 March 31, 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 $384 million and $375 million as of March 31, 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 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 March 31, 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 where VLP provides commercial transportation and terminaling services to us. These transactions are eliminated in consolidation.

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


3.	INVENTORIES

Inventories consisted of the following (in millions):



	March 31, 2014		December 31, 2013
Refinery feedstocks	$	3,500	$	2,135
Refined products and blendstocks	3,129		3,231
Ethanol feedstocks and products	247		166
Materials and supplies	230		226
Inventories	$	7,106	$	5,758

As of March 31, 2014 and December 31, 2013, the replacement cost (market value) of last in, first out (LIFO) inventories exceeded their LIFO carrying amounts by approximately $7.1 billion and $6.9 billion, respectively. As of March 31, 2014 and December 31, 2013, our non-LIFO inventories accounted for $924 million and $851 million, respectively, of our total inventories.


4.	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 March 31, 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. VLP has the option to increase the aggregate commitments under the VLP Revolver to $500 million, subject to, among other things, the consent of the existing lenders whose commitments will be increased or any additional lenders providing such additional capacity. VLP’s obligations under the VLP Revolver will be jointly and severally guaranteed by all of VLP’s directly owned material subsidiaries. As of March 31, 2014 and December 31, 2013, the only guarantor under the VLP Revolver was Valero Partners Operating Co. LLC, a wholly owned subsidiary of VLP. The VLP Revolver has certain restrictive covenants, including a ratio of total debt to EBITDA (as defined in the VLP Revolver) for the prior four fiscal quarters of not greater than 5.0 to 1.0 as of the last day of each fiscal quarter, and limitations on VLP’s ability to pay distributions to its unitholders. As of March 31, 2014, VLP’s debt to EBITDA ratio, calculated in accordance with the terms of the VLP Revolver, was 0.1 to 1.0. We believe that VLP will remain in compliance with this covenant.

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

Activities Under Our Credit Facilities

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

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



				Amounts Outstanding
	Borrowing Capacity		Expiration	March 31, 2014		December 31, 2013
Letter of credit facilities	$	550	June 2014	$	258	$	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 March 31, 2014 and December 31, 2013, we had $414 million and $189 million, respectively, of letters of credit outstanding under our uncommitted short-term bank credit facilities.

Non-Bank Debt

We made no scheduled debt repayments during the three months ended March 31, 2014, but we made a scheduled debt repayment of $200 million related to our 4.75% senior notes in April 2014. During the three months ended March 31, 2013, we made a scheduled debt repayment of $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 2013, we amended this facility to extend the maturity date to July 2014. Proceeds from the sale of receivables under this facility are reflected as debt. Under this program, one of our marketing subsidiaries (Valero Marketing) sells eligible receivables, without recourse, to another of our subsidiaries (Valero Capital), whereupon the receivables are no longer owned by Valero Marketing. Valero Capital, in turn, sells an undivided percentage ownership interest in the eligible receivables, without recourse, to the third-party entities and financial institutions. To the extent that Valero Capital retains an ownership interest in the receivables it has purchased from Valero Marketing, such interest is included in our financial statements solely as a result of the consolidation of the financial statements of Valero Capital with those of Valero Energy Corporation; the receivables are not available to satisfy the claims of the creditors of Valero Marketing or Valero Energy Corporation.

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Capitalized Interest

Capitalized interest was $17 million and $40 million for the three months ended March 31, 2014 and 2013, respectively.


5.	COMMITMENTS AND CONTINGENCIES

Environmental Matter

We are involved, together with several other companies, in an environmental cleanup in the Village of Hartford, Illinois (the Village) and the adjacent shutdown refinery site, which we acquired as part of a prior acquisition. In cooperation with some of the other companies, we have been conducting initial mitigation and cleanup response pursuant to an administrative order issued by the U.S. Environmental Protection Agency (EPA). The EPA is seeking further cleanup obligations from us and other potentially responsible parties for the Village. In parallel with the Village cleanup, we are also in litigation with the State of Illinois Environmental Protection Agency and other potentially responsible parties relating to the remediation of the shutdown refinery site. In each of these matters, we have various defenses and rights for contribution from the other 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.

Aruba Refinery

During 2012, we suspended the operations of the Aruba Refinery and recognized an impairment loss with respect to all of the refinery’s long-lived assets, except for certain terminal assets that we continue to operate. We have not, however, abandoned the refinery. Should we ultimately decide to abandon the refinery, we may be required under our land lease agreement with the Government of Aruba to dismantle and remove the abandoned assets. This would require us to recognize an asset retirement obligation that would be charged to expense. We do not expect these amounts to be material to our financial position or results of operations.

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


6.	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):



	Three Months Ended March 31,
	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)	828			8			836			654			(2		)	652
Dividends	(133		)	—			(133		)	(111		)	—			(111		)
Stock-based compensation expense	10			—			10			11			—			11
Tax deduction in excess of stock-based compensation expense	25			—			25			24			—			24
Transactions in connection with stock-based compensation plans:
Stock issuances	24			—			24			38			—			38
Stock repurchases	(17		)	—			(17		)	(24		)	—			(24		)
Stock repurchases under buyback program	(209		)	—			(209		)	(294		)	—			(294		)
Contributions from noncontrolling interests	—			—			—			—			14			14
Distributions to public unitholders of Valero Energy Partners LP	—			(1		)	(1		)	—			—			—
Other comprehensive income (loss)	(73		)	—			(73		)	13			—			13
Balance as of end of period	$	19,915		$	493		$	20,408		$	18,343		$	75		$	18,418

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

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Share Activity

Activity in the number of shares of common stock and treasury stock was as follows (in millions):



	Three Months Ended March 31,
	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	—	—		—	—
Stock repurchases under buyback program	—	(4	)	—	(7	)
Balance as of end of period	673	(140	)	673	(125	)

Common Stock Dividends

On May 1, 2014, our board of directors declared a quarterly cash dividend of $0.25 per common share payable on June 18, 2014 to holders of record at the close of business on May 21, 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 March 31,
	2014									2013
	Before-Tax Amount			Tax Expense (Benefit)			Net Amount			Before-Tax Amount			Tax Expense (Benefit)			Net Amount
Foreign currency translation adjustment	$	(74	)	$	—		$	(74	)	$	(204	)	$	—		$	(204	)
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	8			3			5			14			5			9
Prior service credit	(10		)	(3		)	(7		)	(6		)	(2		)	(4		)
Net gain (loss) on pension and other postretirement benefits	(2		)	—			(2		)	336			118			218
Derivative instruments designated and qualifying as cash flow hedges:
Net gain arising during the period	7			2			5			1			—			1
Net gain reclassified into income	(3		)	(1		)	(2		)	(3		)	(1		)	(2		)
Net gain (loss) on cash flow hedges	4			1			3			(2		)	(1		)	(1		)
Other comprehensive income (loss)	$	(72	)	$	1		$	(73	)	$	130		$	117		$	13

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 Pension Items			Gains and (Losses) on Cash Flow Hedges			Total
Balance as of December 31, 2013	$	408		$	(58	)	$	—		$	350
Other comprehensive income (loss) before reclassifications	(74		)	—			5			(69		)
Amounts reclassified from accumulated other comprehensive income	—			(2		)	(2		)	(4		)
Net other comprehensive income (loss)	(74		)	(2		)	3			(73		)
Balance as of March 31, 2014	$	334		$	(60	)	$	3		$	277



	Foreign Currency Translation Adjustment			Defined Benefit Pension Items			Gains and (Losses) on Cash Flow Hedges			Total
Balance as of December 31, 2012	$	665		$	(558	)	$	1		$	108
Other comprehensive income (loss) before reclassifications	(204		)	213			1			10
Amounts reclassified from accumulated other comprehensive income	—			5			(2		)	3
Net other comprehensive income (loss)	(204		)	218			(1		)	13
Balance as of March 31, 2013	$	461		$	(340	)	$	—		$	121

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Amounts reclassified out of accumulated other comprehensive income (loss) and into net income were as follows (in millions):



Details about Accumulated Other Comprehensive Income Components							Affected Line Item in the Statement of Income

	Three Months Ended March 31,
	2014			2013
Amortization of items related to defined benefit pension plans:
Net actuarial loss	$	(8	)	$	(14	)	(a)
Prior service credit	10			6			(a)
	2			(8		)	Total before tax
	—			3			Tax benefit
	$	2		$	(5	)	Net of tax

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

Total reclassifications for the period	$	4		$	(3	)	Net of tax

_________________________


(a)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost, as further discussed in Note 7. Net periodic benefit cost is reflected in operating expenses and general and administrative expenses.

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7.	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 March 31:
Service cost	$	30		$	36		$	2		$	3
Interest cost	23			22			4			4
Expected return on plan assets	(33		)	(32		)	—			—
Amortization of:
Prior service credit	(5		)	(3		)	(5		)	(3		)
Net actuarial loss	8			14			—			—
Net periodic benefit cost	$	23		$	37		$	1		$	4

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 three months ended March 31, 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 $10 million and $8 million, respectively, to our pension plans and $4 million and $4 million, respectively, to our other postretirement benefit plans during the three months ended March 31, 2014 and 2013.

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8.	EARNINGS PER COMMON SHARE

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



	Three Months Ended March 31,
	2014				2013
	Restricted Stock		Common Stock		Restricted Stock		Common Stock
Earnings per common share:
Net income attributable to Valero stockholders			$	828			$	654
Less dividends paid:
Common stock			132				110
Nonvested restricted stock			1				1
Undistributed earnings			$	695			$	543
Weighted-average common shares outstanding	2		531		3		550
Earnings per common share:
Distributed earnings	$	0.25	$	0.25	$	0.20	$	0.20
Undistributed earnings	1.30		1.30		0.98		0.98
Total earnings per common share	$	1.55	$	1.55	$	1.18	$	1.18

Earnings per common share – assuming dilution:
Net income attributable to Valero stockholders			$	828			$	654
Weighted-average common shares outstanding			531				550
Common equivalent shares:
Stock options			3				4
Performance awards and nonvested restricted stock			2				2
Weighted-average common shares outstanding – assuming dilution			536				556
Earnings per common share – assuming dilution			$	1.54			$	1.18

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



	Three Months Ended March 31,
	2014	2013
Stock options	1	3


9.	SEGMENT INFORMATION

In May 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 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 (our former retail business), which were eliminated in consolidation prior to the separation, are reported as refining segment operating revenues from external customers after May 1, 2013.

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



	Refining		Ethanol		Retail		Corporate			Total
Three months ended March 31, 2014:
Operating revenues from external customers	$	32,452	$	1,211	$	—	$	—		$	33,663
Intersegment revenues	—		25		—		—			25
Operating income (loss)	1,279		243		—		(172		)	1,350

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

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



	March 31, 2014		December 31, 2013
Refining	$	41,235	$	40,834
Ethanol	1,003		889
Corporate	4,861		5,537
Total assets	$	47,099	$	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.


10.	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):



	Three Months Ended March 31,
	2014			2013
Decrease (increase) in current assets:
Receivables, net	$	958		$	409
Inventories	(1,356		)	(1,074		)
Income taxes receivable	(31		)	79
Prepaid expenses and other	—			(233		)
Increase (decrease) in current liabilities:
Accounts payable	(299		)	561
Accrued expenses	(50		)	181
Taxes other than income taxes	(198		)	318
Income taxes payable	(112		)	14
Changes in current assets and current liabilities	$	(1,088	)	$	255

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;


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

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


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

There were no significant noncash investing or financing activities for the three months ended March 31, 2014 and 2013.

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



	Three Months Ended March 31,
	2014		2013
Interest paid in excess of amount capitalized	$	74	$	56
Income taxes paid, net	459		48


11.	FAIR VALUE MEASUREMENTS

General

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

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.”

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

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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.

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 March 31, 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.



	March 31, 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	$	709	$	163	$	—	$	872	$	(759	)	$	(24	)	$	89	$	—
Physical purchase contracts	—		2		—		2		n/a			n/a			2		n/a
Investments of certain benefit plans	99		—		11		110		n/a			n/a			110		n/a
Total	$	808	$	165	$	11	$	984	$	(759	)	$	(24	)	$	201

Liabilities:
Commodity derivative contracts	$	643	$	149	$	—	$	792	$	(759	)	$	(31	)	$	2	$	(66	)
Biofuels blending obligation	—		75		—		75		n/a			n/a			75		n/a
Physical purchase contracts	—		1		—		1		n/a			n/a			1		n/a
Foreign currency contracts	9		—		—		9		n/a			n/a			9		n/a
Total	$	652	$	225	$	—	$	877	$	(759	)	$	(31	)	$	87

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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 12, 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 12, 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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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 12 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 March 31, 2014 and December 31, 2013 that were measured at fair value on a recurring basis.

There was no activity during the three months ended March 31, 2014 and 2013 related to the fair value amounts categorized in Level 3 as of March 31, 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 March 31, 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):



	March 31, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets:
Cash and temporary cash investments	$	3,647	$	3,647	$	4,292	$	4,292
Financial liabilities:
Debt (excluding capital leases)	6,526		7,883		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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12.	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 11), 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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•	Fair Value Hedges – Fair value hedges are used to hedge price volatility in certain refining inventories and firm commitments to purchase inventories. The level of activity for our fair value hedges is based on the level of our operating inventories, and generally represents the amount by which our inventories differ from our previous year-end LIFO inventory levels.

As of March 31, 2014, we had the following outstanding commodity derivative instruments that were entered into to hedge crude oil and refined product inventories and commodity derivative instruments related to the physical purchase of crude oil and refined products at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).



		Notional Contract Volumes by Year of Maturity
Derivative Instrument		2014
Crude oil and refined products:
Futures – long		2,229
Futures – short		2,905
Physical contracts – long		676


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

As of March 31, 2014, we had the following outstanding commodity derivative instruments that were entered into to hedge forecasted purchases or sales of crude oil and refined products. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).



		Notional Contract Volumes by Year of Maturity
Derivative Instrument		2014
Crude oil and refined products:
Futures – long		13,578
Futures – short		10,312
Physical contracts – short		3,266

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•

Economic Hedges – Economic hedges represent commodity derivative instruments that are not designated as fair value or cash flow hedges and are used to manage price volatility in certain (i) refinery feedstock, refined product, 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 March 31, 2014, we had the following outstanding commodity derivative instruments that were used as economic hedges and commodity derivative instruments related to the physical purchase of corn at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except those identified as corn contracts that are presented in thousands of bushels, 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	10,260	—
Swaps – short	10,551	—
Futures – long	68,833	14
Futures – short	95,621	—
Corn:
Futures – long	12,085	—
Futures – short	32,130	2,075
Physical contracts – long	16,957	2,157
Soybean oil:
Futures – short	99,540	—

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•	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 March 31, 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 and corn contracts that are presented in thousands of bushels).



	Notional Contract Volumes by Year of Maturity
Derivative Instrument	2014	2015
Crude oil and refined products:
Swaps – long	17,760	—
Swaps – short	17,760	—
Futures – long	97,715	8,940
Futures – short	97,631	8,940
Options – long	12,700	—
Options – short	13,150	—
Natural gas:
Futures – long	1,000	1,500
Futures – short	750	—
Options – long	500	—
Corn:
Futures – long	145	—
Futures – short	145	—

Interest Rate Risk

Our primary market risk exposure for changes in interest rates relates to our debt obligations. We manage our exposure to changing interest rates through the use of a combination of fixed-rate and floating-rate debt. In addition, at times we have used interest rate swap agreements to manage our fixed to floating interest rate position by converting certain fixed-rate debt to floating-rate debt. We had no interest rate derivative instruments outstanding as of March 31, 2014 or December 31, 2013, or during the three months ended March 31, 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 March 31, 2014, we had commitments to purchase $999 million of

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U.S. dollars. The majority of these commitments matured on or before April 30, 2014, resulting in an immaterial loss in the second quarter of 2014.

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 $92 million and $130 million for the three months ended March 31, 2014 and 2013, respectively. These amounts are reflected in cost of sales.

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Fair Values of Derivative Instruments

The following tables provide information about the fair values of our derivative instruments as of March 31, 2014 and December 31, 2013 (in millions) and the line items in the balance sheets in which the fair values are reflected. See Note 11 for additional information related to the fair values of our derivative instruments.

As indicated in Note 11, we net fair value amounts recognized for multiple similar derivative contracts executed with the same counterparty under master netting arrangements, including cash collateral assets and obligations. The tables below, however, are presented on a gross asset and gross liability basis, which results in the reflection of certain assets in liability accounts and certain liabilities in asset accounts.



	Balance Sheet Location	March 31, 2014
	Balance Sheet Location	Asset Derivatives		Liability Derivatives
Derivatives designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	19	$	23

Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	690	$	620
Swaps	Receivables, net	159		142
Swaps	Accrued expenses	3		5
Options	Receivables, net	1		2
Physical purchase contracts	Inventories	2		1
Foreign currency contracts	Accrued expenses	—		9
Total		$	855	$	779
Total derivatives		$	874	$	802

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	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 March 31, 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 March 31,
Derivatives in Fair Value Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	2014			2013
Commodity contracts:
Loss recognized in income on derivatives	Cost of sales	$	(31	)	$	(1	)
Gain recognized in income on hedged item	Cost of sales	30			—
Loss recognized in income on derivatives (ineffective portion)	Cost of sales	(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 months ended March 31, 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 months ended March 31, 2014 and 2013.



Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended March 31,
Derivatives in Cash Flow Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	2014			2013
Commodity contracts:
Gain recognized in OCI on derivatives (effective portion)		$	7		$	1
Gain reclassified from accumulated OCI into income (effective portion)	Cost of sales	3			3
Loss recognized in income on derivatives (ineffective portion)	Cost of sales	(4		)	(1		)

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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 months ended March 31, 2014 and 2013. For the three months ended March 31, 2014, cash flow hedges primarily related to forward purchases of crude oil, with $3 million of cumulative after-tax gains on cash flow hedges remaining in accumulated other comprehensive income. We estimate that this deferred gain will be reclassified into cost of sales over the next 12 months as a result of hedged transactions that are forecasted to occur. For the three months ended March 31, 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 Recognized in Income on Derivatives	Three Months Ended March 31,
	Location of Gain Recognized in Income on Derivatives	2014		2013
Commodity contracts	Cost of sales	$	4	$	35
Foreign currency contracts	Cost of sales	9		25
Total		$	13	$	60



Trading Derivatives	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended March 31,
Trading Derivatives	Location of Gain (Loss) Recognized in Income on Derivatives	2014			2013
Commodity contracts	Cost of sales	$	(1	)	$	2
RINs fixed-price contracts	Cost of sales	—			(13		)
Total		$	(1	)	$	(11	)

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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 first quarter of 2014, we reported net income attributable to Valero stockholders of $828 million, or $1.54 per share (assuming dilution), compared to $654 million, or $1.18 per share (assuming dilution), for the first quarter of 2013.

The increase in net income attributable to Valero stockholders of $174 million was primarily due to the increase of $289 million in our operating income as outlined by business segment in the table below (in millions).



	Three Months Ended March 31,
	2014			2013			Change
Operating income (loss) by business segment:
Refining	$	1,279		$	1,212		$	67
Retail	—			42			(42		)
Ethanol	243			14			229
Corporate	(172		)	(207		)	35
Total	$	1,350		$	1,061		$	289

The $67 million increase in refining segment operating income in the first quarter of 2014 compared to the first quarter of 2013 was primarily due 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.

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 first quarter of 2014, resulting in the $42 million decrease in retail segment operating income in the first quarter of 2014 compared to the first quarter of 2013.

Our ethanol segment operating income increased $229 million in the first quarter of 2014 compared to the first quarter of 2013 due to higher gross margin per gallon and higher production volumes. Significantly lower corn prices combined with higher ethanol prices quarter over quarter contributed to the increase in gross margin per gallon. Production volumes increased between the quarters in response to the improved ethanol gross margin per gallon.

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 first quarter of 2014 widened compared to the first quarter of 2013, which positively impacted our refining margins. Thus far in the second quarter of 2014, discounts on crude oils have shown mixed results compared to the first quarter of 2014 as some crude oil discounts have widened while others have narrowed, and we expect these discounts to remain volatile. Gasoline margins, which were seasonally weak during the first quarter of 2014, have increased in the second quarter and look positive as the summer driving season

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approaches. 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 second quarter of 2014, ethanol margins have narrowed substantially. This is primarily due to lower ethanol prices as the weather-related transportation issues that limited supplies and production in the first quarter of 2014 are being resolved. We expect lower average ethanol margins for the remainder of 2014 as compared to the first quarter of 2014.

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

(millions of dollars, except per share amounts)



	Three Months Ended March 31,
	2014			2013			Change
Operating revenues	$	33,663		$	33,474		$	189
Costs and expenses:
Cost of sales	30,630			30,685			(55		)
Operating expenses:
Refining	973			876			97
Retail	—			169			(169		)
Ethanol	129			77			52
General and administrative expenses	160			176			(16		)
Depreciation and amortization expense:
Refining	397			358			39
Retail	—			30			(30		)
Ethanol	12			11			1
Corporate	12			31			(19		)
Total costs and expenses	32,313			32,413			(100		)
Operating income	1,350			1,061			289
Other income, net	15			14			1
Interest and debt expense, net of capitalized interest	(100		)	(83		)	(17		)
Income before income tax expense	1,265			992			273
Income tax expense	429			340			89
Net income	836			652			184
Less: Net income (loss) attributable to noncontrolling interests	8			(2		)	10
Net income attributable to Valero stockholders	$	828		$	654		$	174

Earnings per common share – assuming dilution	$	1.54		$	1.18		$	0.36

________________

See note references on page 38.

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Refining Operating Highlights

(millions of dollars, except per barrel amounts)



	Three Months Ended March 31,
	2014		2013		Change
Refining:
Operating income	$	1,279	$	1,212	$	67
Throughput margin per barrel (a)	$	10.90	$	10.59	$	0.31
Operating costs per barrel:
Operating expenses	4.00		3.79		0.21
Depreciation and amortization expense	1.64		1.55		0.09
Total operating costs per barrel	5.64		5.34		0.30
Operating income per barrel	$	5.26	$	5.25	$	0.01

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude	478		494		(16		)
Medium/light sour crude	510		419		91
Sweet crude	1,063		1,089		(26		)
Residuals	203		224		(21		)
Other feedstocks	128		83		45
Total feedstocks	2,382		2,309		73
Blendstocks and other	319		257		62
Total throughput volumes	2,701		2,566		135

Yields (thousand barrels per day):
Gasolines and blendstocks	1,296		1,198		98
Distillates	1,024		909		115
Other products (b)	415		480		(65		)
Total yields	2,735		2,587		148

_______________

See note references on page 38.

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Refining Operating Highlights by Region (c)

(millions of dollars, except per barrel amounts)



	Three Months Ended March 31,
	2014			2013			Change
U.S. Gulf Coast:
Operating income	$	882		$	591		$	291
Throughput volumes (thousand barrels per day)	1,584			1,421			163
Throughput margin per barrel (a)	$	11.47		$	10.00		$	1.47
Operating costs per barrel:
Operating expenses	3.61			3.77			(0.16		)
Depreciation and amortization expense	1.67			1.61			0.06
Total operating costs per barrel	5.28			5.38			(0.10		)
Operating income per barrel	$	6.19		$	4.62		$	1.57

U.S. Mid-Continent:
Operating income	$	230		$	477		$	(247	)
Throughput volumes (thousand barrels per day)	398			424			(26		)
Throughput margin per barrel (a)	$	12.60		$	17.41		$	(4.81	)
Operating costs per barrel:
Operating expenses	4.45			3.37			1.08
Depreciation and amortization expense	1.73			1.55			0.18
Total operating costs per barrel	6.18			4.92			1.26
Operating income per barrel	$	6.42		$	12.49		$	(6.07	)

North Atlantic:
Operating income	$	198		$	186		$	12
Throughput volumes (thousand barrels per day)	470			485			(15		)
Throughput margin per barrel (a)	$	9.47		$	8.45		$	1.02
Operating costs per barrel:
Operating expenses	3.71			3.32			0.39
Depreciation and amortization expense	1.07			0.86			0.21
Total operating costs per barrel	4.78			4.18			0.60
Operating income per barrel	$	4.69		$	4.27		$	0.42

U.S. West Coast:
Operating loss	$	(31	)	$	(42	)	$	11
Throughput volumes (thousand barrels per day)	249			236			13
Throughput margin per barrel (a)	$	7.24		$	6.26		$	0.98
Operating costs per barrel:
Operating expenses	6.34			5.68			0.66
Depreciation and amortization expense	2.29			2.56			(0.27		)
Total operating costs per barrel	8.63			8.24			0.39
Operating loss per barrel	$	(1.39	)	$	(1.98	)	$	0.59

Total refining operating income	$	1,279		$	1,212		$	67

_______________

See note references on page 38.

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Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)



	Three Months Ended March 31,
	2014		2013			Change
Feedstocks:
Brent crude oil	$	107.90	$	112.63		$	(4.73	)
Brent less West Texas Intermediate (WTI) crude oil	9.18		18.33			(9.15		)
Brent less Alaska North Slope (ANS) crude oil	2.05		2.31			(0.26		)
Brent less Louisiana Light Sweet (LLS) crude oil	2.90		(2.49		)	5.39
Brent less Mars crude oil	6.42		2.32			4.10
Brent less Maya crude oil	18.44		9.68			8.76
LLS crude oil	105.00		115.12			(10.12		)
LLS less Mars crude oil	3.52		4.81			(1.29		)
LLS less Maya crude oil	15.54		12.17			3.37
WTI crude oil	98.72		94.30			4.42

Natural gas (dollars per million British thermal units (MMBtu))	5.23		3.43			1.80

Products:
U.S. Gulf Coast:
CBOB gasoline less Brent	1.78		4.70			(2.92		)
Ultra-low-sulfur diesel less Brent	15.16		16.97			(1.81		)
Propylene less Brent	2.63		6.48			(3.85		)
CBOB gasoline less LLS	4.68		2.21			2.47
Ultra-low-sulfur diesel less LLS	18.06		14.48			3.58
Propylene less LLS	5.53		3.99			1.54
U.S. Mid-Continent:
CBOB gasoline less WTI (d)	13.10		23.83			(10.73		)
Ultra-low-sulfur diesel less WTI	25.87		35.48			(9.61		)
North Atlantic:
CBOB gasoline less Brent	5.39		9.34			(3.95		)
Ultra-low-sulfur diesel less Brent	22.61		18.70			3.91
U.S. West Coast:
CARBOB 87 gasoline less ANS	10.20		14.10			(3.90		)
CARB diesel less ANS	17.44		21.37			(3.93		)
CARBOB 87 gasoline less WTI	17.33		30.12			(12.79		)
CARB diesel less WTI	24.57		37.39			(12.82		)
New York Harbor corn crush (dollars per gallon)	1.20		(0.08		)	1.28

_______________

See note references on page 38.

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Retail and Ethanol Operating Highlights

(millions of dollars, except per gallon amounts)



	Three Months Ended March 31,
	2014		2013		Change
Ethanol:
Operating income	$	243	$	14	$	229
Production (thousand gallons per day)	3,095		2,712		383
Gross margin per gallon of production (a)	$	1.38	$	0.42	$	0.96
Operating costs per gallon of production:
Operating expenses	0.46		0.31		0.15
Depreciation and amortization expense	0.05		0.05		—
Total operating costs per gallon of production	0.51		0.36		0.15
Operating income (loss) per gallon of production	$	0.87	$	0.06	$	0.81

Retail:
Operating income	$	—	$	42	$	(42	)

_______________

See note references below.

The following notes relate to references on pages 34 through 38.


(a)	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.


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

(c)

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


(d)	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 $189 million (or 1 percent) in the first quarter of 2014 compared to the first quarter of 2013 primarily as a result of increased revenues from our ethanol segment due to an increase in both the price of ethanol and an increase in volumes quarter over quarter. Operating income increased $289 million in the first quarter of 2014 compared to the first quarter of 2013 primarily due to a $229 million increase in ethanol segment operating income and a $67 million increase in refining segment operating income, partially offset by a $42 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 $67 million from $1.2 billion in the first quarter of 2013 to $1.3 billion in the first quarter of 2014, primarily due to a $203 million increase in refining margin partially

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offset by a $97 million increase in operating expenses and a $39 million increase in depreciation and amortization expense.

Refining margin increased $203 million for the first quarter of 2014 compared to the first quarter of 2013 primarily due 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 first 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 $2.90 per barrel to Brent crude oil during the first quarter of 2014 compared to a premium of $2.49 per barrel during the first quarter of 2013, representing a favorable increase of $5.39 per barrel. Another example is Maya crude oil, which is a sour crude oil, which sold at a discount of $18.44 per barrel to Brent crude oil during the first quarter of 2014 compared to a discount of $9.68 per barrel during the first quarter of 2013, representing a favorable increase of $8.76 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 $18.33 per barrel in the first quarter of 2013 to $9.18 per barrel in the first quarter of 2014, representing an unfavorable decrease of $9.15 per barrel. 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 $160 million and $400 million, respectively, quarter over quarter.


•	Higher throughput volumes - Refining throughput volumes increased by 135,000 barrels per day in the first quarter of 2014 compared to the first quarter of 2013. We estimate that the increase in refining throughput volumes had a positive impact on our refining margin of approximately $130 million for all regions quarter over quarter.

•

Lower costs of biofuel credits - As more fully described in Note 12 of Condensed Notes to Consolidated Financial Statements, we must purchase biofuel credits in order to meet our biofuel blending obligation under various government and regulatory compliance programs. The cost of these credits (primarily Renewable Identification Numbers (RINs) in the U.S.) decreased by $38 million from $130 million for the first quarter of 2013 to $92 million for the first quarter of 2014. This decrease was primarily due to a drop in the market prices of RINs.

•

Decrease in gasoline margins - We experienced a decline in gasoline margins throughout all our regions during the first quarter of 2014 compared to the first quarter of 2013. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast CBOB gasoline was $1.78 per barrel during the first quarter of 2014 compared to $4.70 per barrel during the first quarter of 2013, representing an unfavorable decrease of $2.92 per barrel. We estimate that the declines in gasoline margins per barrel during the first quarter of 2014 compared to the first quarter of 2013 had a negative impact to our refining margin of approximately $250 million for all refining regions.

•

Decrease in distillate margins - We experienced a decline in distillate margins for most of our regions during the first quarter of 2014 compared to the first quarter of 2013. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was $16.97 per barrel for the first quarter of 2013 compared to $15.16 per barrel for the first quarter of 2014, representing an

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unfavorable decrease of $1.81 per barrel. We estimate that the decline in distillate margins per barrel during the first quarter of 2014 compared to the first quarter of 2013 had a negative impact to our refining margin of approximately $100 million for all refining regions.

•

Lower discounts on other feedstocks - Certain of our processing units, including the hydrocracker units at our St. Charles and Port Arthur Refineries in our U.S. Gulf Coast region, utilize residuals and other feedstocks such as vacuum gas oil. We experienced a decrease in our discounts for these types of feedstocks in the U.S. Gulf Coast region during the first quarter of 2014 compared to the first quarter of 2013 primarily due to the tighter supply of other feedstocks in the region. We estimate that the decrease in the discount in other feedstocks that we processed had a negative impact to our refining margin of approximately $180 million quarter over quarter.

The increase of $97 million in operating expenses was primarily due to a $74 million increase in energy costs related to higher natural gas prices ($5.23 per MMBtu for the first quarter of 2014 compared to $3.43 per MMBtu for the first quarter of 2013), which were due to the severe winter weather in the U.S., and higher use of natural gas at our refineries.

The increase of $39 million in depreciation and amortization expense was primarily due to additional depreciation expense of $12 million associated with the new hydrocracker at our St. Charles Refinery that began operating in July 2013 and an increase in refinery turnaround and catalyst amortization expense of $13 million resulting from the completion of turnaround projects at our Texas City and Quebec City Refineries.

Ethanol

Ethanol segment operating income was $243 million in the first quarter of 2014 compared to $14 million in the first quarter of 2013. The $229 million increase in operating income was primarily due to a $282 million increase in gross margin (a $0.96 per gallon increase), partially offset by a $52 million increase in operating expenses.

Ethanol gross margin per gallon increased to $1.38 per gallon in the first quarter of 2014 from $0.42 per gallon in the first quarter of 2013 primarily due 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 corn price was $4.53 per bushel in the first quarter of 2014 compared to $7.16 per bushel in the first quarter of 2013. The decrease in the price of corn that we processed during the first quarter of 2014 favorably impacted our ethanol margin by approximately $240 million.

•

Higher ethanol prices - Low industry ethanol inventories caused by weather-related rail disruptions and low import volumes positively impacted ethanol prices. For example, the New York Harbor ethanol price was $2.85 per gallon in the first quarter of 2014 compared to $2.52 per gallon in the first quarter of 2013. The increase in the price of ethanol per gallon during the first quarter of 2014 had a favorable impact to our ethanol margin of approximately $40 million.

The $52 million increase in operating expenses during the first quarter of 2014 was primarily due to a $39 million increase in natural gas expense primarily resulting from higher natural gas prices ($5.23 per MMBtu for the first quarter of 2014 compared to $3.43 per MMBtu for the first quarter of 2013), which were due to the severe winter weather in the U.S. that caused a significant increase in regional natural gas

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prices used by our plants, and a $6 million increase in chemical costs during the first quarter of 2014 due to higher production.

Corporate Expenses and Other

General and administrative expenses decreased $16 million from the first quarter of 2013 to the first quarter of 2014. This decrease was primarily due to administrative expenses of $11 million in the first quarter of 2013 associated with our former retail business that did not recur due to the separation of that business in May 2013.

Depreciation and amortization expense decreased $19 million due to the loss of $20 million on the sale of certain corporate property in 2013.

“Interest and debt expense, net of capitalized interest” for the first quarter of 2014 increased $17 million from the first quarter of 2013. This increase was primarily due to a $23 million decrease in capitalized interest due to completion of several large capital projects 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 $89 million from the first quarter of 2013 to the first quarter of 2014 mainly as a result of higher income before income tax expense.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Three Months Ended March 31, 2014 and 2013

Net cash provided by operating activities for the first three months of 2014 was $244 million compared to $1.5 billion for the first three months of 2013. The decrease in cash generated from operating activities was primarily due to unfavorable changes in current assets and current liabilities, partially offset by the $289 million increase in operating income discussed above under “RESULTS OF OPERATIONS.” The changes in cash provided by or used in working capital during the first three months of 2014 and 2013 are shown in Note 10 of Condensed Notes to Consolidated Financial Statements.

The net cash provided by operating activities during the first three months of 2014 and $645 million of available cash on hand was used mainly to:


•	fund $517 million of capital expenditures and deferred turnaround and catalyst costs;


•	purchase common stock for treasury of $226 million; and


•	pay common stock dividends of $133 million.

The net cash provided by operating activities during the first three months of 2013 was used mainly to:


•	fund $864 million of capital expenditures and deferred turnaround and catalyst costs;


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


•	purchase common stock for treasury of $304 million;


•	pay common stock dividends of $111 million; and


•	increase available cash on hand by $134 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.

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Contractual Obligations

As of March 31, 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 our business with respect to these contractual obligations during the three months ended March 31, 2014.

As of March 31, 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.

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 the ratings agencies, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. As of April 30, 2014, 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 March 31, 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 2014	$	258
Revolving credit facility	$	3,000	November 2018	$	59
VLP Revolver	$	300	December 2018	$	—
Canadian revolving credit facility	C$	50	November 2014	C$	10

As of March 31, 2014, we had no amounts borrowed under our revolving credit facilities. The letters of credit outstanding as of March 31, 2014 expire during 2014 and 2015.

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.

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Stock Purchase Programs

As of March 31, 2014, we have approval under our $3 billion common stock purchase program to purchase approximately $2.4 billion of our common stock.

Environmental Matters

Our operations are subject to extensive environmental regulations by governmental authorities relating to the discharge of materials into the environment, waste management, pollution prevention measures, greenhouse gas emissions, and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our operating facilities could require material additional expenditures to comply with environmental laws and regulations. See Note 5 of Condensed Notes to Consolidated Financial Statements for a further discussion of our environmental matters.

Tax Matters

During the first quarter 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 increase and that such amount may exceed the total income tax expense that will be reflected on our statement of income. This belief is primarily based on an expected decrease in deductions that we will 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 three months ended March 31, 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 March 31, 2014, the total amount of uncertain tax position liabilities, including related penalties and interest, was $433 million, with $236 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 three months ended March 31, 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

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incur and pay taxes on the amounts repatriated. In addition, such repatriation could cause us to record deferred tax expense that could significantly impact our results of operations. We believe, however, that a substantial portion of our international cash can be returned to the U.S. without significant tax consequences through means other than a repatriation of earnings. As of March 31, 2014, $920 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 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 March 31, 2014, there have been no significant changes to our critical accounting policies since our annual report on Form 10-K for the year ended December 31, 2013 was filed.

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Item 3.	Quantitative and Qualitative Disclosures About Market Risk

COMMODITY PRICE RISK

We are exposed to market risks related to the volatility in the price of crude oil, refined products (primarily gasoline and distillate), grain (primarily corn), and natural gas used in our operations. To reduce the impact of price volatility on our results of operations and cash flows, we use commodity derivative instruments, including swaps, futures, and options to hedge:


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


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

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

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

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



	Derivative Instruments Held For
	Non-Trading Purposes			Trading Purposes
March 31, 2014:
Gain (loss) in fair value resulting from:
10% increase in underlying commodity prices	$	(290	)	$	(2	)
10% decrease in underlying commodity prices	290			1

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 12 of Condensed Notes to Consolidated Financial Statements for notional volumes associated with these derivative contracts as of March 31, 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

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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 March 31, 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 12 of Condensed Notes to Consolidated Financial Statements for a discussion about these compliance programs.

INTEREST RATE RISK

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



	March 31, 2014
	Expected Maturity Dates
	2014			2015			2016			2017			2018			There- after			Total			Fair Value
Debt:
Fixed rate	$	200		$	475		$	—		$	950		$	—		$	4,824		$	6,449		$	7,783
Average interest rate	4.8		%	5.2		%	—		%	6.4		%	—		%	7.3		%	6.9		%
Floating rate	$	100		$	—		$	—		$	—		$	—		$	—		$	100		$	100
Average interest rate	0.8		%	—		%	—		%	—		%	—		%	—		%	0.8		%

	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 March 31, 2014, we had commitments to purchase $999 million of U.S. dollars. Our market risk was minimal on these contracts, as the majority of them matured on or before April 30, 2014, resulting in an immaterial loss in the second quarter of 2014.

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Item 4. Controls and Procedures


(a)	Evaluation of disclosure controls and procedures.

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

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 5 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.

Bay Area Air Quality Management District (BAAQMD) (Benicia Refinery). We currently have multiple outstanding Violation Notices (VNs) issued by the BAAQMD in 2011, 2012, 2013, and 2014, which we reasonably believe may result in penalties of $100,000 or more. These VNs are for various alleged air regulation and air permit violations at our Benicia Refinery and asphalt plant. In the first quarter of 2014, we settled multiple VNs issued in 2011. We continue to work with the BAAQMD to resolve the remaining VNs.

Texas Commission on Environmental Quality (TCEQ) (Port Arthur Refinery). In our annual report on Form 10-K for the year ended December 31, 2013, we reported that our Port Arthur Refinery had received a proposed agreed order from the TCEQ that assessed a penalty of $180,911 for various alleged air emission and reporting violations; a Notice of Enforcement (NOE) for unauthorized emissions with potential stipulated penalties of $166,000; and additional NOEs for which we had not received proposed penalty amounts, but reasonably believed may result in penalties of $100,000 or more.

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In the first quarter of 2014, we received two proposed agreed orders from the TCEQ resolving multiple violations that occurred between May 2007 and April 2013, including all the unauthorized emissions, reporting violations and stipulated penalties referenced above. We are working with the TCEQ to finalize these agreed orders.

TCEQ (Port Arthur Refinery). In the first quarter of 2014, we received an NOE for unauthorized emissions at our Port Arthur Refinery, for which we have not received a proposed penalty amount, but reasonably believe may result in penalties of $100,000 or more.

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.


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


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


(b)	Use of Proceeds. Not applicable.


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



Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Not Purchased as Part of Publicly Announced Plans or Programs (a)	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (b)
January 2014	4,325,693	$	52.13	325,693	4,000,000	$2.4 billion
February 2014	1,959	$	50.10	1,959	—	$2.4 billion
March 2014	110	$	53.00	110	—	$2.4 billion
Total	4,327,762	$	52.13	327,762	4,000,000	$2.4 billion

(a)

The shares reported in this column represent purchases settled during the three months ended March 31, 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.

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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: May 8, 2014