Edgar Filing: VALERO ENERGY CORP/TX

10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the Quarterly Period Ended September 30, 2015



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 þ 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 þ 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 þ	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 þ

The number of shares of the registrant’s only class of common stock, $0.01 par value, outstanding as of October 30, 2015 was 481,503,440.

VALERO ENERGY CORPORATION

TABLE OF CONTENTS




	Page
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014	1
Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2015 and 2014	2
Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2015 and 2014	3
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2015 and 2014	4
Condensed Notes to Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3. Quantitative and Qualitative Disclosures About Market Risk	55
Item 4. Controls and Procedures	57
PART II – OTHER INFORMATION
Item 1. Legal Proceedings	58
Item 1A. Risk Factors	58
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	59
Item 6. Exhibits	59
SIGNATURE	60

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

VALERO ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Millions of Dollars, Except Par Value)



	September 30, 2015			December 31, 2014
	(Unaudited)
ASSETS
Current assets:
Cash and temporary cash investments	$	5,301		$	3,689
Receivables, net	4,691			5,879
Inventories	6,557			6,623
Income taxes receivable	7			97
Deferred income taxes	98			162
Prepaid expenses and other	173			164
Total current assets	16,827			16,614
Property, plant, and equipment, at cost	36,645			35,933
Accumulated depreciation	(9,957		)	(9,198		)
Property, plant, and equipment, net	26,688			26,735
Deferred charges and other assets, net	2,310			2,201
Total assets	$	45,825		$	45,550
LIABILITIES AND EQUITY
Current liabilities:
Current portion of debt and capital lease obligations	$	129		$	606
Accounts payable	5,679			6,760
Accrued expenses	595			596
Taxes other than income taxes	1,113			1,209
Income taxes payable	386			433
Deferred income taxes	387			376
Total current liabilities	8,289			9,980
Debt and capital lease obligations, less current portion	7,252			5,780
Deferred income taxes	6,656			6,607
Other long-term liabilities	1,760			1,939
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	7,074			7,116
Treasury stock, at cost; 190,478,467 and 159,202,872 common shares	(10,095		)	(8,125		)
Retained earnings	25,130			22,046
Accumulated other comprehensive loss	(795		)	(367		)
Total Valero Energy Corporation stockholders’ equity	21,321			20,677
Noncontrolling interests	547			567
Total equity	21,868			21,244
Total liabilities and equity	$	45,825		$	45,550

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 September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Operating revenues	$	22,579		$	34,408		$	69,027		$	102,985
Costs and expenses:
Cost of sales	18,677			31,023			58,234			93,820
Operating expenses:
Refining	986			987			2,885			2,926
Ethanol	116			118			344			358
General and administrative expenses	179			180			504			510
Depreciation and amortization expense	482			430			1,348			1,265
Total costs and expenses	20,440			32,738			63,315			98,879
Operating income	2,139			1,670			5,712			4,106
Other income, net	3			11			35			38
Interest and debt expense, net of capitalized interest	(112		)	(98		)	(326		)	(296		)
Income from continuing operations before income tax expense	2,030			1,583			5,421			3,848
Income tax expense	657			521			1,715			1,293
Income from continuing operations	1,373			1,062			3,706			2,555
Loss from discontinued operations	—			—			—			(64		)
Net income	1,373			1,062			3,706			2,491
Less: Net income (loss) attributable to noncontrolling interests	(4		)	3			14			16
Net income attributable to Valero Energy Corporation stockholders	$	1,377		$	1,059		$	3,692		$	2,475

Net income attributable to Valero Energy Corporation stockholders:
Continuing operations	$	1,377		$	1,059		$	3,692		$	2,539
Discontinued operations	—			—			—			(64		)
Total	$	1,377		$	1,059		$	3,692		$	2,475
Earnings per common share:
Continuing operations	$	2.79		$	2.01		$	7.31		$	4.78
Discontinued operations	—			—			—			(0.12		)
Total	$	2.79		$	2.01		$	7.31		$	4.66
Weighted-average common shares outstanding (in millions)	491			526			503			529
Earnings per common share – assuming dilution:
Continuing operations	$	2.79		$	2.00		$	7.30		$	4.76
Discontinued operations	—			—			—			(0.12		)
Total	$	2.79		$	2.00		$	7.30		$	4.64
Weighted-average common shares outstanding – assuming dilution (in millions)	494			530			506			533

Dividends per common share	$	0.400		$	0.275		$	1.200		$	0.775

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 September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Net income	$	1,373		$	1,062		$	3,706		$	2,491

Other comprehensive loss:
Foreign currency translation adjustment	(270		)	(274		)	(439		)	(198		)
Net gain (loss) on pension and other postretirement benefits	6			(3		)	17			(5		)
Net gain on derivative instruments designated and qualifying as cash flow hedges	—			—			—			1
Other comprehensive loss before income tax expense (benefit)	(264		)	(277		)	(422		)	(202		)
Income tax expense (benefit) related to items of other comprehensive income (loss)	2			—			6			(1		)
Other comprehensive loss	(266		)	(277		)	(428		)	(201		)

Comprehensive income	1,107			785			3,278			2,290
Less: Comprehensive income (loss) attributable to noncontrolling interests	(4		)	3			14			16
Comprehensive income attributable to Valero Energy Corporation stockholders	$	1,111		$	782		$	3,264		$	2,274

See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions of Dollars)

(Unaudited)



	Nine Months Ended September 30,
	2015			2014
Cash flows from operating activities:
Net income	$	3,706		$	2,491
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	1,348			1,265
Aruba Refinery asset retirement expense and other	—			63
Deferred income tax expense	77			191
Changes in current assets and current liabilities	46			(808		)
Changes in deferred charges and credits and other operating activities, net	(53		)	42
Net cash provided by operating activities	5,124			3,244
Cash flows from investing activities:
Capital expenditures	(1,186		)	(1,453		)
Deferred turnaround and catalyst costs	(509		)	(492		)
Other investing activities, net	16			(41		)
Net cash used in investing activities	(1,679		)	(1,986		)
Cash flows from financing activities:
Proceeds from debt issuances	1,446			—
Repayment of debt	(502		)	(200		)
Proceeds from the exercise of stock options	29			37
Purchase of common stock for treasury	(2,071		)	(799		)
Common stock dividends	(608		)	(411		)
Contributions from noncontrolling interests	4			14
Distributions to noncontrolling interests (public unitholders) of Valero Energy Partners LP	(14		)	(8		)
Distributions to other noncontrolling interest	(25		)	—
Other financing activities, net	14			51
Net cash used in financing activities	(1,727		)	(1,316		)
Effect of foreign exchange rate changes on cash	(106		)	(43		)
Net increase (decrease) in cash and temporary cash investments	1,612			(101		)
Cash and temporary cash investments at beginning of period	3,689			4,292
Cash and temporary cash investments at end of period	$	5,301		$	4,191

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 SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

These unaudited financial statements have been prepared in accordance with United States (U.S.) generally accepted accounting principles (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature unless disclosed otherwise. Financial information for the three and nine months ended September 30, 2015 and 2014 included in these Condensed Notes to Consolidated Financial Statements is derived from our unaudited financial statements. Operating results for the three and nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015.

The balance sheet as of December 31, 2014 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, 2014.

In May 2014, we abandoned our Aruba Refinery, except for the associated crude oil and refined products terminal assets that we continue to operate. As a result, the refinery’s results of operations have been presented as discontinued operations for the nine months ended September 30, 2014. For the nine months ended September 30, 2014, the Aruba Refinery had no operating revenues and a $64 million loss before income tax expense, primarily related to asset retirement obligations. There was no tax benefit recognized for the loss from discontinued operations for the nine months ended September 30, 2014 as we do not expect to realize this tax benefit.

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.

Discontinued Operations

In April 2014, the provisions of Accounting Standards Codification (ASC) Topic 205, “Presentation of Financial Statements,” and ASC Topic 360, “Property, Plant, and Equipment,” were amended to change the criteria for reporting discontinued operations. The provisions of these amendments modify the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have or will have a major effect on an entity’s operations and financial results. These amendments require additional disclosures about discontinued operations and new disclosures for other disposals of individually material components of an organization that do not meet the definition of a discontinued operation. In addition, the guidance allows companies to have significant continuing involvement and continuing cash flows with the discontinued operation. These provisions were effective

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 did 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.

New Accounting Pronouncements

In May 2014, the ASC was amended and a new accounting standard, ASC Topic 606, “Revenue from Contracts with Customers,” was issued to clarify the principles for recognizing revenue. The core principle of the new standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard also requires improved interim and annual disclosures that enable the users of financial statements to better understand the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. In July 2015, the effective date of the new standard was deferred by one year. As a result, the standard is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within those reporting periods, and can be adopted either retrospectively to each prior reporting period presented using a practical expedient, as allowed by the standard, or retrospectively with a cumulative-effect adjustment to retained earnings as of the date of initial application. Early adoption is permitted, but not before the original effective date, which was for annual reporting periods beginning after December 15, 2016, including interim reporting periods within those reporting periods. We are currently evaluating the effect that adopting this standard will have on our financial statements and related disclosures.

In February 2015, the provisions of ASC Topic 810, “Consolidation,” were amended to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (VIEs) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted retrospectively in previously issued financial statements for one or more years with a cumulative-effect adjustment to retained earnings as of the beginning of the first year restated. The adoption of this guidance effective January 1, 2016 will not affect our financial position or results of operations, but will result in additional disclosures.

In April 2015, the provisions of ASC Subtopic 835-30, “Interest–Imputation of Interest,” were amended to simplify the presentation of debt issuance costs. The guidance requires that debt issuance costs related to a note be reported in the balance sheet as a direct deduction from the face amount of that note, consistent with debt discounts, and that amortization of debt issuance costs be reported as interest expense. In August 2015, these provisions were further amended with guidance from the Securities and Exchange Commission staff that they would not object to an entity deferring and presenting debt issuance costs related to line-of-credit arrangements as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. These provisions are to be applied retrospectively and are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

adoption permitted. The adoption of this guidance effective January 1, 2016 will not materially affect our financial position or results of operations; however, our debt issuance costs associated with issued debt (other than borrowings on our line-of-credit arrangements) will be reported in the balance sheet as a direct deduction from “debt and capital lease obligations, less current portion” and excluded from “deferred charges and other assets, net.” Debt issuance costs associated with borrowings on our line-of-credit arrangements will continue to be reported in the balance sheet as “deferred charges and other assets, net,” and the related amortization will continue to be reported as interest expense.

Also in April 2015, the provisions of ASC Topic 715, “Compensation–Retirement Benefits,” were amended to provide a practical expedient for the measurement date of an entity’s defined benefit pension or other postretirement plans. For an entity with a fiscal year-end that does not coincide with a month-end, the guidance provides a practical expedient that allows the entity to measure the defined benefit plan assets and obligations using the month-end that is closest to the entity’s fiscal year-end. For an entity that has a significant event in an interim period that calls for a remeasurement, the guidance allows an entity to remeasure the defined benefit plan assets and obligations using the month-end that is closest to the date of the significant event. These provisions are effective retrospectively for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. The adoption of this guidance effective January 1, 2016 will not affect our financial position or results of operations.

In May 2015, the provisions of ASC Topic 820, “Fair Value Measurements,” were amended to remove the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The guidance also removes the requirement to make certain disclosures for all investments that are eligible to be measured using the net asset value per share practical expedient and limits those disclosures to investments for which the entity has elected to measure the fair value using that practical expedient. These provisions are to be applied retrospectively and are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. The adoption of this guidance effective January 1, 2016 will not affect our financial position or results of operations, but will result in revised disclosures.

In July 2015, the provisions of ASC Topic 330, “Inventory,” were amended to simplify the measurement of inventory. The guidance does not apply to inventory where the cost of such inventory is measured using the last-in, first-out (LIFO) or the retail inventory methods. The guidance applies to inventory where the cost of such inventory is measured using the first-in, first-out (FIFO) or average cost methods, and it requires the inventory to be measured at the lower of cost and net realizable value rather than the lower of cost or market. Net realizable value is defined as the estimated selling prices in the ordinary course of business, less reasonably predicable costs of completion, disposal, and transportation. These provisions are to be applied prospectively and are effective for annual reporting periods beginning after December 15, 2016, and interim periods within those annual periods, with early adoption permitted. The adoption of this guidance effective January 1, 2017 will not affect our financial position or results of operations.

In September 2015, the provisions of ASC Topic 805, “Business Combinations,” were amended to simplify the accounting and reporting of adjustments made to provisional amounts recognized in a business combination. The amendment requires that an acquirer (i) record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

date and (ii) present separately on the statement of income or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, and should be applied prospectively to adjustments made to provisional amounts that occur after the effective date. Earlier application is permitted for financial statements that have not yet been issued. The adoption of this guidance effective January 1, 2016 will not affect our financial position or results of operations; however, it may result in changes to the manner in which adjustments to provisional amounts recognized in a future business combination, if any, are presented in our financial statements.


2.	VALERO ENERGY PARTNERS LP

Valero Energy Partners LP (VLP) is a publicly traded master limited partnership that we formed to own, operate, develop, and acquire crude oil and refined petroleum products pipelines, terminals, and other transportation and logistics assets. As of September 30, 2015, VLP’s assets included crude oil and refined products pipeline and terminal systems in the U.S. Gulf Coast and U.S. Mid-Continent regions that are integral to the operations of seven of our refineries.

Effective March 1, 2015, we contributed to VLP our Houston and St. Charles Terminal Services Business, which owns and operates crude oil, intermediates, and refined products terminals supporting our Houston and St. Charles Refineries. We received (i) cash consideration of $571 million and (ii) 1,908,100 common units representing limited partner interests in VLP and 38,941 general partner units representing general partner interests in VLP having an aggregate value of $100 million. A portion of the cash consideration was funded through a $200 million borrowing by VLP under its revolving credit facility. The remaining cash consideration was funded with $211 million of VLP’s cash on hand and a $160 million borrowing under a subordinated credit agreement between VLP and us, which is eliminated in consolidation as further described below.

The ownership of VLP consisted of the following:



	September 30, 2015		December 31, 2014
Valero:
Limited partner interest	69.6	%	68.6	%
General partner interest	2.0	%	2.0	%
Public:
Limited partner interest	28.4	%	29.4	%

We consolidate the financial statements of VLP into our financial statements and as such, VLP’s cash and temporary cash investments are included in our consolidated cash and temporary cash investments. However, VLP’s cash and temporary cash investments can only be used to settle its own obligations. VLP’s cash and temporary cash investments were $51 million and $237 million as of September 30, 2015 and December 31, 2014, respectively. In addition, VLP’s partnership capital attributable to the public’s ownership interest in VLP of $385 million and $375 million as of September 30, 2015 and December 31, 2014, respectively, is reflected in noncontrolling interests.

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Effective October 1, 2015, we contributed to VLP our Corpus Christi Terminal Services Business, which owns and operates crude oil, intermediates, and refined products terminals supporting our Corpus Christi East and West Refineries. We received (i) cash consideration of $395 million and (ii) 1,570,513 common units representing limited partner interests in VLP and 32,051 general partner units representing general partner interests in VLP having an aggregate value of $70 million. The cash consideration was funded with a $395 million borrowing under a subordinated credit agreement between VLP and us. Because we consolidate the financial statements of VLP into our financial statements, this transaction will be eliminated in consolidation and will not impact our consolidated financial position or cash flows.


3.	INVENTORIES

Inventories consisted of the following (in millions):



	September 30, 2015		December 31, 2014
Refinery feedstocks	$	2,728	$	2,269
Refined products and blendstocks	3,396		3,926
Ethanol feedstocks and products	190		195
Materials and supplies	243		233
Inventories	$	6,557	$	6,623

As of September 30, 2015 and December 31, 2014, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by $1.0 billion and $857 million, respectively. As of September 30, 2015 and December 31, 2014, our non-LIFO inventories accounted for $634 million and $906 million, respectively, of our total inventories.


4.	DEBT

Credit Facilities

Revolver

We have a $3 billion revolving credit facility (the Revolver) that matures in 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 September 30, 2015 and December 31, 2014, we were in compliance with the Revolver’s restrictive covenants. As of September 30, 2015 and December 31, 2014, there were no borrowings outstanding under the Revolver.

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

VLP Revolver

VLP has a $300 million senior unsecured revolving credit facility agreement (the VLP Revolver) that matures in December 2018. The VLP Revolver bears interest at a variable rate, which was 1.5 percent as of September 30, 2015. The VLP Revolver is available only to the operations of VLP, and creditors of VLP do not have recourse against Valero. During the nine months ended September 30, 2015, VLP borrowed $200 million under the VLP Revolver in connection with VLP’s acquisition of the Houston and St. Charles Terminal Services Business, as further discussed in Note 2, and repaid $25 million on the VLP Revolver. As of September 30, 2015, VLP had $175 million of borrowings outstanding under the VLP Revolver. No borrowings were outstanding on the VLP Revolver as of December 31, 2014.

Canadian Revolver

One of our Canadian subsidiaries has a C$50 million committed revolving credit facility (the Canadian Revolver) that matures in November 2015. As of September 30, 2015 and December 31, 2014, there were no borrowings outstanding under the Canadian Revolver.

Letters of Credit

Letters of credit issued under our committed credit facilities were as follows (in millions):



				Amounts Issued
	Borrowing Capacity		Expiration	September 30, 2015		December 31, 2014
Letter of credit facility	$	125	June 2016	$	20	$	56
Revolver	$	3,000	November 2018	$	54	$	54
VLP Revolver	$	300	December 2018	$	—	$	—
Canadian Revolver	C$	50	November 2015	C$	10	C$	10

In June 2015, one of our committed letter of credit facilities with a borrowing capacity of $300 million expired and was not renewed. The remaining committed letter of credit facility was amended in July 2015 to extend the maturity date to June 2016 and reduce the borrowing capacity from $250 million to $125 million.

As of September 30, 2015 and December 31, 2014, there were $93 million and $80 million, respectively, of letters of credit issued under our uncommitted short-term bank credit facilities.

Non-Bank Debt

During the nine months ended September 30, 2015, we issued $600 million of 3.65 percent senior notes due March 15, 2025 and $650 million of 4.9 percent senior notes due March 15, 2045. Proceeds from these debt issuances totaled $1.246 billion. We also incurred $12 million of debt issuance costs.

In addition, during the nine months ended September 30, 2015, we made scheduled debt repayments of $400 million related to our 4.5 percent senior notes and $75 million related to our 8.75 percent debentures. During the nine months ended September 30, 2014, we made a scheduled debt repayment of $200 million related to our 4.75 percent senior notes.

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Accounts Receivable Sales Facility

We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell eligible trade receivables on a revolving basis. In July 2015, we amended our agreement to decrease the facility from $1.5 billion to $1.4 billion and extended the maturity date to July 2016. 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.

As of September 30, 2015 and December 31, 2014, we had $100 million outstanding under our accounts receivable sales facility.

Capitalized Interest

Capitalized interest was $18 million and $17 million for the three months ended September 30, 2015 and 2014, respectively, and $50 million and $52 million for the nine months ended September 30, 2015 and 2014, respectively.


5.	COMMITMENTS AND CONTINGENCIES

Environmental Matters

We are involved, together with several other companies, in an environmental cleanup in the Village of Hartford, Illinois (the Village) and recently, one of these companies assumed the ongoing remediation in the Village pursuant to a federal court order. Along with other companies, we previously conducted initial mitigation and cleanup in the Village pursuant to an administrative order issued by the U.S. Environmental Protection Agency (EPA). The parties involved in the initial Village cleanup may have further claims between themselves for costs already incurred. We also continue to be engaged in site assessment and interim measures at the adjacent shutdown refinery site, which we acquired as part of an acquisition in 2005, and we are in litigation with the Illinois EPA and other potentially responsible parties relating to the remediation of the site. In each of these matters, we have various defenses and rights for contribution from the other responsible parties. We have recorded a liability for our own expected contribution obligations. However, because of the unpredictable nature of these cleanups, the methodology for allocation of liabilities and the state of Illinois’ failure to directly sue third parties responsible for historic contamination at the site, 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

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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.


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 noncontrolling interests, and total equity (in millions):



	Nine Months Ended September 30,
	2015									2014
	Valero Stockholders’ Equity			Non- controlling Interests			Total Equity			Valero Stockholders’ Equity			Non- controlling Interests			Total Equity
Balance as of beginning of period	$	20,677		$	567		$	21,244		$	19,460		$	486		$	19,946
Net income	3,692			14			3,706			2,475			16			2,491
Dividends	(608		)	—			(608		)	(411		)	—			(411		)
Stock-based compensation expense	27			—			27			30			—			30
Tax deduction in excess of stock-based compensation expense	33			—			33			33			—			33
Transactions in connection with stock-based compensation plans:
Stock issuances	29			—			29			37			—			37
Stock purchases	(136		)	—			(136		)	(177		)	—			(177		)
Stock purchases under repurchase program	(1,965		)	—			(1,965		)	(692		)	—			(692		)
Contributions from noncontrolling interests	—			5			5			—			14			14
Distributions to noncontrolling interests	—			(39		)	(39		)	—			(8		)	(8		)
Other comprehensive loss	(428		)	—			(428		)	(201		)	—			(201		)
Balance as of end of period	$	21,321		$	547		$	21,868		$	20,554		$	508		$	21,062

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

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Share Activity

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



	Nine Months Ended September 30,
	2015			2014
	Common Stock	Treasury Stock		Common Stock	Treasury Stock
Balance as of beginning of period	673	(159	)	673	(138	)
Transactions in connection with stock-based compensation plans:
Stock issuances	—	3		—	3
Stock purchases	—	(2	)	—	(2	)
Stock purchases under repurchase program	—	(32	)	—	(13	)
Balance as of end of period	673	(190	)	673	(150	)

Treasury Stock

On July 13, 2015, our board of directors authorized our repurchase of an additional $2.5 billion of our outstanding common stock with no expiration date.

Common Stock Dividends

On October 28, 2015, our board of directors declared a quarterly cash dividend of $0.50 per common share payable on December 17, 2015 to holders of record at the close of business on November 23, 2015.

Income Tax Effects Related to Components of Other Comprehensive Income (Loss)

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



	Three Months Ended September 30,
	2015									2014
	Before- Tax Amount			Tax Expense (Benefit)			Net Amount			Before- Tax Amount			Tax Expense (Benefit)			Net Amount
Foreign currency translation adjustment	$	(270	)	$	—		$	(270	)	$	(274	)	$	—		$	(274	)
Pension and other postretirement benefits:
Amounts reclassified into income related to:
Net actuarial loss	16			5			11			8			3			5
Prior service credit	(10		)	(3		)	(7		)	(11		)	(3		)	(8		)
Net gain (loss) on pension and other postretirement benefits	6			2			4			(3		)	—			(3		)
Derivative instruments designated and qualifying as cash flow hedges:
Net loss arising during the period	—			—			—			(5		)	(2		)	(3		)
Net loss reclassified into income	—			—			—			5			2			3
Net loss on cash flow hedges	—			—			—			—			—			—
Other comprehensive loss	$	(264	)	$	2		$	(266	)	$	(277	)	$	—		$	(277	)

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	Nine Months Ended September 30,
	2015									2014
	Before- Tax Amount			Tax Expense (Benefit)			Net Amount			Before- Tax Amount			Tax Expense (Benefit)			Net Amount
Foreign currency translation adjustment	$	(439	)	$	—		$	(439	)	$	(198	)	$	—		$	(198	)
Pension and other postretirement benefits:
Amounts reclassified into income related to:
Net actuarial loss	47			16			31			25			9			16
Prior service credit	(30		)	(10		)	(20		)	(30		)	(11		)	(19		)
Net gain (loss) on pension and other postretirement benefits	17			6			11			(5		)	(2		)	(3		)
Derivative instruments designated and qualifying as cash flow hedges:
Net loss arising during the period	—			—			—			(1		)	—			(1		)
Net loss reclassified into income	—			—			—			2			1			1
Net gain on cash flow hedges	—			—			—			1			1			—
Other comprehensive loss	$	(422	)	$	6		$	(428	)	$	(202	)	$	(1	)	$	(201	)

Accumulated Other Comprehensive Income (Loss)

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



	Foreign Currency Translation Adjustment			Defined Benefit Plans Items			Gains and (Losses) on Cash Flow Hedges		Total
Balance as of December 31, 2014	$	1		$	(368	)	$	—	$	(367	)
Other comprehensive loss before reclassifications	(439		)	—			—		(439		)
Amounts reclassified from accumulated other comprehensive loss	—			11			—		11
Net other comprehensive income (loss)	(439		)	11			—		(428		)
Balance as of September 30, 2015	$	(438	)	$	(357	)	$	—	$	(795	)



Balance as of December 31, 2013	$	408		$	(58	)	$	—		$	350
Other comprehensive loss before reclassifications	(198		)	—			(1		)	(199		)
Amounts reclassified from accumulated other comprehensive income (loss)	—			(3		)	1			(2		)
Net other comprehensive loss	(198		)	(3		)	—			(201		)
Balance as of September 30, 2014	$	210		$	(61	)	$	—		$	149

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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
	2015			2014			2015			2014
Three months ended September 30:
Service cost	$	27		$	30		$	2		$	3
Interest cost	24			23			4			4
Expected return on plan assets	(33		)	(34		)	—			—
Amortization of:
Prior service credit	(5		)	(6		)	(5		)	(5		)
Net actuarial (gain) loss	16			9			—			(1		)
Net periodic benefit cost	$	29		$	22		$	1		$	1

Nine months ended September 30:
Service cost	$	82		$	90		$	6		$	6
Interest cost	73			69			11			12
Expected return on plan assets	(100		)	(100		)	—			—
Amortization of:
Prior service credit	(16		)	(16		)	(14		)	(14		)
Net actuarial (gain) loss	47			26			—			(1		)
Net periodic benefit cost	$	86		$	69		$	3		$	3

We contributed $114 million and $31 million, respectively, to our pension plans and $11 million and $14 million, respectively, to our other postretirement benefit plans during the nine months ended September 30, 2015 and 2014. Of the $114 million contributed to our pension plans during the nine months ended September 30, 2015, $77 million was discretionary and was contributed during the third quarter of 2015.

As a result of the additional discretionary pension contributions discussed above, our expected contributions to our pension plans have increased to $124 million for 2015. Our anticipated contributions to our other postretirement benefit plans during 2015 have not changed from the amount previously disclosed in our financial statements for the year ended December 31, 2014.

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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 September 30,
	2015				2014
	Participating Securities		Common Stock		Participating Securities		Common Stock
Earnings per common share from continuing operations:
Net income attributable to Valero stockholders from continuing operations			$	1,377			$	1,059
Less dividends paid:
Common stock			198				145
Participating securities			1				—
Undistributed earnings			$	1,178			$	914
Weighted-average common shares outstanding	2		491		2		526
Earnings per common share from continuing operations:
Distributed earnings	$	0.40	$	0.40	$	0.28	$	0.28
Undistributed earnings	2.39		2.39		1.73		1.73
Total earnings per common share from continuing operations	$	2.79	$	2.79	$	2.01	$	2.01

Earnings per common share from continuing operations – assuming dilution:
Net income attributable to Valero stockholders from continuing operations			$	1,377			$	1,059
Weighted-average common shares outstanding			491				526
Common equivalent shares:
Stock options			1				2
Performance awards and nonvested restricted stock			2				2
Weighted-average common shares outstanding – assuming dilution			494				530
Earnings per common share from continuing operations – assuming dilution			$	2.79			$	2.00

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	Nine Months Ended September 30,
	2015				2014
	Participating Securities		Common Stock		Participating Securities		Common Stock
Earnings per common share from continuing operations:
Net income attributable to Valero stockholders from continuing operations			$	3,692			$	2,539
Less dividends paid:
Common stock			606				410
Participating securities			2				1
Undistributed earnings			$	3,084			$	2,128
Weighted-average common shares outstanding	2		503		2		529
Earnings per common share from continuing operations:
Distributed earnings	$	1.20	$	1.20	$	0.77	$	0.77
Undistributed earnings	6.11		6.11		4.01		4.01
Total earnings per common share from continuing operations	$	7.31	$	7.31	$	4.78	$	4.78

Earnings per common share from continuing operations – assuming dilution:
Net income attributable to Valero stockholders from continuing operations			$	3,692			$	2,539
Weighted-average common shares outstanding			503				529
Common equivalent shares:
Stock options			2				3
Performance awards and nonvested restricted stock			1				1
Weighted-average common shares outstanding – assuming dilution			506				533
Earnings per common share from continuing operations – assuming dilution			$	7.30			$	4.76

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9.	SEGMENT INFORMATION

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



	Refining		Ethanol		Corporate			Total
Three months ended September 30, 2015:
Operating revenues from external customers	$	21,739	$	840	$	—		$	22,579
Intersegment revenues	—		39		—			39
Operating income (loss)	2,295		35		(191		)	2,139

Three months ended September 30, 2014:
Operating revenues from external customers	33,274		1,134		—			34,408
Intersegment revenues	—		21		—			21
Operating income (loss)	1,664		198		(192		)	1,670

Nine months ended September 30, 2015:
Operating revenues from external customers	66,618		2,409		—			69,027
Intersegment revenues	—		104		—			104
Operating income (loss)	6,097		155		(540		)	5,712

Nine months ended September 30, 2014:
Operating revenues from external customers	99,183		3,802		—			102,985
Intersegment revenues	—		55		—			55
Operating income (loss)	4,023		628		(545		)	4,106

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



	September 30, 2015		December 31, 2014
Refining	$	38,558	$	40,103
Ethanol	959		954
Corporate	6,308		4,493
Total assets	$	45,825	$	45,550

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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):



	Nine Months Ended September 30,
	2015			2014
Decrease (increase) in current assets:
Receivables, net	$	1,093		$	503
Inventories	(45		)	(1,164		)
Income taxes receivable	88			(8		)
Prepaid expenses and other	(11		)	2
Increase (decrease) in current liabilities:
Accounts payable	(1,007		)	(57		)
Accrued expenses	(5		)	73
Taxes other than income taxes	(50		)	(24		)
Income taxes payable	(17		)	(133		)
Changes in current assets and current liabilities	$	46		$	(808	)

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


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


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


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


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

Noncash investing and financing activities for the nine months ended September 30, 2015 included the recognition of a capital lease asset and related obligation associated with an agreement for storage tanks near one of our refineries. Noncash financing activities for the nine months ended September 30, 2015 also included an accrual of $30 million for the purchase of 506,100 shares of our common stock, which was settled in early October 2015.

There were no significant noncash investing activities for the nine months ended September 30, 2014. Noncash financing activities for the nine months ended September 30, 2014 included an accrual of $70 million for the purchase of 1,500,000 shares of our common stock, which was settled in early October 2014.

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



	Nine Months Ended September 30,
	2015		2014
Interest paid in excess of amount capitalized	$	301	$	271
Income taxes paid, net	1,532		1,209

Cash flows related to the discontinued operations of the Aruba Refinery were immaterial for the nine months ended September 30, 2014.


11.	FAIR VALUE MEASUREMENTS

General

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

U.S. GAAP also requires the disclosure of the fair values of financial instruments when an option to elect fair value accounting has been provided, but such election has not been made. A debt obligation is an example of such a financial instrument. The disclosure of the fair values of financial instruments not recognized at fair value in our balance sheet is presented below under “Other Financial Instruments.”

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


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


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

•

Level 3 - Unobservable inputs for the asset or liability. Unobservable inputs reflect our own assumptions about what market participants would use to price the asset or liability. The inputs are developed based on the best information available in the circumstances, which might include occasional market quotes or sales of similar instruments or our own financial data such as internally developed pricing models, discounted cash flow methodologies, as well as instruments for which the fair value determination requires significant judgment.

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Recurring Fair Value Measurements

The tables below present information (in millions) about our assets and liabilities recognized at their fair values in our balance sheets categorized according to the fair value hierarchy of the inputs utilized by us to determine the fair values as of September 30, 2015 and December 31, 2014.

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 in the tables below on a gross basis. We have no derivative contracts that are subject to master netting arrangements that are reflected gross on the balance sheet.



	September 30, 2015
							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	$	354	$	28	$	—	$	382	$	(316	)	$	(11	)	$	55	$	—
Foreign currency contracts	2		—		—		2		n/a			n/a			2		n/a
Investments of certain benefit plans	67		—		11		78		n/a			n/a			78		n/a
Total	$	423	$	28	$	11	$	462	$	(316	)	$	(11	)	$	135

Liabilities:
Commodity derivative contracts	$	295	$	21	$	—	$	316	$	(316	)	$	—		$	—	$	(113	)
Environmental credit obligations	—		4		—		4		n/a			n/a			4		n/a
Physical purchase contracts	—		5		—		5		n/a			n/a			5		n/a
Total	$	295	$	30	$	—	$	325	$	(316	)	$	—		$	9

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	December 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	$	3,096	$	36	$	—	$	3,132	$	(2,907	)	$	(99	)	$	126	$	—
Physical purchase contracts	—		1		—		1		n/a			n/a			1		n/a
Investments of certain benefit plans	97		—		11		108		n/a			n/a			108		n/a
Total	$	3,193	$	37	$	11	$	3,241	$	(2,907	)	$	(99	)	$	235

Liabilities:
Commodity derivative contracts	$	2,886	$	34	$	—	$	2,920	$	(2,907	)	$	(13	)	$	—	$	(25	)
Environmental credit obligations	—		14		—		14		n/a			n/a			14		n/a
Physical purchase contracts	—		5		—		5		n/a			n/a			5		n/a
Total	$	2,886	$	53	$	—	$	2,939	$	(2,907	)	$	(13	)	$	19

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 fixed-price corn purchase contracts. The fair values of these 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 for our international operations to manage our exposure to exchange rate fluctuations on transactions denominated in currencies other than the local (functional) currencies of those operations. These

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contracts are valued based on quoted prices from the exchange and are categorized in Level 1 of the fair value hierarchy.

•

Environmental credit obligations represent our liability for the purchase of (i) biofuel credits (primarily Renewable Identification Numbers (RINs) in the U.S.) needed to satisfy our obligation to blend biofuels into the products we produce and (ii) emission credits under the California Global Warming Solutions Act (the California cap-and-trade system, also known as AB 32) and Quebec’s Regulation respecting the cap-and-trade system for greenhouse gas emission allowances (the Quebec cap-and-trade system), (collectively, the cap-and-trade systems). To the degree we are unable to blend biofuels (such as ethanol and biodiesel) at percentages required under the biofuel programs, we must purchase biofuel credits to comply with these programs. Under the cap-and-trade systems, we must purchase emission credits to comply with these systems. These programs are further described in Note 12 under “Compliance Program Price Risk.” The liability for environmental credits is based on our deficit for such credits as of the balance sheet date, if any, after considering any credits acquired or under contract, and is equal to the product of the credits deficit and the market price of these credits as of the balance sheet date. The environmental credit obligations are categorized in Level 2 of the fair value hierarchy and are 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 September 30, 2015 and December 31, 2014 that were measured at fair value on a recurring basis.

There was no activity during the three and nine months ended September 30, 2015 and 2014 related to the fair value amounts categorized in Level 3 as of September 30, 2015 and December 31, 2014.

Nonrecurring Fair Value Measurements

There were no assets or liabilities that were measured at fair value on a nonrecurring basis as of September 30, 2015 and December 31, 2014.

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Other Financial Instruments

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



	September 30, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets:
Cash and temporary cash investments	$	5,301	$	5,301	$	3,689	$	3,689
Financial liabilities:
Debt (excluding capital leases)	7,293		8,117		6,354		7,562

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


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


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

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


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 our risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors.

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

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

•

Fair Value Hedges – Fair value hedges are used, from time to time, 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 exceed our previous year-end LIFO inventory levels. As of September 30, 2015, we had no outstanding commodity derivative instruments that were entered into as fair value hedges.

•

Cash Flow Hedges – Cash flow hedges are used, from time to time, to hedge price volatility in certain forecasted feedstock and refined product purchases, refined product sales, and natural gas purchases. The objective of our cash flow hedges is to lock in the price of forecasted feedstock, refined product, or natural gas purchases or refined product sales at existing market prices that we deem favorable. As of September 30, 2015, we had no outstanding commodity derivative instruments that were entered into as cash flow hedges.

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

•

Economic Hedges – Economic hedges represent commodity derivative instruments that are not designated as fair value or cash flow hedges and are used to manage price volatility in certain (i) feedstock and refined product inventories, (ii) forecasted feedstock and product purchases, and product sales, and (iii) fixed-price 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 qualify as hedging instruments for accounting purposes.

As of September 30, 2015, we had the following outstanding commodity derivative instruments that were used as economic hedges, as well as commodity derivative instruments related to the physical purchase of corn at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except those identified as corn contracts that are presented in thousands of bushels and soybean oil contracts that are presented in thousands of pounds).



	Notional Contract Volumes by Year of Maturity
Derivative Instrument	2015	2016	2017
Crude oil and refined products:
Swaps – long	11,605	700	—
Swaps – short	11,519	330	—
Futures – long	49,472	2,327	—
Futures – short	57,858	4,109	—
Corn:
Futures – long	13,615	85	10
Futures – short	24,450	8,555	20
Physical contracts – long	13,188	5,520	8
Soybean oil:
Futures – long	28,980	900	—
Futures – short	77,220	28,560	—

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


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

As of September 30, 2015, we had the following outstanding commodity derivative instruments that were entered into for trading purposes. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes represent thousands of barrels, except those identified as natural gas contracts that are presented in billions of British thermal units).



	Notional Contract Volumes by Year of Maturity
Derivative Instrument	2015	2016
Crude oil and refined products:
Swaps – long	7,275	3,220
Swaps – short	7,275	3,220
Futures – long	43,371	1,982
Futures – short	44,415	1,071
Options – long	11,400	10,500
Options – short	12,500	10,500
Natural gas:
Futures – long	2,000	—

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.

Foreign Currency Risk

We are exposed to exchange rate fluctuations on transactions entered into by our international operations that are denominated in currencies other than the local (functional) currencies of those operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and purchase contracts. These contracts are not designated as hedging instruments for accounting purposes, and therefore they are classified as economic hedges. As of September 30, 2015, we had commitments to purchase $344 million of U.S. dollars. These commitments matured before October 31, 2015.

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Environmental 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 environmental compliance programs.

Certain of these programs 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 biofuel programs was $95 million and $82 million for the three months ended September 30, 2015 and 2014, respectively, and $283 million and $265 million for the nine months ended September 30, 2015 and 2014, respectively. These amounts are reflected in cost of sales.

Effective January 1, 2015, we became subject to additional requirements under greenhouse gas emission programs, including the cap-and-trade systems, as discussed in Note 11. Under these cap-and-trade systems, we purchase various greenhouse gas emission credits available on the open market. Therefore, we are exposed to the volatility in the market price of these credits. The cost to implement certain provisions of the cap-and-trade systems are significant; however, we have recovered the majority of these costs from our customers for the nine months ended September 30, 2015 and expect to continue to recover the majority of these costs in the future. For the three and nine months ended September 30, 2015 and 2014, the net cost of meeting our obligations under these compliance programs was immaterial.

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Fair Values of Derivative Instruments

The following tables provide information about the fair values of our derivative instruments as of September 30, 2015 and December 31, 2014 (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	September 30, 2015
	Balance Sheet Location	Asset Derivatives		Liability Derivatives
Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	354	$	295
Swaps	Receivables, net	25		20
Options	Receivables, net	3		1
Physical purchase contracts	Inventories	—		5
Foreign currency contracts	Receivables, net	2		—
Total		$	384	$	321



	Balance Sheet Location	December 31, 2014
	Balance Sheet Location	Asset Derivatives		Liability Derivatives
Derivatives not designated as hedging instruments
Commodity contracts:
Futures	Receivables, net	$	3,096	$	2,886
Swaps	Receivables, net	34		31
Options	Receivables, net	2		3
Physical purchase contracts	Inventories	1		5
Total		$	3,133	$	2,925

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 our risk control group to ensure compliance with our stated risk management policy. We do not require any

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

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 (OCI) on our derivative instruments and the line items in the financial statements in which such gains and losses are reflected (in millions).



Derivatives in Fair Value Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended September 30,					Nine Months Ended September 30,
Derivatives in Fair Value Hedging Relationships	Location of Gain (Loss) Recognized in Income on Derivatives	2015		2014			2015		2014
Commodity contracts:
Loss recognized in income on derivatives	Cost of sales	$	—	$	(16	)	$	—	$	(42	)
Gain recognized in income on hedged item	Cost of sales	—		17			—		42
Gain recognized in income on derivatives (ineffective portion)	Cost of sales	—		1			—		—

For fair value hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness for the three and nine months ended September 30, 2015 and 2014. There were no amounts recognized in income for hedged firm commitments that no longer qualified as fair value hedges during the three and nine months ended September 30, 2015 and 2014.



Derivatives in Cash Flow Hedging Relationships	Location of Loss Recognized in Income on Derivatives	Three Months Ended September 30,					Nine Months Ended September 30,
Derivatives in Cash Flow Hedging Relationships	Location of Loss Recognized in Income on Derivatives	2015		2014			2015		2014
Commodity contracts:
Loss recognized in OCI on derivatives (effective portion)		$	—	$	(5	)	$	—	$	(1	)
Loss reclassified from accumulated OCI into income (effective portion)	Cost of sales	—		(5		)	—		(2		)
Loss recognized in income on derivatives (ineffective portion)	Cost of sales	—		—			—		(1		)

For cash flow hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness for the three and nine months ended September 30, 2014. For the three and nine months ended September 30, 2015, there were no cumulative after-tax gains or losses on cash flow hedges remaining in accumulated other comprehensive income. For the three and nine months ended

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VALERO ENERGY CORPORATION

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2015 and 2014, 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 September 30,				Nine Months Ended September 30,
	Location of Gain Recognized in Income on Derivatives	2015		2014		2015		2014
Commodity contracts	Cost of sales	$	122	$	354	$	159	$	222
Foreign currency contracts	Cost of sales	24		43		31		20



Trading Derivatives	Location of Gain Recognized in Income on Derivatives	Three Months Ended September 30,				Nine Months Ended September 30,
Trading Derivatives	Location of Gain Recognized in Income on Derivatives	2015		2014		2015		2014
Commodity contracts	Cost of sales	$	20	$	11	$	41	$	14

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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 costs for refinery turnarounds and catalyst 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 in the regions where we operate, as well as globally;


•	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;

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


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


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


•	the levels of government subsidies for alternative fuels;


•	the volatility in the market price of biofuel credits (primarily Renewable Identification Numbers (RINs) needed to comply with the United States (U.S.) federal Renewable Fuel Standard);


•	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 implemented under the California Global Warming Solutions Act (also known as AB 32), Quebec’s Regulation respecting the cap-and-trade system for greenhouse gas emission allowances (the Quebec cap-and-trade system), and the 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;


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


•	other factors generally described in the “Risk Factors” section included in our annual report on Form 10-K for the year ended December 31, 2014 that is incorporated by reference herein.

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

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

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OVERVIEW AND OUTLOOK

Overview

For the third quarter of 2015, we reported net income attributable to Valero stockholders from continuing operations of $1.4 billion, or $2.79 per share (assuming dilution), compared to $1.1 billion, or $2.00 per share (assuming dilution), for the third quarter of 2014. The increase of $318 million was due primarily to the increase of $469 million in our operating income as shown in the table below (in millions).



	Three Months Ended September 30,
	2015			2014			Change
Operating income by business segment:
Refining	$	2,295		$	1,664		$	631
Ethanol	35			198			(163		)
Corporate	(191		)	(192		)	1
Total	$	2,139		$	1,670		$	469

The $631 million increase in refining segment operating income in the third quarter of 2015 compared to the third quarter of 2014 was due primarily to higher margins on gasoline and other refined products (e.g., petroleum coke, propane, and sulfur), partially offset by lower discounts on light sweet and sour crude oils relative to Brent crude oil. Our ethanol segment operating income decreased $163 million in the third quarter of 2015 compared to the third quarter of 2014 due primarily to lower ethanol margins that resulted from lower ethanol prices.

For the first nine months of 2015, we reported net income attributable to Valero stockholders from continuing operations of $3.7 billion, or $7.30 per share (assuming dilution), compared to $2.5 billion, or $4.76 per share (assuming dilution) for the first nine months of 2014. The increase of $1.2 billion was due primarily to the increase of $1.6 billion in our operating income as shown in the table below (in millions).



	Nine Months Ended September 30,
	2015			2014			Change
Operating income by business segment:
Refining	$	6,097		$	4,023		$	2,074
Ethanol	155			628			(473		)
Corporate	(540		)	(545		)	5
Total	$	5,712		$	4,106		$	1,606

The $2.1 billion increase in refining segment operating income in the first nine months of 2015 compared to the first nine months of 2014 was due to higher margins on gasoline and other refined products (e.g., petroleum coke, propane, and sulfur), partially offset by lower discounts for most light sweet and sour crude oils relative to Brent crude oil. Our ethanol segment operating income decreased $473 million in the first nine months 2015 compared to the first nine months of 2014 due to lower ethanol margins that resulted from lower ethanol and lower co-product prices. Corn feedstock costs also declined in the first nine months of 2015 compared to the first nine months of 2014, but the decline was not as significant as the decline in ethanol prices, which resulted in lower ethanol margins.

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

In March 2015, we issued $600 million of 3.65 percent senior notes due March 15, 2025 and $650 million of 4.9 percent senior notes due March 15, 2045, and our consolidated subsidiary, Valero Energy Partners LP (VLP), borrowed $200 million under its revolving credit facility (the VLP Revolver), as further described in Note 4 of Condensed Notes to Consolidated Financial Statements. On July 1, 2015, VLP repaid $25 million of the amount borrowed under the VLP Revolver.

On July 13, 2015, our board of directors authorized us to purchase an additional $2.5 billion of our outstanding common stock, with no expiration date to such authorization.

Outlook

Energy markets and margins were volatile during the first nine months of 2015, and we expect them to continue to be volatile in the near to mid-term. Below is a summary of factors that have impacted or may impact our results of operations during the fourth quarter of 2015:


•	Refining margins are expected to be volatile as gasoline margins are projected to follow the seasonal trend and decline from current levels and crude oil discounts continue to be volatile.


•	Ethanol margins are expected to remain depressed as long as gasoline prices remain low.


•	The market price of biofuel credits (primarily RINs) is expected to remain unpredictable for the foreseeable future.


•	A decline in market prices of crude oil and refined products may negatively impact the carrying value of our inventories.

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RESULTS OF OPERATIONS

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

Financial Highlights

(millions of dollars, except per share amounts)



	Three Months Ended September 30,
	2015			2014			Change
Operating revenues	$	22,579		$	34,408		$	(11,829	)
Costs and expenses:
Cost of sales	18,677			31,023			(12,346		)
Operating expenses:
Refining	986			987			(1		)
Ethanol	116			118			(2		)
General and administrative expenses	179			180			(1		)
Depreciation and amortization expense:
Refining	455			406			49
Ethanol	15			12			3
Corporate	12			12			—
Total costs and expenses	20,440			32,738			(12,298		)
Operating income	2,139			1,670			469
Other income, net	3			11			(8		)
Interest and debt expense, net of capitalized interest	(112		)	(98		)	(14		)
Income before income tax expense	2,030			1,583			447
Income tax expense	657			521			136
Net income	1,373			1,062			311
Less: Net income (loss) attributable to noncontrolling interests	(4		)	3			(7		)
Net income attributable to Valero Energy Corporation stockholders	$	1,377		$	1,059		$	318
Earnings per common share – assuming dilution	$	2.79		$	2.00		$	0.79

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Refining Operating Highlights

(millions of dollars, except per barrel amounts)



	Three Months Ended September 30,
	2015		2014		Change
Refining:
Operating income	$	2,295	$	1,664	$	631
Throughput margin per barrel (a)	$	14.38	$	11.81	$	2.57
Operating costs per barrel:
Operating expenses	3.80		3.81		(0.01		)
Depreciation and amortization expense	1.75		1.57		0.18
Total operating costs per barrel	5.55		5.38		0.17
Operating income per barrel	$	8.83	$	6.43	$	2.40

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude oil	398		473		(75		)
Medium/light sour crude oil	416		465		(49		)
Sweet crude oil	1,307		1,208		99
Residuals	292		237		55
Other feedstocks	119		123		(4		)
Total feedstocks	2,532		2,506		26
Blendstocks and other	291		308		(17		)
Total throughput volumes	2,823		2,814		9

Yields (thousand barrels per day):
Gasolines and blendstocks	1,386		1,338		48
Distillates	1,065		1,087		(22		)
Other products (b)	406		420		(14		)
Total yields	2,857		2,845		12

_______________

See note references on page 41.

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Refining Operating Highlights by Region (c)

(millions of dollars, except per barrel amounts)



	Three Months Ended September 30,
	2015		2014		Change
U.S. Gulf Coast:
Operating income	$	1,038	$	927	$	111
Throughput volumes (thousand barrels per day)	1,571		1,613		(42		)

Throughput margin per barrel (a)	$	12.93	$	11.47	$	1.46
Operating costs per barrel:
Operating expenses	3.87		3.63		0.24
Depreciation and amortization expense	1.88		1.59		0.29
Total operating costs per barrel	5.75		5.22		0.53
Operating income per barrel	$	7.18	$	6.25	$	0.93

U.S. Mid-Continent:
Operating income	$	500	$	470	$	30
Throughput volumes (thousand barrels per day)	470		469		1

Throughput margin per barrel (a)	$	16.74	$	16.24	$	0.50
Operating costs per barrel:
Operating expenses	3.51		3.80		(0.29		)
Depreciation and amortization expense	1.68		1.56		0.12
Total operating costs per barrel	5.19		5.36		(0.17		)
Operating income per barrel	$	11.55	$	10.88	$	0.67

North Atlantic:
Operating income	$	415	$	239	$	176
Throughput volumes (thousand barrels per day)	507		467		40

Throughput margin per barrel (a)	$	12.78	$	10.02	$	2.76
Operating costs per barrel:
Operating expenses	2.76		3.29		(0.53		)
Depreciation and amortization expense	1.13		1.17		(0.04		)
Total operating costs per barrel	3.89		4.46		(0.57		)
Operating income per barrel	$	8.89	$	5.56	$	3.33

U.S. West Coast:
Operating income	$	342	$	28	$	314
Throughput volumes (thousand barrels per day)	275		265		10

Throughput margin per barrel (a)	$	21.61	$	9.14	$	12.47
Operating costs per barrel:
Operating expenses	5.79		5.84		(0.05		)
Depreciation and amortization expense	2.28		2.14		0.14
Total operating costs per barrel	8.07		7.98		0.09
Operating income per barrel	$	13.54	$	1.16	$	12.38

Total refining operating income	$	2,295	$	1,664	$	631

_______________

See note references on page 41.

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Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)



	Three Months Ended September 30,
	2015			2014		Change
Feedstocks:
Brent crude oil	$	51.13		$	103.28	$	(52.15	)
Brent less West Texas Intermediate (WTI) crude oil	4.73			5.78		(1.05		)
Brent less Alaska North Slope (ANS) crude oil	(0.31		)	1.77		(2.08		)
Brent less Louisiana Light Sweet (LLS) crude oil	1.94			3.07		(1.13		)
Brent less Mars crude oil	6.82			6.73		0.09
Brent less Maya crude oil	8.48			12.45		(3.97		)
LLS crude oil	49.19			100.21		(51.02		)
LLS less Mars crude oil	4.88			3.66		1.22
LLS less Maya crude oil	6.54			9.38		(2.84		)
WTI crude oil	46.40			97.50		(51.10		)

Natural gas (dollars per million British thermal units (MMBtu))	2.72			3.96		(1.24		)

Products:
U.S. Gulf Coast:
CBOB gasoline less Brent	12.40			6.04		6.36
Ultra-low-sulfur diesel less Brent	12.13			13.92		(1.79		)
Propylene less Brent	(13.85		)	3.39		(17.24		)
CBOB gasoline less LLS	14.34			9.11		5.23
Ultra-low-sulfur diesel less LLS	14.07			16.99		(2.92		)
Propylene less LLS	(11.91		)	6.46		(18.37		)
U.S. Mid-Continent:
CBOB gasoline less WTI	22.71			13.96		8.75
Ultra-low-sulfur diesel less WTI	20.36			21.73		(1.37		)
North Atlantic:
CBOB gasoline less Brent	16.28			11.57		4.71
Ultra-low-sulfur diesel less Brent	14.54			15.20		(0.66		)
U.S. West Coast:
CARBOB 87 gasoline less ANS	31.59			17.48		14.11
CARB diesel less ANS	14.84			20.19		(5.35		)
CARBOB 87 gasoline less WTI	36.63			21.49		15.14
CARB diesel less WTI	19.88			24.20		(4.32		)
New York Harbor corn crush (dollars per gallon)	0.20			0.81		(0.61		)

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Ethanol Operating Highlights

(millions of dollars, except per gallon amounts)



	Three Months Ended September 30,
	2015		2014		Change
Ethanol:
Operating income	$	35	$	198	$	(163	)
Production (thousand gallons per day)	3,853		3,556		297

Gross margin per gallon of production (a)	$	0.47	$	1.00	$	(0.53	)
Operating costs per gallon of production:
Operating expenses	0.33		0.36		(0.03		)
Depreciation and amortization expense	0.04		0.04		—
Total operating costs per gallon of production	0.37		0.40		(0.03		)
Operating income per gallon of production	$	0.10	$	0.60	$	(0.50	)

_______________

See note references below.

The following notes relate to references on pages 38 through 41.


(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 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.

General

Operating revenues decreased $11.8 billion (or 34 percent) and cost of sales decreased $12.3 billion (or 40 percent) in the third quarter of 2015 compared to the third quarter of 2014 primarily due to a decrease in refined product prices and crude oil feedstock costs, respectively. Despite the decrease in operating revenues, cost of sales decreased to a greater extent resulting in an increase in operating income of $469 million in the third quarter of 2015 compared to the third quarter of 2014, with refining segment operating income increasing by $631 million and ethanol segment operating income decreasing by $163 million. The reasons for these changes in the operating results of our segments, as well as other items that affected our income, are discussed below.

Refining

Refining segment operating income increased $631 million from $1.7 billion in the third quarter of 2014 to $2.3 billion in the third quarter of 2015, due primarily to a $679 million increase in refining margin, partially offset by a $49 million increase in depreciation and amortization expense.

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Refining margin increased $679 million (a $2.57 per barrel increase) for the third quarter of 2015 compared to the third quarter of 2014, due primarily to the following:

•

Increase in gasoline margins - We experienced an increase in gasoline margins throughout all our regions during the third quarter of 2015 compared to the third quarter of 2014. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast CBOB gasoline was $12.40 per barrel during the third quarter of 2015 compared to $6.04 per barrel during the third quarter of 2014, representing a favorable increase of $6.36 per barrel. Another example is the ANS-based reference margin for U.S. West Coast CARBOB gasoline that was $31.59 per barrel during the third quarter of 2015 compared to $17.48 per barrel during the third quarter of 2014, representing a favorable increase of $14.11 per barrel. We estimate that the increase in gasoline margins per barrel during the third quarter of 2015 compared to the third quarter of 2014 had a positive impact to our refining margin of approximately $900 million.

•

Decrease in distillate margins - We experienced a decrease in distillate margins in all of our regions during the third quarter of 2015 compared to the third quarter of 2014. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel was $12.13 per barrel for the third quarter of 2015 compared to $13.92 per barrel for the third quarter of 2014, representing an unfavorable decrease of $1.79 per barrel. We estimate that the decrease in distillate margins during the third quarter of 2015 compared to the third quarter of 2014 had an unfavorable impact to our refining margin of approximately $150 million.

•

Increase in other refined products margins - We experienced an increase in the margins of other refined products (such as petroleum coke and sulfur) during the third quarter of 2015 compared to the third quarter of 2014. Margins for other refined products were higher during the third quarter of 2015 due to the decrease in the cost of crude oils during the period compared to the third quarter of 2014. Because the market prices for our other refined products remain relatively stable, we benefit when the cost of crude oils that we process declines. For example, the benchmark price of Brent crude oil was $51.13 per barrel for the third quarter of 2015 compared to $103.28 per barrel for the third quarter of 2014. We estimate that the increase in other refined products margins during the third quarter of 2015 compared to the third quarter of 2014 had a positive impact to our refining margin of approximately $500 million.

•

Lower discounts on light sweet crude oils and sour crude oils - Because the market prices for refined products generally track 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. For the third quarter of 2015, the discount in the price of most crude oils compared to the price of Brent crude oil narrowed. Therefore, while we benefitted from processing crude oils priced at a discount to Brent crude oil, that benefit declined in the third quarter of 2015 compared to the third quarter of 2014. For example, we processed LLS crude oil (a type of light sweet crude oil) in our U.S. Gulf Coast region that sold at a discount of $1.94 per barrel to Brent crude oil during the third quarter of 2015 compared to a discount of $3.07 per barrel during the third quarter of 2014, representing an unfavorable decrease of $1.13 per barrel. Another example is Maya crude oil (a type of sour crude oil) that sold at a discount of $8.48 per barrel to Brent crude oil during the third quarter of 2015 compared to a discount of $12.45 per barrel during the third quarter of 2014, representing an unfavorable decrease of $3.97 per barrel. We estimate that the narrowing of the discounts for light sweet crude oils and sour crude oils that we processed during the third quarter of 2015 had an unfavorable impact to our refining margin of approximately $100 million and $220 million, respectively.


•	Lower benefit from processing other feedstocks - In addition to crude oil, we use other feedstocks and blendstocks in our refining processes, such as natural gas. When combined with steam, natural gas

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produces hydrogen that is used in our hydrotreater and hydrocracker processing units to produce refined products. Although natural gas costs declined from the third quarter of 2014 to the third quarter of 2015, the decline was not as significant as the decline in the cost of Brent crude oil; therefore, the benefit we normally derive by using natural gas as a feedstock declined. We estimate that the decline in the benefit derived from processing natural gas feedstock had an unfavorable impact to our refining margin of approximately $200 million from the third quarter of 2014 to the third quarter of 2015.

The increase of $49 million in depreciation and amortization expense was primarily due to an increase of $20 million in depreciation expense associated with new capital projects, $17 million of write-offs for projects that were cancelled during the period, and $10 million in refinery turnaround and catalyst amortization expense resulting from the completion of turnaround projects at many of our refineries.

Ethanol

Ethanol segment operating income was $35 million in the third quarter of 2015 compared to $198 million in the third quarter of 2014. The $163 million decrease in operating income was due primarily to a $162 million decrease in gross margin (a $0.53 per gallon decrease).

Ethanol segment gross margin per gallon decreased to $0.47 per gallon in the third quarter of 2015 from $1.00 per gallon in the third quarter of 2014 due primarily to the following:

•

Lower ethanol prices - Ethanol prices were lower in the third quarter of 2015 primarily due to the decrease in crude oil and gasoline prices in the third quarter of 2015 compared to the third quarter of 2014. For example, the New York Harbor ethanol price was $1.59 per gallon in the third quarter of 2015 compared to $2.12 per gallon in the third quarter of 2014. We estimate that the decrease in the price of ethanol per gallon during the third quarter of 2015 had an unfavorable impact to our ethanol margin of approximately $170 million.

•

Higher corn prices - Corn prices were higher in the third quarter of 2015 compared to the third quarter of 2014 primarily due to expectations of a reduced 2015 corn harvest compared to a record corn harvest in 2014. For example, the Chicago Board of Trade (CBOT) corn price was $3.83 per bushel in the third quarter of 2015 compared to $3.59 per bushel in the third quarter of 2014. We estimate that the increase in the price of corn that we processed during the third quarter of 2015 had an unfavorable impact to our ethanol margin of approximately $20 million.


•	Higher co-product prices - The increase in corn prices in the third quarter of 2015 compared to the third quarter of 2014 had a favorable effect on the prices we received for corn-related ethanol co-products, such as distillers grains and corn oil. We estimate that the increase in co-products prices had a favorable impact to our ethanol margin of approximately $10 million.

•

Increased production volumes - Ethanol margin was favorably impacted by increased production volumes of 297,000 gallons per day in the third quarter of 2015 compared to the third quarter of 2014 primarily due to the production volumes from our Mount Vernon plant, which began operations in August 2014. We estimate that the increase in production volumes had a favorable impact to our ethanol margin of approximately $10 million.

Other

“Interest and debt expense, net of capitalized interest” for the third quarter of 2015 increased $14 million from the third quarter of 2014. This increase was primarily due to the impact from $1.25 billion of debt

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issued by Valero in March 2015 and $175 million of net borrowings outstanding ($200 million borrowed in March 2015, net of $25 million repaid in July 2015) under the VLP Revolver.

Income tax expense increased $136 million from the third quarter of 2014 to the third quarter of 2015 as a result of higher income from continuing operations before income tax expense.

Financial Highlights

(millions of dollars, except per share amounts)



	Nine Months Ended September 30,
	2015			2014			Change
Operating revenues	$	69,027		$	102,985		$	(33,958	)
Costs and expenses:
Cost of sales	58,234			93,820			(35,586		)
Operating expenses:
Refining	2,885			2,926			(41		)
Ethanol	344			358			(14		)
General and administrative expenses	504			510			(6		)
Depreciation and amortization expense:
Refining	1,280			1,194			86
Ethanol	32			36			(4		)
Corporate	36			35			1
Total costs and expenses	63,315			98,879			(35,564		)
Operating income	5,712			4,106			1,606
Other income, net	35			38			(3		)
Interest and debt expense, net of capitalized interest	(326		)	(296		)	(30		)
Income from continuing operations before income tax expense	5,421			3,848			1,573
Income tax expense	1,715			1,293			422
Income from continuing operations	3,706			2,555			1,151
Loss from discontinued operations	—			(64		)	64
Net income	3,706			2,491			1,215
Less: Net income attributable to noncontrolling interests	14			16			(2		)
Net income attributable to Valero Energy Corporation stockholders	$	3,692		$	2,475		$	1,217

Net income attributable to Valero Energy Corporation stockholders:
Continuing operations	$	3,692		$	2,539		$	1,153
Discontinued operations	—			(64		)	64
Total	$	3,692		$	2,475		$	1,217

Earnings per common share – assuming dilution:
Continuing operations	$	7.30		$	4.76		$	2.54
Discontinued operations	—			(0.12		)	0.12
Total	$	7.30		$	4.64		$	2.66

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Refining Operating Highlights

(millions of dollars, except per barrel amounts)



	Nine Months Ended September 30,
	2015		2014		Change
Refining:
Operating income	$	6,097	$	4,023	$	2,074
Throughput margin per barrel (a)	$	13.52	$	10.86	$	2.66
Operating costs per barrel:
Operating expenses	3.80		3.90		(0.10		)
Depreciation and amortization expense	1.69		1.59		0.10
Total operating costs per barrel	5.49		5.49		—
Operating income per barrel	$	8.03	$	5.37	$	2.66

Throughput volumes (thousand barrels per day):
Feedstocks:
Heavy sour crude oil	425		460		(35		)
Medium/light sour crude oil	421		482		(61		)
Sweet crude oil	1,210		1,119		91
Residuals	273		225		48
Other feedstocks	142		134		8
Total feedstocks	2,471		2,420		51
Blendstocks and other	310		326		(16		)
Total throughput volumes	2,781		2,746		35

Yields (thousand barrels per day):
Gasolines and blendstocks	1,357		1,317		40
Distillates	1,060		1,049		11
Other products (b)	402		413		(11		)
Total yields	2,819		2,779		40

_______________

See note references on page 48.

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Refining Operating Highlights by Region (c)

(millions of dollars, except per barrel amounts)



	Nine Months Ended September 30,
	2015		2014		Change
U.S. Gulf Coast:
Operating income	$	2,996	$	2,470	$	526
Throughput volumes (thousand barrels per day)	1,570		1,589		(19		)

Throughput margin per barrel (a)	$	12.52	$	11.00	$	1.52
Operating costs per barrel:
Operating expenses	3.76		3.69		0.07
Depreciation and amortization expense	1.77		1.61		0.16
Total operating costs per barrel	5.53		5.30		0.23
Operating income per barrel	$	6.99	$	5.70	$	1.29

U.S. Mid-Continent:
Operating income	$	1,215	$	950	$	265
Throughput volumes (thousand barrels per day)	446		431		15

Throughput margin per barrel (a)	$	15.33	$	13.76	$	1.57
Operating costs per barrel:
Operating expenses	3.68		4.03		(0.35		)
Depreciation and amortization expense	1.68		1.66		0.02
Total operating costs per barrel	5.36		5.69		(0.33		)
Operating income per barrel	$	9.97	$	8.07	$	1.90

North Atlantic:
Operating income	$	1,167	$	582	$	585
Throughput volumes (thousand barrels per day)	492		466		26

Throughput margin per barrel (a)	$	12.74	$	9.10	$	3.64
Operating costs per barrel:
Operating expenses	2.88		3.40		(0.52		)
Depreciation and amortization expense	1.17		1.13		0.04
Total operating costs per barrel	4.05		4.53		(0.48		)
Operating income per barrel	$	8.69	$	4.57	$	4.12

U.S. West Coast:
Operating income	$	719	$	21	$	698
Throughput volumes (thousand barrels per day)	273		260		13

Throughput margin per barrel (a)	$	17.70	$	8.38	$	9.32
Operating costs per barrel:
Operating expenses	5.88		5.91		(0.03		)
Depreciation and amortization expense	2.17		2.17		—
Total operating costs per barrel	8.05		8.08		(0.03		)
Operating income per barrel	$	9.65	$	0.30	$	9.35

Total refining operating income	$	6,097	$	4,023	$	2,074

_______________

See note references on page 48.

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Average Market Reference Prices and Differentials

(dollars per barrel, except as noted)



	Nine Months Ended September 30,
	2015			2014		Change
Feedstocks:
Brent crude oil	$	56.59		$	106.97	$	(50.38	)
Brent less WTI crude oil	5.66			7.21		(1.55		)
Brent less ANS crude oil	0.58			1.44		(0.86		)
Brent less LLS crude oil	2.43			3.12		(0.69		)
Brent less Mars crude oil	6.40			7.12		(0.72		)
Brent less Maya crude oil	9.24			14.95		(5.71		)
LLS crude oil	54.16			103.85		(49.69		)
LLS less Mars crude oil	3.97			4.00		(0.03		)
LLS less Maya crude oil	6.81			11.83		(5.02		)
WTI crude oil	50.93			99.76		(48.83		)

Natural gas (dollars per MMBtu)	2.73			4.58		(1.85		)

Products:
U.S. Gulf Coast:
CBOB gasoline less Brent	10.95			5.05		5.90
Ultra-low-sulfur diesel less Brent	13.76			13.96		(0.20		)
Propylene less Brent	(3.95		)	0.34		(4.29		)
CBOB gasoline less LLS	13.38			8.17		5.21
Ultra-low-sulfur diesel less LLS	16.19			17.08		(0.89		)
Propylene less LLS	(1.52		)	3.46		(4.98		)
U.S. Mid-Continent:
CBOB gasoline less WTI	19.09			14.35		4.74
Ultra-low-sulfur diesel less WTI	20.36			22.86		(2.50		)
North Atlantic:
CBOB gasoline less Brent	13.49			9.55		3.94
Ultra-low-sulfur diesel less Brent	17.59			17.33		0.26
U.S. West Coast:
CARBOB 87 gasoline less ANS	27.21			15.80		11.41
CARB diesel less ANS	17.39			18.26		(0.87		)
CARBOB 87 gasoline less WTI	32.29			21.57		10.72
CARB diesel less WTI	22.47			24.03		(1.56		)
New York Harbor corn crush (dollars per gallon)	0.22			0.90		(0.68		)

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Ethanol Operating Highlights

(millions of dollars, except per gallon amounts)



	Nine Months Ended September 30,
	2015		2014		Change
Ethanol:
Operating income	$	155	$	628	$	(473	)
Production (thousand gallons per day)	3,808		3,311		497

Gross margin per gallon of production (a)	$	0.51	$	1.13	$	(0.62	)
Operating costs per gallon of production:
Operating expenses	0.33		0.40		(0.07		)
Depreciation and amortization expense	0.03		0.04		(0.01		)
Total operating costs per gallon of production	0.36		0.44		(0.08		)
Operating income per gallon of production	$	0.15	$	0.69	$	(0.54	)

_______________

See note references below.

The following notes relate to references on pages 45 through 48.


(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)

General

Operating revenues decreased $34.0 billion (or 33 percent) and cost of sales decreased $35.6 billion (or 38 percent) in the first nine months of 2015 compared to the first nine months of 2014 primarily due to a decrease in refined product prices and crude oil feedstock costs, respectively. Despite the decrease in operating revenues, cost of sales decreased to a greater extent resulting in an increase in operating income of $1.6 billion in the first nine months of 2015 compared to the first nine months of 2014, with refining segment operating income increasing by $2.1 billion and ethanol segment operating income decreasing by $473 million. The reasons for these changes in the operating results of our segments, as well as other items that affected our income, are discussed below.

Refining

Refining segment operating income increased $2.1 billion from $4.0 billion in the first nine months of 2014 to $6.1 billion in the first nine months of 2015, due to a $2.1 billion increase in refining margin and a $41 million decrease in operating expenses, partially offset by an $86 million increase in depreciation and amortization expense.

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Refining margin increased $2.1 billion (a $2.66 per barrel increase) in the first nine months of 2015 compared to the first nine months of 2014, due primarily to the following:

•

Increase in gasoline margins - We experienced an increase in gasoline margins throughout all our regions during the first nine months of 2015 compared to the first nine months of 2014. For example, the Brent-based benchmark reference margin for U.S. Gulf Coast CBOB gasoline was $10.95 per barrel during the first nine months of 2015 compared to $5.05 per barrel during the first nine months of 2014, representing a favorable increase of $5.90 per barrel. Another example is the ANS-based reference margin for U.S. West Coast CARBOB gasoline that was $27.21 per barrel during the first nine months of 2015 compared to $15.80 per barrel during the first nine months of 2014, representing a favorable increase of $11.41 per barrel. We estimate that the increase in gasoline margins per barrel during the first nine months of 2015 compared to the first nine months of 2014 had a positive impact to our refining margin of approximately $1.8 billion.

•

Decrease in distillate margins - We experienced a decrease in distillate margins throughout all our regions for the first nine months of 2015 compared to the first nine months of 2014. For example, the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low-sulfur diesel (a type of distillate) was $20.36 per barrel for the first nine months of 2015 compared to $22.86 per barrel for the first nine months of 2014, representing an unfavorable decrease of $2.50 per barrel. Another example is the Brent-based benchmark reference margin for U.S. Gulf Coast ultra-low-sulfur diesel (a type of distillate) was $13.76 per barrel for the first nine months of 2015 compared to $13.96 per barrel for the first nine months of 2014, representing an unfavorable decrease of $0.20 per barrel. We estimate that the decrease in distillate margins per barrel in the first nine months of 2015 compared to the first nine months of 2014 had an unfavorable impact to our refining margin of approximately $160 million.

•

Increase in other refined products margins - We experienced an increase in the margins of other refined products (such as petroleum coke, propane, and sulfur) during the first nine months of 2015 compared to the first nine months of 2014. Margins for other refined products were higher during the first nine months of 2015 due to the lower cost of crude oils during the period compared to the first nine months of 2014. Because the market prices for our other refined products remain relatively stable, we benefit when the cost of crude oils that we process declines. For example, the benchmark price of Brent crude oil was $56.59 per barrel for the first nine months of 2015 compared to $106.97 per barrel for the first nine months of 2014. We estimate that the increase in other refined products margins during the first nine months of 2015 compared to the first nine months of 2014 had a positive impact to our refining margin of approximately $1.3 billion.


•	Higher throughput volumes - Refining throughput volumes increased by 35,000 barrels per day during the first nine months of 2015 compared to the first nine months of 2014. We estimate that the increase in refining throughput volumes had a positive impact to our refining margin of approximately $130 million period over period.

•

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2015 compared to $3.12 per barrel for the first nine months of 2014, representing an unfavorable decrease of $0.69 per barrel. Another example is Maya crude oil (a type of sour crude oil) that sold at a discount of $9.24 per barrel to Brent crude oil during the first nine months of 2015 compared to a discount of $14.95 per barrel during the first nine months of 2014, representing an unfavorable decrease of $5.71 per barrel. We estimate that the narrowing of the discounts for light sweet crude oils and sour crude oils that we processed during the first nine months of 2015 had an unfavorable impact to our refining margin of approximately $75 million and $710 million, respectively.

•

Lower benefit from processing other feedstocks - In addition to crude oil, we use other feedstocks and blendstocks in our refining processes, such as natural gas. When combined with steam, natural gas produces hydrogen that is used in our hydrotreater and hydrocracker processing units to produce refined products. Although natural gas costs declined from the first nine months of 2014 to the first nine months of 2015, the decline was not as significant as the decline in the cost of Brent crude oil; therefore, the benefit we normally derive by using natural gas as a feedstock declined. We estimate that the decline in the benefit we derived from processing natural gas feedstock had an unfavorable impact to our refining margin of approximately $510 million from the first nine months of 2014 to the first nine months of 2015.

The decrease of $41 million in operating expenses was primarily due to a $158 million decrease in energy costs related to lower natural gas prices ($2.73 per MMBtu for the first nine months of 2015 compared to $4.58 per MMBtu for the first nine months of 2014). This decrease in energy costs was partially offset by the effect of $41 million of favorable sales and ad valorem tax settlements in the first nine months of 2014, combined with a $41 million increase in employee-related expenses primarily due to higher employee benefit costs and incentive compensation expense and a $26 million increase in costs associated with higher levels of maintenance activities and chemical costs during the first nine months of 2015.

The increase of $86 million in depreciation and amortization expense was primarily associated with the impact of new capital projects that began operating subsequent to the first nine months of 2014 and $19 million of write-offs for projects that were cancelled during the period.

Ethanol

Ethanol segment operating income was $155 million for the first nine months of 2015 compared to $628 million for the first nine months of 2014. The $473 million decrease in operating income was due to a $491 million decrease in gross margin (a $0.62 per gallon decrease), partially offset by a $14 million decrease in operating expenses and a $4 million decrease in depreciation and amortization expense.

Ethanol segment gross margin per gallon decreased to $0.51 per gallon for the first nine months of 2015 from $1.13 per gallon for the first nine months of 2014 due primarily to the following:

•

Lower ethanol prices - Ethanol prices were lower in the first nine months of 2015 primarily due to the decrease in crude oil and gasoline prices in the first nine months of 2015 compared to the first nine months of 2014. For example, the New York Harbor ethanol price was $1.59 per gallon in the first nine months of 2015 compared to $2.47 per gallon in the first nine months of 2014. We estimate that the decrease in the price of ethanol per gallon during the first nine months of 2015 had an unfavorable impact to our ethanol margin of approximately $700 million.


•	Lower corn prices - Corn prices were lower in the first nine months of 2015 compared to the first nine months of 2014 due to a higher domestic corn yield realized during the 2014 fall harvest (most of which is processed in the following year). For example, the CBOT corn price was $3.78 per bushel in the first

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nine months of 2015 compared to $4.30 per bushel in the first nine months of 2014. We estimate that the decrease in the price of corn that we processed during the first nine months of 2015 had a favorable impact to our ethanol margin of approximately $170 million.


•	Lower co-product prices - The decrease in corn prices in the first nine months of 2015 compared to the first nine months of 2014 had a negative effect on the prices we received for corn-related ethanol co-products, such as distillers grains and corn oil. We estimate that the decrease in co-products prices had an unfavorable impact to our ethanol margin of approximately $50 million.

•

Increased production volumes - Ethanol margin was favorably impacted by increased production volumes of 497,000 gallons per day in the first nine months of 2015 compared to the first nine months of 2014. Production volumes in the first nine months of 2014 were negatively impacted by weather-related rail disruptions. In addition, production volumes in the first nine months of 2015 were positively impacted by production volumes from our Mount Vernon plant, which began operations in August 2014. We estimate that the increase in production volumes had a favorable impact to our ethanol margin of approximately $50 million.

The $14 million decrease in operating expenses was primarily due to a $40 million decrease in energy costs primarily related to lower natural gas prices ($2.73 per MMBtu for the first nine months of 2015 compared to $4.58 per MMBtu for the first nine months of 2014), partially offset by an increase of $20 million related to maintenance and chemical costs due to increased production volumes.

Other

“Interest and debt expense, net of capitalized interest” for the first nine months of 2015 increased $30 million from the first nine months of 2014. This increase was primarily due to the impact from $1.25 billion of debt issued by Valero and $200 million borrowed by VLP under the VLP Revolver during March 2015, of which VLP repaid $25 million in July 2015.

Income tax expense increased $422 million from the first nine months of 2014 to the first nine months of 2015 as a result of higher income from continuing operations before income tax expense, partially offset by a $31 million increase in tax benefits from our U.S. manufacturing deduction, and a $12 million favorable impact related to tax audit settlements.

The loss from discontinued operations for the nine months ended September 30, 2014 includes expenses of $64 million primarily related to an asset retirement obligation associated with our decision in May 2014 to abandon the Aruba Refinery, as further described in Note 1 to Condensed Notes to Consolidated Financial Statements.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Nine Months Ended September 30, 2015

Our operations generated $5.1 billion of cash during the first nine months of 2015, consisting primarily of net income of $3.7 billion for the period and excluding $1.3 billion of noncash charges to income (primarily depreciation and amortization expense). See “RESULTS OF OPERATIONS” for further discussion of our operations. The change in working capital over the nine-month period had little impact to cash generated by our operations, contributing only $46 million. This overall change, however, was composed primarily of a decrease in accounts receivable of $1.1 billion and a largely offsetting decrease in accounts payable of $1.0 billion as shown in Note 10 of Condensed Notes to Consolidated Financial Statements. The favorable

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effect in accounts receivable and the unfavorable effect in accounts payable were mainly due to a decrease in commodity prices from December 2014 to September 2015.

The $5.1 billion of cash provided by our operations during the first nine months of 2015, along with $1.45 billion in proceeds from the issuance of debt, consisting of $600 million of 3.65 percent senior notes due March 15, 2025 and $650 million of 4.9 percent senior notes due March 15, 2045, and borrowings under the VLP Revolver of $200 million as discussed in Note 4 of Condensed Notes to Consolidated Financial Statements, were used mainly to:


•	fund $1.7 billion of capital expenditures and deferred turnaround and catalyst costs;


•	make debt repayments of $502 million, of which $400 million related to our 4.5 percent senior notes, $75 million related to our 8.75 percent debentures, $25 million related to the VLP Revolver, and $2 million related to other non-bank debt;


•	purchase common stock for treasury of $2.1 billion;


•	pay common stock dividends of $608 million; and


•	increase available cash on hand by $1.6 billion.

Cash Flows for the Nine Months Ended September 30, 2014

Our operations generated $3.2 billion of cash during the first nine months of 2014, consisting primarily of net income of $2.5 billion for the period and excluding $1.3 billion of noncash charges to income (primarily depreciation and amortization expense). See “RESULTS OF OPERATIONS” for further discussion of our operations. However, the change in our working capital over the nine-month period had a negative impact to cash generated by our operations of $808 million. This use of cash was composed primarily of an increase in inventories of $1.2 billion and a decrease in income taxes payable of $133 million, partially offset by a decrease in accounts receivable of $503 million as shown in Note 10 of Condensed Notes to Consolidated Financial Statements. The unfavorable effect in inventories was mainly due to the purchase of crude oil feedstocks. The unfavorable effect associated with income taxes payable resulted from income tax payments exceeding income tax liabilities incurred in the 2014 period due to the payment of liabilities associated with prior period earnings. The decrease in accounts receivable was primarily attributable to lower sales in September 2014 compared to those in December 2013.

The $3.2 billion of cash provided by our operations during the first nine months of 2014, along with $101 million from available cash on hand, was used mainly to:


•	fund $1.9 billion of capital expenditures and deferred turnaround and catalyst costs;


•	make a scheduled debt repayment of $200 million related to our 4.75 percent senior notes;


•	purchase common stock for treasury of $799 million; and


•	pay common stock dividends of $411 million.

Capital Investments

For 2015, we expect to incur approximately $1.8 billion for capital expenditures and approximately $700 million for deferred turnaround and catalyst costs. The capital expenditure estimate excludes expenditures related to potential strategic acquisitions, as well as the potential investment in the joint venture described below. We continuously evaluate our capital budget and make changes as conditions warrant.

We hold an option until January 2016 to purchase a 50 percent interest in the Diamond Pipeline project, a 440-mile, 20-inch crude oil pipeline that is projected to provide capacity of up to 200,000 barrels per day of domestic sweet crude oil from the Plains Cushing, Oklahoma terminal to our Memphis Refinery. The Diamond Pipeline project is currently being developed by a third party for an estimated $900 million and is expected to be completed in 2017. If we decide to exercise our option, we would incur additional capital investment expenditures during the fourth quarter of 2015.

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Contractual Obligations

As of September 30, 2015, our contractual obligations included debt, capital lease obligations, operating leases, purchase obligations, and other long-term liabilities. There were no material changes outside the ordinary course of business with respect to these contractual obligations during the nine months ended September 30, 2015.

Our debt and financing agreements do not have rating agency triggers that would automatically require us to post additional collateral. However, in the event of certain downgrades of our senior unsecured debt by the ratings agencies, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. All of the 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 September 30, 2015, letters of credit issued under our committed credit facilities were as follows (in millions):



	Borrowing Capacity		Expiration	Letters of Credit Issued
Letter of credit facility	$	125	June 2016	$	20
Revolver	$	3,000	November 2018	$	54
VLP Revolver	$	300	December 2018	$	—
Canadian Revolver	C$	50	November 2015	C$	10

The letters of credit issued as of September 30, 2015 expire in 2015 through 2018.

Other Matters Impacting Liquidity and Capital Resources

Stock Purchase Programs

On July 13, 2015, our board of directors authorized us to purchase an additional $2.5 billion of our outstanding common stock with no expiration date to such authorization. This authorization was in addition to the remaining amount available under a $3 billion program previously authorized. During the third quarter of

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2015, we completed our purchases under the $3 billion program. As of September 30, 2015, we had approximately $2 billion remaining available under the $2.5 billion program, but we have no obligation to make purchases under this program.

Pension Plan Funding

We contributed $114 million to our pension plans and $11 million to our other postretirement benefit plans during the nine months ended September 30, 2015. During the fourth quarter of 2015, we plan to contribute approximately $10 million to our pension plans and $9 million to our other postretirement benefit plans.

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 as previously discussed above in “OUTLOOK.” 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

The Internal Revenue Service (IRS) has ongoing tax audits related to our U.S. federal tax returns from 2008 through 2011, and we have received Revenue Agent Reports (RARs) in connection with the audits for tax years 2008 and 2009. We are contesting certain tax positions and assertions included in the RARs and continue to make progress in resolving certain of these matters with the IRS. During the nine months ended September 30, 2015, we settled the audit related to our 2004 and 2005 tax years consistent with the recorded amounts of uncertain tax position liabilities associated with that audit. In addition, we settled our audit for tax years 2006 and 2007 in October 2015 for amounts consistent with the recorded amounts of uncertain tax position liabilities associated with that audit.

Cash Held by Our International Subsidiaries

We operate in countries outside the U.S. through subsidiaries incorporated in these countries, and the earnings of these subsidiaries are taxed by the countries in which they are incorporated. We intend to reinvest these earnings indefinitely in our international operations even though we are not restricted from repatriating such earnings to the U.S. in the form of cash dividends. Should we decide to repatriate such earnings, we would incur and pay taxes on the amounts repatriated. In addition, such repatriation could cause us to record deferred tax expense that could significantly impact our results of operations. We believe, however, that a substantial portion of our international cash can be returned to the U.S. without significant tax consequences through means other than a repatriation of earnings. As of September 30, 2015, $1.6 billion 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.

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Sources of Liquidity

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

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 September 30, 2015, there were no significant changes to our critical accounting policies since the date our annual report on Form 10‑K for the year ended December 31, 2014 was filed.


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

COMMODITY PRICE RISK

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


•	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 price risk activities. 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 our risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors.

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



	Derivative Instruments Held For
	Non-Trading Purposes			Trading Purposes
September 30, 2015:
Gain (loss) in fair value resulting from:
10% increase in underlying commodity prices	$	(50	)	$	1
10% decrease in underlying commodity prices	50			(3		)

December 31, 2014:
Gain (loss) in fair value resulting from:
10% increase in underlying commodity prices	(127		)	(2		)
10% decrease in underlying commodity prices	126			7

See Note 12 of Condensed Notes to Consolidated Financial Statements for notional volumes associated with these derivative contracts as of September 30, 2015.

COMPLIANCE PROGRAM PRICE RISK

We are exposed to market risk related to the volatility in the price of biofuel credits and greenhouse gas emission credits needed to comply with various governmental and regulatory programs. To manage these risks, we enter into contracts to purchase these credits when prices are deemed favorable. Some of these contracts are derivative instruments; however, we elect the normal purchase exception and do not record these contracts at their fair values. As of September 30, 2015, there was an immaterial amount of 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.

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INTEREST RATE RISK

The following table provides information about our debt instruments, excluding unamortized discount (including fair value adjustments) and capital lease obligations (dollars in millions), the fair values of which are sensitive to changes in interest rates. Principal cash flows and related weighted-average interest rates by expected maturity dates are presented. We had no interest rate derivative instruments outstanding as of September 30, 2015 or December 31, 2014.



	September 30, 2015
	Expected Maturity Dates
	2015			2016			2017			2018			2019			There- after			Total			Fair Value
Debt:
Fixed rate	$	—		$	—		$	950		$	—		$	750		$	5,324		$	7,024		$	7,823
Average interest rate	—		%	—		%	6.4		%	—		%	9.4		%	6.3		%	6.6		%
Floating rate	$	15		$	104		$	—		$	175		$	—		$	—		$	294		$	294
Average interest rate	6.2		%	1.1		%	—		%	1.5		%	—		%	—		%	1.6		%

	December 31, 2014
	Expected Maturity Dates
	2015			2016			2017			2018			2019			There- after			Total			Fair Value
Debt:
Fixed rate	$	475		$	—		$	950		$	—		$	750		$	4,074		$	6,249		$	7,436
Average interest rate	5.2		%	—		%	6.4		%	—		%	9.4		%	6.9		%	7.0		%
Floating rate	$	126		$	—		$	—		$	—		$	—		$	—		$	126		$	126
Average interest rate	2.0		%	—		%	—		%	—		%	—		%	—		%	2.0		%

FOREIGN CURRENCY RISK

As of September 30, 2015, we had commitments to purchase $344 million of U.S. dollars. Our market risk was minimal on these contracts, as all of them matured before October 31, 2015.

Item 4. Controls and Procedures


(a)	Evaluation of disclosure controls and procedures.

Our management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of September 30, 2015.


(b)	Changes in internal control over financial reporting.

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

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PART II – OTHER INFORMATION


Item 1.	Legal Proceedings

The information below describes new proceedings or material developments in proceedings that we previously reported in our annual report on Form 10-K for the year ended December 31, 2014.

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 into 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, 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. During the third quarter of 2015, we settled various VNs and continue to work with the BAAQMD to resolve the remaining VNs.

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, 2014.

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


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


(b)	Use of Proceeds. Not applicable.


(c)	Issuer Purchases of Equity Securities. The following table discloses purchases of shares of our common stock made by us or on our behalf during the third quarter of 2015.



Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Not Purchased as Part of Publicly Announced Plans or Programs (a)	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (b)
July 2015	2,813,492	$	64.00	461,704	2,351,788	$2.9 billion
August 2015	7,010,629	$	65.44	1,948	7,008,681	$2.5 billion
September 2015	7,374,914	$	59.65	2,708	7,372,206	$2.0 billion
Total	17,199,035	$	62.72	466,360	16,732,675	$2.0 billion

(a)

The shares reported in this column represent purchases settled in the third quarter of 2015 relating to (i) our purchases of shares in open-market transactions to meet our obligations under stock-based compensation plans, and (ii) 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 July 13, 2015, we announced that our board of directors approved our purchase of $2.5 billion of our outstanding common stock (with no expiration date), which was in addition to the remaining amount available under our $3 billion program previously authorized. During the third quarter of 2015, we completed our purchases under the $3 billion program. As of September 30, 2015, we had $2 billion remaining available for purchase under the $2.5 billion program.

Item 6. Exhibits



Exhibit No.	Description

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

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

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

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

101	Interactive Data Files

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SIGNATURE

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




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

Date: November 4, 2015