10-Q 1 vloform10-qx6302014.htm 10-Q VLO Form 10-Q - 6.30.2014

 
 
 
 
 
 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
R
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2014
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from _______________ to _______________
Commission File Number 1-13175
VALERO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Delaware
 
74-1828067
(State or other jurisdiction of
 
(I.R.S. Employer
incorporation or organization)
 
Identification No.)
One Valero Way
San Antonio, Texas
(Address of principal executive offices)
78249
(Zip Code)
(210) 345-2000
(Registrant’s telephone number, including area code) 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes R No o

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No R
The number of shares of the registrant’s only class of common stock, $0.01 par value, outstanding as of July 31, 2014 was 527,963,334.
 
 
 
 
 



VALERO ENERGY CORPORATION
TABLE OF CONTENTS
 
 
 
Page
 
 
for the Three and Six Months Ended June 30, 2014 and 2013
for the Six Months Ended June 30, 2014 and 2013
 
 
 
 
 
 
 
 
 
 
 





i


PART I – FINANCIAL INFORMATION
Item 1. Financial Statements

VALERO ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Par Value)
 
June 30,
2014
 
December 31,
2013
 
(Unaudited)
 
 
ASSETS
 
 
 
Current assets:
 
 
 
Cash and temporary cash investments
$
3,480

 
$
4,292

Receivables, net
7,952

 
8,751

Inventories
6,526

 
5,758

Income taxes receivable
93

 
72

Deferred income taxes
275

 
266

Prepaid expenses and other
124

 
138

Total current assets
18,450

 
19,277

Property, plant, and equipment, at cost
34,870

 
33,933

Accumulated depreciation
(8,748
)
 
(8,226
)
Property, plant, and equipment, net
26,122

 
25,707

Deferred charges and other assets, net
2,441

 
2,276

Total assets
$
47,013

 
$
47,260

LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Current portion of debt and capital lease obligations
$
601

 
$
303

Accounts payable
9,355

 
9,931

Accrued expenses
584

 
522

Taxes other than income taxes
1,286

 
1,345

Income taxes payable
421

 
773

Deferred income taxes
276

 
249

Total current liabilities
12,523

 
13,123

Debt and capital lease obligations, less current portion
5,784

 
6,261

Deferred income taxes
6,659

 
6,601

Other long-term liabilities
1,327

 
1,329

Commitments and contingencies

 

Equity:
 
 
 
Valero Energy Corporation stockholders’ equity:
 
 
 
Common stock, $0.01 par value; 1,200,000,000 shares authorized;
673,501,593 and 673,501,593 shares issued
7

 
7

Additional paid-in capital
7,132

 
7,187

Treasury stock, at cost;
143,579,323 and 137,932,138 common shares
(7,474
)
 
(7,054
)
Retained earnings
20,120

 
18,970

Accumulated other comprehensive income
426

 
350

Total Valero Energy Corporation stockholders’ equity
20,211


19,460

Noncontrolling interests
509

 
486

Total equity
20,720

 
19,946

Total liabilities and equity
$
47,013

 
$
47,260

See Condensed Notes to Consolidated Financial Statements.



1


VALERO ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars, Except Per Share Amounts)
(Unaudited)
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2014
 
2013
 
2014
 
2013
Operating revenues
$
34,914

 
$
34,034

 
$
68,577

 
$
67,508

Costs and expenses:
 
 
 
 
 
 
 
Cost of sales
32,167

 
31,523

 
62,797

 
62,208

Operating expenses:
 
 
 
 
 
 
 
Refining
967

 
909

 
1,939

 
1,788

Retail

 
57

 

 
226

Ethanol
111

 
102

 
240

 
179

General and administrative expenses
170

 
233

 
330

 
409

Depreciation and amortization expense
414

 
405

 
835

 
835

Total costs and expenses
33,829

 
33,229

 
66,141

 
65,645

Operating income
1,085

 
805

 
2,436

 
1,863

Other income, net
12

 
11

 
27

 
25

Interest and debt expense, net of capitalized interest
(98
)
 
(78
)
 
(198
)
 
(161
)
Income from continuing operations before income tax expense
999

 
738

 
2,265

 
1,727

Income tax expense
343

 
276

 
772

 
616

Income from continuing operations
656

 
462

 
1,493

 
1,111

Income (loss) from discontinued operations
(63
)
 
3

 
(64
)
 
6

Net income
593

 
465

 
1,429

 
1,117

Less: Net income (loss) attributable to noncontrolling interests
5

 
(1
)
 
13

 
(3
)
Net income attributable to Valero Energy Corporation stockholders
$
588

 
$
466

 
$
1,416

 
$
1,120

 
 
 
 
 
 
 
 
Net income attributable to Valero Energy Corporation stockholders:
 
 
 
 
 
 
 
Continuing operations
$
651

 
$
463

 
$
1,480

 
$
1,114

Discontinued operations
(63
)
 
3

 
(64
)
 
6

Total
$
588

 
$
466

 
$
1,416

 
$
1,120

 
 
 
 
 
 
 
 
Earnings per common share:
 
 
 
 
 
 
 
Continuing operations
$
1.23

 
$
0.85

 
$
2.78

 
$
2.03

Discontinued operations
(0.12
)
 
0.01

 
(0.12
)
 
0.01

Total
$
1.11

 
$
0.86

 
$
2.66

 
$
2.04

Weighted-average common shares outstanding (in millions)
529

 
543

 
530

 
546

 
 
 
 
 
 
 
 
Earnings per common share – assuming dilution:
 
 
 
 
 
 
 
Continuing operations
$
1.22

 
$
0.84

 
$
2.77

 
$
2.02

Discontinued operations
(0.12
)
 
0.01

 
(0.12
)
 
0.01

Total
$
1.10

 
$
0.85

 
$
2.65

 
$
2.03

Weighted-average common shares outstanding –
assuming dilution (in millions)
534

 
548

 
535

 
552

 
 
 
 
 
 
 
 
Dividends per common share
$
0.25

 
$
0.20

 
$
0.50

 
$
0.40


See Condensed Notes to Consolidated Financial Statements.



2


VALERO ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of Dollars)
(Unaudited)

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2014
 
2013
 
2014
 
2013
Net income
$
593

 
$
465

 
$
1,429

 
$
1,117

 
 
 
 
 
 
 
 
Other comprehensive income (loss):
 
 
 
 
 
 
 
Foreign currency translation adjustment
150

 
(64
)
 
76

 
(268
)
Net gain (loss) on pension
and other postretirement benefits

 
6

 
(2
)
 
342

Net gain (loss) on derivative instruments designated
and qualifying as cash flow hedges
(3
)
 
(2
)
 
1

 
(4
)
Other comprehensive income (loss)
before income tax expense (benefit)
147

 
(60
)
 
75

 
70

Income tax expense (benefit) related to
items of other comprehensive income (loss)
(2
)
 
1

 
(1
)
 
118

Other comprehensive income (loss)
149

 
(61
)
 
76

 
(48
)
 
 
 
 
 
 
 
 
Comprehensive income
742

 
404

 
1,505

 
1,069

Less: Comprehensive income (loss) attributable to
noncontrolling interests
5

 
(1
)
 
13

 
(3
)
Comprehensive income attributable to
Valero Energy Corporation stockholders
$
737

 
$
405

 
$
1,492

 
$
1,072

See Condensed Notes to Consolidated Financial Statements.



3


VALERO ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)
 
Six Months Ended
June 30,
 
2014
 
2013
Cash flows from operating activities:
 
 
 
Net income
$
1,429

 
$
1,117

Adjustments to reconcile net income to net cash provided by
operating activities:
 
 
 
Depreciation and amortization expense
835

 
835

Aruba Refinery asset retirement expense and other
63

 

Deferred income tax expense
73

 
341

Changes in current assets and current liabilities
(1,024
)
 
444

Changes in deferred charges and credits and
other operating activities, net
2

 
77

Net cash provided by operating activities
1,378

 
2,814

Cash flows from investing activities:
 
 
 
Capital expenditures
(954
)
 
(1,211
)
Deferred turnaround and catalyst costs
(369
)
 
(449
)
Other investing activities, net
(43
)
 
(23
)
Net cash used in investing activities
(1,366
)
 
(1,683
)
Cash flows from financing activities:
 
 
 
Repayment of debt
(200
)
 
(480
)
Proceeds from the exercise of stock options
32

 
43

Purchase of common stock for treasury
(455
)
 
(560
)
Common stock dividends
(266
)
 
(220
)
Contributions from noncontrolling interests
14

 
45

Distributions to public unitholders of Valero Energy Partners LP
(4
)
 

Disposition of retail business:
 
 
 
Proceeds from short-term debt in anticipation of separation

 
550

Cash distributed to Valero by CST Brands, Inc.

 
500

Cash held and retained by CST Brands, Inc. upon separation

 
(315
)
Other financing activities, net
52

 
24

Net cash used in financing activities
(827
)
 
(413
)
Effect of foreign exchange rate changes on cash
3

 
(43
)
Net increase (decrease) in cash and temporary cash investments
(812
)
 
675

Cash and temporary cash investments at beginning of period
4,292

 
1,723

Cash and temporary cash investments at end of period
$
3,480

 
$
2,398

See Condensed Notes to Consolidated Financial Statements.

4



VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
As used in this report, the terms “Valero,” “we,” “us,” or “our” may refer to Valero Energy Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole.
These unaudited financial statements have been prepared in accordance with United States (U.S.) generally accepted accounting principles (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature unless disclosed otherwise. Financial information for the three and six months ended June 30, 2014 and 2013 included in these Condensed Notes to Consolidated Financial Statements is derived from our unaudited financial statements. Operating results for the three and six months ended June 30, 2014 are not necessarily indicative of the results that may be expected for the year ending December 31, 2014.

The balance sheet as of December 31, 2013 has been derived from our audited financial statements as of that date. For further information, refer to our financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2013.

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

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

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




5




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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

2.
VALERO ENERGY PARTNERS LP

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

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



6




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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

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

3.
DISCONTINUED OPERATIONS

In May 2014, we decided to abandon our Aruba Refinery, except for the associated crude oil and refined products terminal assets that we continue to operate. As a result of our decision, the refinery’s results of operations have been presented in this report as discontinued operations for the three and six months ended June 30, 2014 and 2013.
We had suspended operations of the refinery in 2012 and at that time we wrote off the entire carrying value of the refinery’s idled crude oil processing units and related infrastructure (refining assets) and supplies inventories that supported the refining operations. In addition, we terminated the employees who supported the refining operations and incurred severance costs at that time. Even though we suspended refining operations in 2012, we continued to maintain the refining assets to allow them to be restarted and did not abandon them until our recent decision to no longer pursue options to restart refining operations.
The Aruba Refinery resides on land leased from the Government of Aruba (GOA) and our agreements with the GOA require us to dismantle our leasehold improvements under certain conditions. Because of our May 2014 decision to abandon the refining assets, we believe the GOA will require us to dismantle those assets. As a result, we recognized an asset retirement obligation of $59 million, which was charged to expense during the three months ended June 30, 2014, and is reflected in discontinued operations. We had not recognized an asset retirement obligation previously due to our belief that we would not be required to



7




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

dismantle the assets as long as we intended to operate them. In the second quarter of 2014, we also recognized liabilities of $4 million relating to obligations under certain contracts, including a liability for the remaining lease payments for the land on which the refining assets reside.
Of the $63 million of liabilities recorded in connection with our decision to abandon the Aruba Refinery, $30 million is classified as a current liability and is reflected in accrued expenses, and $33 million is classified as a long-term liability and is reflected in other long-term liabilities as of June 30, 2014. Our agreements with the GOA require us to complete the dismantlement activities within 3 years.
Selected results of operations of the Aruba Refinery are shown below (in millions).
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2014
 
2013
2014
 
2013
Operating revenues
$

 
$

 
$

 
$

Income (loss) before income taxes
(63
)
 
3

 
(64
)
 
6


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

4.
SEPARATION OF RETAIL BUSINESS

On May 1, 2013, we completed the separation of our retail business by creating an independent public company named CST Brands, Inc. (CST) and distributing 80 percent of the outstanding shares of CST common stock to our stockholders. Each Valero stockholder received one share of CST common stock for every nine shares of Valero common stock held at the close of business on the record date of April 19, 2013.

In connection with the separation, we received an aggregate of $1.05 billion in cash, consisting of $550 million from the issuance of short-term debt to a third-party financial institution on April 16, 2013 and $500 million distributed to us by CST on May 1, 2013. The cash distributed to us by CST was borrowed by CST on May 1, 2013 under its senior secured credit facility. Also on May 1, 2013, CST issued $550 million of its senior unsecured bonds to us, and we exchanged those bonds with the third-party financial institution in satisfaction of our short-term debt. Immediately prior to May 1, 2013, subsidiaries of CST held $315 million of cash, and CST retained that cash following the distribution on May 1, 2013. We also incurred $30 million in costs during the three months ended June 30, 2013 to effect the separation, which were included in general and administrative expenses.

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

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




8




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

5.
INVENTORIES

Inventories consisted of the following (in millions):
 
June 30,
2014
 
December 31,
2013
Refinery feedstocks
$
3,380

 
$
2,135

Refined products and blendstocks
2,732

 
3,231

Ethanol feedstocks and products
182

 
166

Materials and supplies
232

 
226

Inventories
$
6,526

 
$
5,758


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

6.
DEBT

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

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

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




9




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

We had outstanding letters of credit under our committed lines of credit as follows (in millions):
 
 
 
 
 
Amounts Outstanding
 
Borrowing
Capacity
 
Expiration
 
June 30,
2014
 
December 31,
2013
Letter of credit facilities
$
550

 
June 2015
 
$

 
$
278

Revolver
$
3,000

 
November 2018
 
$
59

 
$
59

VLP Revolver
$
300

 
December 2018
 
$

 
$

Canadian revolving credit facility
C$
50

 
November 2014
 
C$
10

 
C$
10


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

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

Accounts Receivable Sales Facility
We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell up to $1.5 billion of eligible trade receivables on a revolving basis. In July 2014, we amended this facility to extend the maturity date to July 2015. Proceeds from the sale of receivables under this facility are reflected as debt. Under this program, one of our marketing subsidiaries (Valero Marketing) sells eligible receivables, without recourse, to another of our subsidiaries (Valero Capital), whereupon the receivables are no longer owned by Valero Marketing. Valero Capital, in turn, sells an undivided percentage ownership interest in the eligible receivables, without recourse, to the third-party entities and financial institutions. To the extent that Valero Capital retains an ownership interest in the receivables it has purchased from Valero Marketing, such interest is included in our financial statements solely as a result of the consolidation of the financial statements of Valero Capital with those of Valero Energy Corporation; the receivables are not available to satisfy the claims of the creditors of Valero Marketing or Valero Energy Corporation.

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

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




10




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7.
COMMITMENTS AND CONTINGENCIES

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

Litigation Matters
We are party to claims and legal proceedings arising in the ordinary course of business. We have not recorded a loss contingency liability with respect to some of these matters because we have determined that it is remote that a loss has been incurred. For other matters, we have recorded a loss contingency liability where we have determined that it is probable that a loss has been incurred and that the loss is reasonably estimable. These loss contingency liabilities are not material to our financial position. We re-evaluate and update our loss contingency liabilities as matters progress over time, and we believe that any changes to the recorded liabilities will not be material to our financial position, results of operations, or liquidity.




11




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8.
EQUITY

Reconciliation of Balances
The following is a reconciliation of the beginning and ending balances of equity attributable to our stockholders, equity attributable to the noncontrolling interests, and total equity (in millions):
 
Six Months Ended June 30,
 
2014
 
2013
 
Valero
Stockholders
Equity
 
Non-
controlling
Interests
 
Total
Equity
 
Valero
Stockholders
Equity
 
Non-
controlling
Interests
 
Total
Equity
Balance as of
beginning of period
$
19,460

 
$
486

 
$
19,946

 
$
18,032

 
$
63

 
$
18,095

Net income (loss)
1,416

 
13

 
1,429

 
1,120

 
(3
)
 
1,117

Dividends
(266
)
 

 
(266
)
 
(220
)
 

 
(220
)
Stock-based
compensation expense
21

 

 
21

 
25

 

 
25

Tax deduction in excess
of stock-based
compensation expense
31

 

 
31

 
27

 

 
27

Transactions
in connection with
stock-based
compensation plans:
 
 
 
 
 
 
 
 
 
 
 
Stock issuances
32

 

 
32

 
43

 

 
43

Stock repurchases
(76
)
 

 
(76
)
 
(196
)
 

 
(196
)
Stock repurchases under
buyback program
(483
)
 

 
(483
)
 
(364
)
 

 
(364
)
Separation of retail business

 

 

 
(499
)
 

 
(499
)
Contributions from
noncontrolling interests

 
14

 
14

 

 
45

 
45

Distributions to public
unitholders of
Valero Energy Partners LP

 
(4
)
 
(4
)
 

 

 

Other comprehensive
income (loss)
76

 

 
76

 
(48
)
 

 
(48
)
Balance as of end of period
$
20,211

 
$
509

 
$
20,720

 
$
17,920

 
$
105

 
$
18,025


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




12




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Share Activity
Activity in the number of shares of common stock and treasury stock was as follows (in millions):
 
Six Months Ended June 30,
 
2014
 
2013
 
Common
Stock
 
Treasury
Stock
 
Common
Stock
 
Treasury
Stock
Balance as of beginning of period
673

 
(138
)
 
673

 
(121
)
Transactions in connection with
stock-based compensation plans:
 
 
 
 
 
 
 
Stock issuances

 
2

 

 
3

Stock repurchases

 
(1
)
 

 
(5
)
Stock repurchases under buyback program

 
(7
)
 

 
(8
)
Balance as of end of period
673

 
(144
)
 
673

 
(131
)

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

Income Tax Effects related to Components of Other Comprehensive Income
The tax effects allocated to each component of other comprehensive income (loss) were as follows (in millions):
 
Three Months Ended June 30,
 
2014
 
2013
 
Before-Tax Amount
 
Tax Expense (Benefit)
 
Net Amount
 
Before-Tax Amount
 
Tax Expense (Benefit)
 
Net Amount
Foreign currency translation adjustment
$
150

 
$

 
$
150

 
$
(64
)
 
$

 
$
(64
)
Pension and other postretirement benefits:
 
 
 
 
 
 
 
 
 
 
 
Amounts reclassified into income related to:
 
 
 
 

 
 
 
 
 
 
Net actuarial loss
9

 
3

 
6

 
15

 
5

 
10

Prior service credit
(9
)
 
(5
)
 
(4
)
 
(9
)
 
(4
)
 
(5
)
Net gain on pension and other
postretirement benefits

 
(2
)
 
2

 
6

 
1

 
5

Derivative instruments designated and
qualifying as cash flow hedges:
 
 
 
 
 
 
 
 
 
 
 
Net loss arising during the period
(3
)
 

 
(3
)
 
(10
)
 
(3
)
 
(7
)
Net loss reclassified into income

 

 

 
8

 
3

 
5

Net loss on cash flow hedges
(3
)
 

 
(3
)
 
(2
)
 

 
(2
)
Other comprehensive income (loss)
$
147

 
$
(2
)
 
$
149

 
$
(60
)
 
$
1

 
$
(61
)




13




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 
Six Months Ended June 30,
 
2014
 
2013
 
Before-Tax Amount
 
Tax Expense (Benefit)
 
Net Amount
 
Before-Tax Amount
 
Tax Expense (Benefit)
 
Net Amount
Foreign currency translation adjustment
$
76

 
$

 
$
76

 
$
(268
)
 
$

 
$
(268
)
Pension and other postretirement benefits:
 
 
 
 
 
 
 
 
 
 
 
Gain arising during the period related to
plan amendments

 

 

 
328

 
115

 
213

Amounts reclassified into income related to:
 
 
 
 
 
 
 
 
 
 
 
Net actuarial loss
17

 
6

 
11

 
29

 
10

 
19

Prior service credit
(19
)
 
(8
)
 
(11
)
 
(15
)
 
(6
)
 
(9
)
Net gain (loss) on pension and other
postretirement benefits
(2
)
 
(2
)
 

 
342

 
119

 
223

Derivative instruments designated and
qualifying as cash flow hedges:
 
 
 
 
 
 
 
 
 
 
 
Net gain (loss) arising during the period
4

 
2

 
2

 
(9
)
 
(3
)
 
(6
)
Net (gain) loss reclassified into income
(3
)
 
(1
)
 
(2
)
 
5

 
2

 
3

Net gain (loss) on cash flow hedges
1

 
1

 

 
(4
)
 
(1
)
 
(3
)
Other comprehensive income (loss)
$
75

 
$
(1
)
 
$
76

 
$
70

 
$
118

 
$
(48
)

Accumulated Other Comprehensive Income
Changes in accumulated other comprehensive income by component, net of tax, were as follows (in millions):
 
Foreign
Currency
Translation
Adjustment
 
Defined
Benefit
Plans
Items
 
Gains and
(Losses) on
Cash Flow
Hedges
 
Total
Balance as of December 31, 2013
$
408

 
$
(58
)
 
$

 
$
350

Other comprehensive income
before reclassifications
76

 

 
2

 
78

Amounts reclassified from
accumulated other comprehensive
income (loss)

 

 
(2
)
 
(2
)
Net other comprehensive income
76

 

 

 
76

Balance as of June 30, 2014
$
484

 
$
(58
)
 
$

 
$
426





14




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 
Foreign
Currency
Translation
Adjustment
 
Defined
Benefit
Plans
Items
 
Gains and
(Losses) on
Cash Flow
Hedges
 
Total
Balance as of December 31, 2012
$
665

 
$
(558
)
 
$
1

 
$
108

Other comprehensive income (loss)
before reclassifications
(268
)
 
213

 
(6
)
 
(61
)
Amounts reclassified from
accumulated other comprehensive
income (loss)

 
10

 
3

 
13

Net other comprehensive income (loss)
(268
)
 
223

 
(3
)
 
(48
)
Separation of retail business
(159
)
 

 

 
(159
)
Balance as of June 30, 2013
$
238

 
$
(335
)
 
$
(2
)
 
$
(99
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 



15




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9.
EMPLOYEE BENEFIT PLANS

The components of net periodic benefit cost related to our defined benefit plans were as follows (in millions) :
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
2014
 
2013
 
2014
 
2013
Three months ended June 30:
 
 
 
 
 
 
 
Service cost
$
30

 
$
35

 
$
1

 
$
3

Interest cost
23

 
22

 
4

 
5

Expected return on plan assets
(33
)
 
(34
)
 

 

Amortization of:
 
 
 
 
 
 
 
Prior service credit
(5
)
 
(6
)
 
(4
)
 
(3
)
Net actuarial loss
9

 
15

 

 

Net periodic benefit cost
$
24

 
$
32

 
$
1

 
$
5

 
 
 
 
 
 
 
 
Six months ended June 30:
 
 
 
 
 
 
 
Service cost
$
60

 
$
71

 
$
3

 
$
6

Interest cost
46

 
44

 
8

 
9

Expected return on plan assets
(66
)
 
(66
)
 

 

Amortization of:
 
 
 
 
 
 
 
Prior service credit
(10
)
 
(9
)
 
(9
)
 
(6
)
Net actuarial loss
17

 
29

 

 

Net periodic benefit cost
$
47

 
$
69

 
$
2

 
$
9


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

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




16




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10.
EARNINGS PER COMMON SHARE

Earnings per common share were computed as follows (dollars and shares in millions, except per share amounts):
 
Three Months Ended June 30,
 
2014
 
2013
 
Restricted
Stock
 
Common
Stock
 
Restricted
Stock
 
Common
Stock
Earnings per common share from
continuing operations:
 
 
 
 
 
 
 
Net income attributable to Valero stockholders
from continuing operations
 
 
$
651

 
 
 
$
463

Less dividends paid:
 
 
 
 
 
 
 
Common stock
 
 
133

 

 
109

Undistributed earnings
 
 
$
518

 

 
$
354

Weighted-average common shares outstanding
2

 
529

 
3

 
543

Earnings per common share from
continuing operations:
 
 
 
 
 
 
 
Distributed earnings
$
0.25

 
$
0.25

 
$
0.20

 
$
0.20

Undistributed earnings
0.98

 
0.98

 
0.65

 
0.65

Total earnings per common share from
continuing operations
$
1.23

 
$
1.23

 
$
0.85

 
$
0.85

 
 
 
 
 
 
 
 
Earnings per common share from
continuing operations – assuming dilution:
 
 
 
 
 
 
 
Net income attributable to Valero stockholders
from continuing operations
 
 
$
651

 
 
 
$
463

Weighted-average common shares outstanding
 
 
529

 
 
 
543

Common equivalent shares:
 
 
 
 
 
 
 
Stock options
 
 
3

 
 
 
3

Performance awards and
nonvested restricted stock
 
 
2

 
 
 
2

Weighted-average common shares outstanding –
assuming dilution
 
 
534

 
 
 
548

Earnings per common share from
continuing operations – assuming dilution
 
 
$
1.22

 
 
 
$
0.84




17




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 
Six Months Ended June 30,
 
2014
 
2013
 
Restricted
Stock
 
Common
Stock
 
Restricted
Stock
 
Common
Stock
Earnings per common share from
continuing operations:
 
 
 
 
 
 
 
Net income attributable to Valero stockholders
from continuing operations
 
 
$
1,480

 
 
 
$
1,114

Less dividends paid:
 
 
 
 
 
 
 
Common stock
 
 
265

 
 
 
219

Nonvested restricted stock
 
 
1

 
 
 
1

Undistributed earnings
 
 
$
1,214

 
 
 
$
894

Weighted-average common shares outstanding
2

 
530

 
3

 
546

Earnings per common share from
continuing operations:
 
 
 
 
 
 
 
Distributed earnings
$
0.50

 
$
0.50

 
$
0.40

 
$
0.40

Undistributed earnings
2.28

 
2.28

 
1.63

 
1.63

Total earnings per common share from
continuing operations
$
2.78

 
$
2.78

 
$
2.03

 
$
2.03

 
 
 
 
 
 
 
 
Earnings per common share from
continuing operations – assuming dilution:
 
 
 
 
 
 
 
Net income attributable to Valero stockholders
from continuing operations
 
 
$
1,480

 
 
 
$
1,114

Weighted-average common shares outstanding
 
 
530

 
 
 
546

Common equivalent shares:
 
 
 
 
 
 
 
Stock options
 
 
3

 
 
 
4

Performance awards and
nonvested restricted stock
 
 
2

 
 
 
2

Weighted-average common shares outstanding –
assuming dilution
 
 
535

 
 
 
552

Earnings per common share from
continuing operations – assuming dilution
 
 
$
2.77

 
 
 
$
2.02





18




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2014
 
2013
 
2014
 
2013
Stock options
1

 
3

 
1

 
3





19




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11.
SEGMENT INFORMATION

In May 2013, we completed the separation of our retail business, CST, and as a result, we no longer operate a retail business or report retail segment operating results. Segment activity related to our retail business prior to the separation is reflected in the retail segment results below. Motor fuel sales to CST, which were eliminated in consolidation prior to the separation, are reported as refining segment operating revenues from external customers after May 1, 2013.

The following table reflects activity related to our reportable segments (in millions):
 
Refining
 
Ethanol
 
Retail
 
Corporate
 
Total
Three months ended June 30, 2014:
 
 
 
 
 
 
 
 
 
Operating revenues from external
customers
$
33,457

 
$
1,457

 
$

 
$

 
$
34,914

Intersegment revenues

 
9

 

 

 
9

Operating income (loss)
1,079

 
187

 

 
(181
)
 
1,085

 
 
 
 
 
 
 
 
 
 
Three months ended June 30, 2013:
 
 
 
 
 
 
 
 
 
Operating revenues from external
customers
31,564

 
1,491

 
979

 

 
34,034

Intersegment revenues
671

 
15

 

 

 
686

Operating income (loss)
918

 
95

 
39

 
(247
)
 
805

 
 
 
 
 
 
 
 
 
 
Six months ended June 30, 2014:
 
 
 
 
 
 
 
 
 
Operating revenues from external
customers
65,909

 
2,668

 

 

 
68,577

Intersegment revenues

 
34

 

 

 
34

Operating income (loss)
2,359

 
430

 

 
(353
)
 
2,436

 
 
 
 
 
 
 
 
 
 
Six months ended June 30, 2013:
 
 
 
 
 
 
 
 
 
Operating revenues from external
customers
61,117

 
2,495

 
3,896

 

 
67,508

Intersegment revenues
2,876

 
70

 

 

 
2,946

Operating income (loss)
2,127

 
109

 
81

 
(454
)
 
1,863





20




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

 
June 30,
2014
 
December 31,
2013
Refining
$
41,326

 
$
40,834

Ethanol
937

 
889

Corporate
4,750

 
5,537

Total assets
$
47,013

 
$
47,260


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

12.
SUPPLEMENTAL CASH FLOW INFORMATION

In order to determine net cash provided by operating activities, net income is adjusted by, among other things, changes in current assets and current liabilities as follows (in millions):
 
Six Months Ended
June 30,
 
2014
 
2013
Decrease (increase) in current assets:
 
 
 
Receivables, net
$
837

 
$
412

Inventories
(721
)
 
(824
)
Income taxes receivable
(16
)
 
31

Prepaid expenses and other
11

 
2

Increase (decrease) in current liabilities:
 
 
 
Accounts payable
(707
)
 
625

Accrued expenses
12

 
(44
)
Taxes other than income taxes
(71
)
 
268

Income taxes payable
(369
)
 
(26
)
Changes in current assets and current liabilities
$
(1,024
)
 
$
444


The above changes in current assets and current liabilities differ from changes between amounts reflected in the applicable balance sheets for the respective periods for the following reasons:
the amounts shown above exclude changes in cash and temporary cash investments, deferred income taxes, and current portion of debt and capital lease obligations, as well as the effect of certain noncash investing and financing activities discussed below;
the amounts shown above for the six months ended June 30, 2013 exclude the change in current assets and current liabilities resulting from the separation of our retail business as described in Note 4;



21




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

amounts accrued for capital expenditures and deferred turnaround and catalyst costs are reflected in investing activities when such amounts are paid;
amounts accrued for common stock purchases in the open market that are not settled as of the balance sheet date are reflected in financing activities when the purchases are settled and paid; and
certain differences between balance sheet changes and the changes reflected above result from translating foreign currency denominated balances at the applicable exchange rates as of each balance sheet date.

There were no significant noncash investing activities for the six months ended June 30, 2014 and 2013. Noncash financing activities for the six months ended June 30, 2014 included an accrual of $104 million for the purchase of 2,000,000 shares of our common stock, which was settled in early July 2014. Noncash financing activities for the six months ended June 30, 2013 included the exchange of CST’s senior unsecured bonds with the third-party financial institution in satisfaction of our short-term debt as described in Note 4.

Cash flows related to interest and income taxes were as follows (in millions):
 
Six Months Ended
June 30,
 
2014
 
2013
Interest paid in excess of amount capitalized
$
197

 
$
160

Income taxes paid, net
1,054

 
243


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




22




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13.
FAIR VALUE MEASUREMENTS

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

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

U.S. GAAP provides a framework for measuring fair value and establishes a three-level fair value hierarchy that prioritizes inputs to valuation techniques based on the degree to which objective prices in external active markets are available to measure fair value. Following is a description of each of the levels of the fair value hierarchy.
Level 1 - Observable inputs, such as unadjusted quoted prices in active markets for identical assets or liabilities.
Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active.
Level 3 - Unobservable inputs for the asset or liability. Unobservable inputs reflect our own assumptions about what market participants would use to price the asset or liability. The inputs are developed based on the best information available in the circumstances, which might include occasional market quotes or sales of similar instruments or our own financial data such as internally developed pricing models, discounted cash flow methodologies, as well as instruments for which the fair value determination requires significant judgment.




23




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Recurring Fair Value Measurements
The tables below present information (in millions) about our assets and liabilities recognized at their fair values in our balance sheets categorized according to the fair value hierarchy of the inputs utilized by us to determine the fair values as of June 30, 2014 and December 31, 2013.

We have elected to offset the fair value amounts recognized for multiple similar derivative contracts executed with the same counterparty, including any related cash collateral assets or obligations as shown below; however, fair value amounts by hierarchy level are presented on a gross basis in the tables below. We have no derivative contracts that are subject to master netting arrangements that are reflected gross on the balance sheet.
 
June 30, 2014
 
 
 
Total
Gross
Fair
Value
 
Effect of
Counter-
party
Netting
 
Effect of
Cash
Collateral
Netting
 
Net
Carrying
Value on
Balance
Sheet
 
Cash
Collateral
Paid or
Received
Not Offset
 
Fair Value Hierarchy
 
 
Level 1
 
Level 2
 
Level 3
 
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivative
contracts
$
1,182

 
$
28

 
$

 
$
1,210

 
$
(1,182
)
 
$
(5
)
 
$
23

 
$

Investments of certain
benefit plans
100

 

 
11

 
111

 
n/a

 
n/a

 
111

 
n/a

Total
$
1,282

 
$
28

 
$
11

 
$
1,321

 
$
(1,182
)
 
$
(5
)
 
$
134

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 

 
 
 
 
 

 
 
Commodity derivative
contracts
$
1,260

 
$
32

 
$

 
$
1,292

 
$
(1,182
)
 
$
(109
)
 
$
1

 
$
(159
)
Biofuels blending
obligation

 
77

 

 
77

 
n/a

 
n/a

 
77

 
n/a

Physical purchase
contracts

 
11

 

 
11

 
n/a

 
n/a

 
11

 
n/a

Foreign currency
contracts
13

 

 

 
13

 
n/a

 
n/a

 
13

 
n/a

Total
$
1,273

 
$
120

 
$

 
$
1,393

 
$
(1,182
)
 
$
(109
)
 
$
102

 





24




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

 
December 31, 2013
 
 
 
Total
Gross
Fair
Value
 
Effect of
Counter-
party
Netting
 
Effect of
Cash
Collateral
Netting
 
Net
Carrying
Value on
Balance
Sheet
 
Cash
Collateral
Paid or
Received
Not Offset
 
Fair Value Hierarchy
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivative
contracts
$
499

 
$
38

 
$

 
$
537

 
$
(505
)
 
$
(7
)
 
$
25

 
$

Investments of certain benefit plans
98

 

 
11

 
109

 
n/a

 
n/a

 
109

 
n/a

Total
$
597

 
$
38

 
$
11

 
$
646

 
$
(505
)
 
$
(7
)
 
$
134

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivative
contracts
$
492

 
$
24

 
$

 
$
516

 
$
(505
)
 
$
(6
)
 
$
5

 
$
(76
)
Biofuels blending obligation

 
11

 

 
11

 
n/a

 
n/a

 
11

 
n/a

Physical purchase contracts

 
5

 

 
5

 
n/a

 
n/a

 
5

 
n/a

Foreign currency
contracts
8

 

 

 
8

 
n/a

 
n/a

 
8

 
n/a

Total
$
500

 
$
40

 
$

 
$
540

 
$
(505
)
 
$
(6
)
 
$
29

 



A description of our assets and liabilities recognized at fair value along with the valuation methods and inputs we used to develop their fair value measurements are as follows:
Commodity derivative contracts consist primarily of exchange-traded futures and swaps, and as disclosed in Note 14, some of these contracts are designated as hedging instruments. These contracts are measured at fair value using the market approach. Exchange-traded futures are valued based on quoted prices from the exchange and are categorized in Level 1 of the fair value hierarchy. Swaps are priced using third-party broker quotes, industry pricing services, and exchange-traded curves, with appropriate consideration of counterparty credit risk, but because they have contractual terms that are not identical to exchange-traded futures instruments with a comparable market price, these financial instruments are categorized in Level 2 of the fair value hierarchy.
Physical purchase contracts represent the fair value of firm commitments to purchase crude oil feedstocks and the fair value of fixed-price corn purchase contracts, and as disclosed in Note 14, some of these contracts are designated as hedging instruments. The fair values of these firm commitments and purchase contracts are measured using a market approach based on quoted prices from the commodity exchange or an independent pricing service and are categorized in Level 2 of the fair value hierarchy.
Investments of certain benefit plans consist of investment securities held by trusts for the purpose of satisfying a portion of our obligations under certain U.S. nonqualified benefit plans. The assets categorized in Level 1 of the fair value hierarchy are measured at fair value using a market approach based on quoted prices from national securities exchanges. The assets categorized in Level 3 of the fair value hierarchy represent insurance contracts, the fair value of which is provided by the insurer.
Foreign currency contracts consist of foreign currency exchange and purchase contracts entered into by our international operations to manage our exposure to exchange rate fluctuations on transactions



25




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

denominated in currencies other than the local (functional) currencies of those operations. These contracts are valued based on quoted prices from the exchange and are categorized in Level 1 of the fair value hierarchy.
Our biofuels blending obligation represents a liability for the purchase of biofuel credits (primarily Renewable Identification Numbers (RINs) in the U.S.) needed to satisfy our obligation to blend biofuels into the products we produce. To the degree we are unable to blend at percentages required under various governmental and regulatory programs, we must purchase biofuel credits to comply with these programs. These programs are further described in Note 14 under “Compliance Program Price Risk.” This liability is based on our deficit in biofuel credits as of the balance sheet date, if any, after considering any biofuel credits acquired or under contract, and is equal to the product of the biofuel credits deficit and the market price of these credits as of the balance sheet date. This liability is categorized in Level 2 of the fair value hierarchy and is measured at fair value using the market approach based on quoted prices from an independent pricing service.

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

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

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

Other Financial Instruments
Financial instruments that we recognize in our balance sheets at their carrying amounts are shown in the table below (in millions):
 
June 30, 2014
 
December 31, 2013
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Financial assets:
 
 
 
 
 
 
 
Cash and temporary cash investments
$
3,480

 
$
3,480

 
$
4,292

 
$
4,292

Financial liabilities:
 
 
 
 
 
 
 
Debt (excluding capital leases)
6,348

 
7,862

 
6,525

 
7,659


The methods and significant assumptions used to estimate the fair value of these financial instruments are as follows:
The fair value of cash and temporary cash investments approximates the carrying value due to the low level of credit risk of these assets combined with their short maturities and market interest rates (Level 1).
The fair value of debt is determined primarily using the market approach based on quoted prices provided by third-party brokers and vendor pricing services (Level 2).




26




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14.
PRICE RISK MANAGEMENT ACTIVITIES

We are exposed to market risks related to the volatility in the price of commodities, interest rates, and foreign currency exchange rates. We enter into derivative instruments to manage some of these risks, including derivative instruments related to the various commodities we purchase or produce, interest rate swaps, and foreign currency exchange and purchase contracts, as described below under “Risk Management Activities by Type of Risk.” These derivative instruments are recorded as either assets or liabilities measured at their fair values (see Note 13), as summarized below under “Fair Values of Derivative Instruments.” In addition, the effect of these derivative instruments on our income is summarized below under “Effect of Derivative Instruments on Income and Other Comprehensive Income.”

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

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

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

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



27




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Fair Value Hedges – Fair value hedges are used to hedge price volatility in certain refining inventories and firm commitments to purchase inventories. The level of activity for our fair value hedges is based on the level of our operating inventories, and generally represents the amount by which our inventories differ from our previous year-end LIFO inventory levels.
As of June 30, 2014, we had no outstanding commodity derivative instruments that were entered into to hedge crude oil and refined product inventories and no commodity derivative instruments related to the physical purchase of crude oil and refined products at a fixed price.
Cash Flow Hedges – Cash flow hedges are used to hedge price volatility in certain forecasted feedstock and refined product purchases, refined product sales, and natural gas purchases. The objective of our cash flow hedges is to lock in the price of forecasted feedstock, refined product, or natural gas purchases or refined product sales at existing market prices that we deem favorable.

As of June 30, 2014, we had the following outstanding commodity derivative instruments that were entered into to hedge forecasted purchases of crude oil and sales of refined products. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).

 
 
Notional
Contract
Volumes by
Year of
Maturity
Derivative Instrument
 
2014
Crude oil and refined products:
 
 
Futures – long
 
6,006

Futures – short
 
2,793

Physical contracts – short
 
3,213




28




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Economic Hedges – Economic hedges represent commodity derivative instruments that are not designated as fair value or cash flow hedges and are used to manage price volatility in certain (i) refinery feedstock, refined product, animal fat feedstock, and corn inventories, (ii) forecasted refinery feedstock, refined product, and corn purchases, and refined product sales, and (iii) fixed-price corn purchase contracts. Our objective for entering into economic hedges is consistent with the objectives discussed above for fair value hedges and cash flow hedges. However, the economic hedges are not designated as a fair value hedge or a cash flow hedge for accounting purposes, usually due to the difficulty of establishing the required documentation at the date that the derivative instrument is entered into that would allow us to achieve “hedge deferral accounting.”
As of June 30, 2014, we had the following outstanding commodity derivative instruments that were used as economic hedges, as well as commodity derivative instruments related to the physical purchase of corn at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except those identified as corn contracts that are presented in thousands of bushels, and soybean oil contracts that are presented in thousands of pounds).

 
 
Notional Contract Volumes by
Year of Maturity
Derivative Instrument
 
2014
 
2015
Crude oil and refined products:
 
 
 
 
Swaps – long
 
10,145

 

Swaps – short
 
10,286

 
30

Futures – long
 
89,761

 
39

Futures – short
 
108,422

 
1

Corn:
 
 
 
 
Futures – long
 
20,770

 
5

Futures – short
 
43,805

 
3,415

Physical contracts – long
 
24,339

 
3,405

Soybean oil:
 
 
 
 
Futures – long
 
115,440

 

Futures – short
 
212,520

 




29




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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

 
 
Notional Contract Volumes by
Year of Maturity
Derivative Instrument
 
2014
 
2015
Crude oil and refined products:
 
 
 
 
Swaps – long
 
10,650

 
120

Swaps – short
 
10,650

 
120

Futures – long
 
96,138

 
16,519

Futures – short
 
95,818

 
16,194

Options – long
 
700

 

Options – short
 
1,150

 

Natural gas:
 
 
 
 
Futures – long
 
250

 
1,800

Futures – short
 
750

 

Options – long
 
500

 


Interest Rate Risk
Our primary market risk exposure for changes in interest rates relates to our debt obligations. We manage our exposure to changing interest rates through the use of a combination of fixed-rate and floating-rate debt. In addition, at times we have used interest rate swap agreements to manage our fixed to floating interest rate position by converting certain fixed-rate debt to floating-rate debt. We had no interest rate derivative instruments outstanding as of June 30, 2014 or December 31, 2013, or during the three and six months ended June 30, 2014 and 2013.

Foreign Currency Risk
We are exposed to exchange rate fluctuations on transactions entered into by our international operations that are denominated in currencies other than the local (functional) currencies of those operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and purchase contracts. These contracts are not designated as hedging instruments for accounting purposes, and therefore they are classified as economic hedges. As of June 30, 2014, we had commitments to purchase $692 million of U.S. dollars. The majority of these commitments matured on or before July 31, 2014, resulting in an immaterial gain in the third quarter of 2014.




30




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Compliance Program Price Risk
We are exposed to market risk related to the volatility in the price of credits needed to comply with various governmental and regulatory programs. The most significant programs impacting our operations are those that require us to blend biofuels into the products we produce, and we are subject to such programs in most of the countries in which we operate. These countries set annual quotas for the percentage of biofuels that must be blended into the motor fuels consumed in these countries. As a producer of motor fuels from petroleum, we are obligated to blend biofuels into the products we produce at a rate that is at least equal to the applicable quota. To the degree we are unable to blend at the applicable rate, we must purchase biofuel credits (primarily RINs in the U.S.). We are exposed to the volatility in the market price of these credits, and we manage that risk by purchasing biofuel credits when prices are deemed favorable. The cost of meeting our obligations under these compliance programs was $91 million and $137 million for the three months ended June 30, 2014 and 2013, respectively, and $183 million and $267 million for the six months ended June 30, 2014 and 2013, respectively. These amounts are reflected in cost of sales.

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

As indicated in Note 13, we net fair value amounts recognized for multiple similar derivative contracts executed with the same counterparty under master netting arrangements, including cash collateral assets and obligations. The tables below, however, are presented on a gross asset and gross liability basis, which results in the reflection of certain assets in liability accounts and certain liabilities in asset accounts.
 
Balance Sheet
Location
 
June 30, 2014
 
 
Asset
Derivatives
 
Liability
Derivatives
Derivatives designated as
hedging instruments
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
Futures
Receivables, net
 
$
3

 
$
2

 
 
 
 
 
 
Derivatives not designated as
hedging instruments
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
Futures
Receivables, net
 
$
1,179

 
$
1,258

Swaps
Receivables, net
 
26

 
29

Swaps
Accrued expenses
 
2

 
3

Physical purchase contracts
Inventories
 

 
11

Foreign currency contracts
Accrued expenses
 

 
13

Total
 
 
$
1,207

 
$
1,314

Total derivatives
 
 
$
1,210

 
$
1,316




31




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

 
$
36

 
 
 
 
 
 
Derivatives not designated as
hedging instruments
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
Futures
Receivables, net
 
$
474

 
$
455

Swaps
Receivables, net
 
33

 
18

Swaps
Prepaid expenses and other
 
3

 

Swaps
Accrued expenses
 

 
5

Options
Receivables, net
 
2

 
2

Physical purchase contracts
Inventories
 

 
5

Foreign currency contracts
Accrued expenses
 

 
8

Total
 
 
$
512

 
$
493

Total derivatives
 
 
$
537

 
$
529

Market and Counterparty Risk
Our price risk management activities involve the receipt or payment of fixed price commitments into the future. These transactions give rise to market risk, which is the risk that future changes in market conditions may make an instrument less valuable. We closely monitor and manage our exposure to market risk on a daily basis in accordance with policies approved by our board of directors. Market risks are monitored by a risk control group to ensure compliance with our stated risk management policy. Concentrations of customers in the refining industry may impact our overall exposure to counterparty risk because these customers may be similarly affected by changes in economic or other conditions. In addition, financial services companies are the counterparties in certain of our price risk management activities, and such financial services companies may be adversely affected by periods of uncertainty and illiquidity in the credit and capital markets.
There were no material amounts due from counterparties in the refining or financial services industry as of June 30, 2014 or December 31, 2013. We do not require any collateral or other security to support derivative instruments into which we enter. We also do not have any derivative instruments that require us to maintain a minimum investment-grade credit rating.



32




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Derivatives in Fair Value
Hedging Relationships
 
Location of Gain (Loss)
Recognized in Income
on Derivatives
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
2014
 
2013
2014
 
2013
Commodity contracts:
 
 
 
 
 
 
 
 
 
 
Gain (loss) recognized in
income on derivatives
 
Cost of sales
 
$
5

 
$
(20
)
 
$
(26
)
 
$
(21
)
Gain (loss) recognized in
income on hedged item
 
Cost of sales
 
(5
)
 
22

 
25

 
22

Gain (loss) recognized in
income on derivatives
(ineffective portion)
 
Cost of sales
 

 
2

 
(1
)
 
1


For fair value hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness for the three and six months ended June 30, 2014 and 2013. There were no amounts recognized in income for hedged firm commitments that no longer qualified as fair value hedges during the three and six months ended June 30, 2014 and 2013.

Derivatives in Cash Flow
Hedging Relationships
 
Location of Gain (Loss)
Recognized in Income
on Derivatives
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2014
 
2013
 
2014
 
2013
Commodity contracts:
 
 
 
 
 
 
 
 
 
 
Gain (loss) recognized in
OCI on derivatives
(effective portion)
 
 
 
$
(3
)
 
$
(10
)
 
$
4

 
$
(9
)
Gain (loss) reclassified
from accumulated OCI
into income
(effective portion)
 
Cost of sales
 

 
(8
)
 
3

 
(5
)
Gain (loss) recognized in
income on derivatives
(ineffective portion)
 
Cost of sales
 
3

 
(2
)
 
(1
)
 
(3
)




33




VALERO ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For cash flow hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness for the three and six months ended June 30, 2014 and 2013. For the three and six months ended June 30, 2014, cash flow hedges primarily related to forward purchases of crude oil, with no cumulative after-tax gains or losses on cash flow hedges remaining in accumulated other comprehensive income. For the three and six months ended June 30, 2014 and 2013, there were no amounts reclassified from accumulated other comprehensive income into income as a result of the discontinuance of cash flow hedge accounting.

Derivatives Designated as
Economic Hedges
and Other
Derivative Instruments
 
Location of Gain (Loss)
Recognized in
Income on Derivatives
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
2014
 
2013
2014
 
2013
Commodity contracts
 
Cost of sales
 
$
(136
)
 
$
246

 
$
(132
)
 
$
281

Foreign currency contracts
 
Cost of sales
 
(32
)
 
11

 
(23
)
 
36

Total
 
 
 
$
(168
)
 
$
257

 
$
(155
)
 
$
317


Trading Derivatives
 
Location of Gain (Loss)
Recognized in
Income on Derivatives
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
2014
 
2013
2014
 
2013
Commodity contracts
 
Cost of sales
 
$
4

 
$
3

 
$
3

 
$
5

RINs fixed-price contracts
 
Cost of sales
 

 
(7
)
 

 
(20
)
Total
 
 
 
$
4

 
$
(4
)
 
$
3

 
$
(15
)




34


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

CAUTIONARY STATEMENT FOR THE PURPOSE OF SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This Form 10-Q, including without limitation our discussion below under the heading “OVERVIEW AND OUTLOOK,” includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “believe,” “expect,” “plan,” “intend,” “estimate,” “project,” “projection,” “predict,” “budget,” “forecast,” “goal,” “guidance,” “target,” “could,” “should,” “may,” and similar expressions.

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

future refining margins, including gasoline and distillate margins;
future ethanol margins;
expectations regarding feedstock costs, including crude oil differentials, and operating expenses;
anticipated levels of crude oil and refined product inventories;
our anticipated level of capital investments, including deferred refinery turnaround and catalyst costs and capital expenditures for environmental and other purposes, and the effect of those capital investments on our results of operations;
anticipated trends in the supply of and demand for crude oil and other feedstocks and refined products globally and in the regions where we operate;
expectations regarding environmental, tax, and other regulatory initiatives; and
the effect of general economic and other conditions on refining and ethanol industry fundamentals.

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

acts of terrorism aimed at either our facilities or other facilities that could impair our ability to produce or transport refined products or receive feedstocks;
political and economic conditions in nations that produce crude oil or consume refined products;
demand for, and supplies of, refined products such as gasoline, diesel fuel, jet fuel, petrochemicals, and ethanol;
demand for, and supplies of, crude oil and other feedstocks;
the ability of the members of the Organization of Petroleum Exporting Countries to agree on and to maintain crude oil price and production controls;
the level of consumer demand, including seasonal fluctuations;
refinery overcapacity or undercapacity;
our ability to successfully integrate any acquired businesses into our operations;
the actions taken by competitors, including both pricing and adjustments to refining capacity in response to market conditions;
the level of competitors’ imports into markets that we supply;
accidents, unscheduled shutdowns, or other catastrophes affecting our refineries, machinery, pipelines, equipment, and information systems, or those of our suppliers or customers;



35


changes in the cost or availability of transportation for feedstocks and refined products;
the price, availability, and acceptance of alternative fuels and alternative-fuel vehicles;
the levels of government subsidies for ethanol and other alternative fuels;
delay of, cancellation of, or failure to implement planned capital projects and realize the various assumptions and benefits projected for such projects or cost overruns in constructing such planned capital projects;
earthquakes, hurricanes, tornadoes, and irregular weather, which can unforeseeably affect the price or availability of natural gas, crude oil, grain and other feedstocks, and refined products and ethanol;
rulings, judgments, or settlements in litigation or other legal or regulatory matters, including unexpected environmental remediation costs, in excess of any reserves or insurance coverage;
legislative or regulatory action, including the introduction or enactment of legislation or rulemakings by governmental authorities, including tax and environmental regulations, such as those to be implemented under the California Global Warming Solutions Act (also known as AB 32) and the United States (U.S.) Environmental Protection Agency’s (EPA) regulation of greenhouse gases, which may adversely affect our business or operations;
changes in the credit ratings assigned to our debt securities and trade credit;
changes in currency exchange rates, including the value of the Canadian dollar, the pound sterling, and the euro relative to the U.S. dollar; and
overall economic conditions, including the stability and liquidity of financial markets.
Any one of these factors, or a combination of these factors, could materially affect our future results of operations and whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.

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




36


OVERVIEW AND OUTLOOK

Overview
For the second quarter of 2014, we reported net income attributable to Valero stockholders from continuing operations of $651 million, or $1.22 per share (assuming dilution), compared to $463 million, or $0.84 per share (assuming dilution), for the second quarter of 2013. The increase of $188 million was due primarily to the increase of $280 million in our operating income as outlined by business segment in the table below (in millions).
 
 
Three Months Ended June 30,
 
 
2014
 
2013
 
Change
Operating income (loss) by business segment:
 
 
 
 
 
 
Refining
 
$
1,079

 
$
918

 
$
161

Ethanol
 
187

 
95

 
92

Retail
 

 
39

 
(39
)
Corporate
 
(181
)
 
(247
)
 
66

Total
 
$
1,085

 
$
805

 
$
280


The $161 million increase in refining segment operating income in the second quarter of 2014 compared to the second quarter of 2013 was due primarily to higher refining throughput margin per barrel and higher throughput volumes in most of our regions, partially offset by higher energy costs and higher depreciation expense between the periods. Our ethanol segment operating income increased $92 million in the second quarter of 2014 compared to the second quarter of 2013 due to higher gross margin per gallon.
On May 1, 2013, we completed the separation of our retail business, creating an independent public company named CST Brands, Inc. (CST), and as a result, we no longer operate a retail business. Therefore, we did not have any retail segment operating results for the second quarter of 2014, resulting in the $39 million decrease in retail segment operating income in the second quarter of 2014 compared to the second quarter of 2013.
For the first six months of 2014, we reported net income attributable to Valero stockholders from continuing operations of $1.5 billion, or $2.77 per share (assuming dilution), compared to $1.1 billion, or $2.02 per share (assuming dilution), for the first six months of 2013. The increase of $366 million was due primarily to the increase of $573 million in our operating income as outlined by business segment in the table below (in millions).
 
 
Six Months Ended June 30,
 
 
2014
 
2013
 
Change
Operating income (loss) by business segment:
 
 
 
 
 
 
Refining
 
$
2,359

 
$
2,127

 
$
232

Ethanol
 
430

 
109

 
321

Retail
 

 
81

 
(81
)
Corporate
 
(353
)
 
(454
)
 
101

Total
 
$
2,436

 
$
1,863

 
$
573


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



37


months of 2014 compared to the first six months of 2013 due to higher gross margin per gallon, partially offset by higher energy costs.
As previously discussed, we no longer operate a retail business. Therefore, we did not have any retail segment operating results for the first six months of 2014, which resulted in the $81 million decrease in retail segment operating income in the first six months of 2014 compared to the first six months of 2013.
In May 2014, we decided to abandon our Aruba Refinery, except for the associated crude oil and refined products terminal assets that we continue to operate, as further described in Note 3 of Condensed Notes to Consolidated Financial Statements. As a result, the Aruba Refinery’s results of operations have been presented as discontinued operations for all periods presented under “RESULTS OF OPERATIONS.”
Additional analysis of the changes in the operating income of our business segments and other components of net income attributable to Valero stockholders is provided below under “RESULTS OF OPERATIONS.”
Outlook
Our refining segment benefits from processing sour crude oils (such as Mars and Maya crude oil) and light sweet crude oils (such as West Texas Intermediate and Louisiana Light Sweet crude oil) due to the favorable discounts between the prices of these types of crude oil and the price of Brent crude oil. Because the market for refined products generally tracks the price of Brent crude oil, which is a benchmark sweet crude oil, we benefit when we process crude oils that are priced at a discount to Brent crude oil. The discounts in the prices of certain light sweet crude oils and sour crude oils compared to the price of Brent crude oil in the second quarter of 2014 widened compared to the second quarter of 2013, which positively impacted our refining margins. Thus far in the third quarter of 2014, discounts on most crude oils have narrowed compared to the second quarter of 2014, and we expect these discounts to remain volatile. As the end of the summer driving season approaches, we expect gasoline margins to follow the normal seasonal trend and decline from current levels. Energy markets and margins are volatile, and we expect them to continue to be volatile in the near to mid-term.
Thus far in the third quarter of 2014, ethanol margins have widened slightly. However, we expect lower average ethanol margins for the remainder of 2014 as compared to the first six months of 2014 as ethanol production is expected to increase due to the favorable ethanol margin environment.

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




38


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

Financial Highlights (a)
(millions of dollars, except per share amounts)
 
Three Months Ended June 30,
 
2014
 
2013 (b)
 
Change
Operating revenues
$
34,914

 
$
34,034

 
$
880

Costs and expenses:
 
 
 
 
 
Cost of sales
32,167

 
31,523

 
644

Operating expenses:
 
 
 
 
 
Refining
967

 
909

 
58

Retail

 
57

 
(57
)
Ethanol
111

 
102

 
9

General and administrative expenses
170

 
233

 
(63
)
Depreciation and amortization expense:
 
 
 
 
 
Refining
391

 
369

 
22

Retail

 
11

 
(11
)
Ethanol
12

 
11

 
1

Corporate
11

 
14

 
(3
)
Total costs and expenses
33,829

 
33,229

 
600

Operating income
1,085

 
805

 
280

Other income, net
12

 
11

 
1

Interest and debt expense, net of capitalized interest
(98
)
 
(78
)
 
(20
)
Income from continuing operations before income tax expense
999

 
738

 
261

Income tax expense
343

 
276

 
67

Income from continuing operations
656

 
462

 
194

Income (loss) from discontinued operations
(63
)
 
3

 
(66
)
Net income
593

 
465

 
128

Less: Net income (loss) attributable to noncontrolling interests
5

 
(1
)
 
6

Net income attributable to Valero stockholders
$
588

 
$
466

 
$
122

 
 
 
 
 
 
Net income attributable to Valero stockholders:
 
 
 
 
 
Continuing operations
$
651

 
$
463

 
$
188

Discontinued operations
(63
)
 
3

 
(66
)
Total
$
588

 
$
466

 
$
122

 
 
 
 
 
 
Earnings per common share – assuming dilution:
 

 
 
 
 
Continuing operations
$
1.22

 
$
0.84

 
$
0.38

Discontinued operations
(0.12
)
 
0.01

 
(0.13
)
Total
$
1.10

 
$
0.85

 
$
0.25

________________
See note references on page 43.



39


Refining Operating Highlights (a)
(millions of dollars, except per barrel amounts)

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

 
$
918

 
$
161

 
 
 
 
 
 
Throughput margin per barrel (c)
$
9.84

 
$
9.26

 
$
0.58

Operating costs per barrel:
 
 
 
 
 
Operating expenses
3.90

 
3.83

 
0.07

Depreciation and amortization expense
1.58

 
1.56

 
0.02

Total operating costs per barrel
5.48

 
5.39

 
0.09

Operating income per barrel
$
4.36

 
$
3.87

 
$
0.49

 
 
 
 
 
 
Throughput volumes (thousand barrels per day):
 
 
 
 
 
Feedstocks:
 
 
 
 
 
Heavy sour crude oil
428

 
488

 
(60
)
Medium/light sour crude oil
472

 
463

 
9

Sweet crude oil
1,084

 
896

 
188

Residuals
235

 
315

 
(80
)
Other feedstocks
152

 
120

 
32

Total feedstocks
2,371

 
2,282

 
89

Blendstocks and other
350

 
324

 
26

Total throughput volumes
2,721

 
2,606

 
115

 
 
 
 
 
 
Yields (thousand barrels per day):
 
 
 
 
 
Gasolines and blendstocks
1,318

 
1,281

 
37

Distillates
1,034

 
910

 
124

Other products (d)
405

 
441

 
(36
)
Total yields
2,757

 
2,632

 
125

_______________
See note references on page 43.



40


Refining Operating Highlights by Region (e)
(millions of dollars, except per barrel amounts)
 
Three Months Ended June 30,
 
2014
 
2013
 
Change
U.S. Gulf Coast (a):
 
 
 
 
 
Operating income
$
660

 
$
411

 
$
249

Throughput volumes (thousand barrels per day)
1,567

 
1,530

 
37

 
 
 
 
 
 
Throughput margin per barrel (c)
$
10.03

 
$
8.12

 
$
1.91

Operating costs per barrel:
 
 
 
 
 
Operating expenses
3.82

 
3.66

 
0.16

Depreciation and amortization expense
1.58

 
1.51

 
0.07

Total operating costs per barrel
5.40

 
5.17

 
0.23

Operating income per barrel
$
4.63

 
$
2.95

 
$
1.68

 
 
 
 
 
 
U.S. Mid-Continent:
 
 
 
 
 
Operating income
$
250

 
$
343

 
$
(93
)
Throughput volumes (thousand barrels per day)
426

 
422

 
4

 
 
 
 
 
 
Throughput margin per barrel (c)
$
12.07

 
$
14.20

 
$
(2.13
)
Operating costs per barrel:
 
 
 
 
 
Operating expenses
3.91

 
3.69

 
0.22

Depreciation and amortization expense
1.70

 
1.59

 
0.11

Total operating costs per barrel
5.61

 
5.28

 
0.33

Operating income per barrel
$
6.46

 
$
8.92

 
$
(2.46
)
 
 
 
 
 
 
North Atlantic:
 
 
 
 
 
Operating income
$
145

 
$
70

 
$
75

Throughput volumes (thousand barrels per day)
462

 
370

 
92

 
 
 
 
 
 
Throughput margin per barrel (c)
$
7.78

 
$
7.18

 
$
0.60

Operating costs per barrel:
 
 
 
 
 
Operating expenses
3.20

 
3.90

 
(0.70
)
Depreciation and amortization expense
1.13

 
1.20

 
(0.07
)
Total operating costs per barrel
4.33

 
5.10

 
(0.77
)
Operating income per barrel
$
3.45

 
$
2.08

 
$
1.37

 
 
 
 
 
 
U.S. West Coast:
 
 
 
 
 
Operating income
$
24

 
$
94

 
$
(70
)
Throughput volumes (thousand barrels per day)
266

 
284

 
(18
)
 
 
 
 
 
 
Throughput margin per barrel (c)
$
8.66

 
$
10.81

 
$
(2.15
)
Operating costs per barrel:
 
 
 
 
 
Operating expenses
5.59

 
4.93

 
0.66

Depreciation and amortization expense
2.08

 
2.22

 
(0.14
)
Total operating costs per barrel
7.67

 
7.15

 
0.52

Operating income per barrel
$
0.99

 
$
3.66

 
$
(2.67
)
 
 
 
 
 
 
Total refining operating income
$
1,079

 
$
918

 
$
161

_______________
See note references on page 43.



41


Average Market Reference Prices and Differentials
(dollars per barrel, except as noted)

 
Three Months Ended June 30,
 
2014
 
2013
 
Change
Feedstocks:
 
 
 
 
 
Brent crude oil
$
109.74

 
$
103.36

 
$
6.38

Brent less West Texas Intermediate (WTI) crude oil
6.68

 
9.17

 
(2.49
)
Brent less Alaska North Slope (ANS) crude oil
0.51

 
(0.91
)
 
1.42

Brent less Louisiana Light Sweet (LLS) crude oil
3.41

 
(1.78
)
 
5.19

Brent less Mars crude oil
8.22

 
3.53

 
4.69

Brent less Maya crude oil
13.95

 
5.46

 
8.49

LLS crude oil
106.33

 
105.14

 
1.19

LLS less Mars crude oil
4.81

 
5.31

 
(0.50
)
LLS less Maya crude oil
10.54

 
7.24

 
3.30

WTI crude oil
103.06

 
94.19

 
8.87

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

 
4.00

 
0.56

 
 
 
 
 
 
Products:
 
 
 
 
 
U.S. Gulf Coast:
 
 
 
 
 
CBOB gasoline less Brent
7.33

 
7.51

 
(0.18
)
Ultra-low-sulfur diesel less Brent
12.81

 
16.79

 
(3.98
)
Propylene less Brent
(5.00
)
 
(6.76
)
 
1.76

CBOB gasoline less LLS
10.74

 
5.73

 
5.01

Ultra-low-sulfur diesel less LLS
16.22

 
15.01

 
1.21

Propylene less LLS
(1.59
)
 
(8.54
)
 
6.95

U.S. Mid-Continent:
 
 
 
 
 
CBOB gasoline less WTI (f)
16.00

 
26.11

 
(10.11
)
Ultra-low-sulfur diesel less WTI
20.99

 
29.30

 
(8.31
)
North Atlantic:
 
 
 
 
 
CBOB gasoline less Brent
11.69

 
10.89

 
0.80

Ultra-low-sulfur diesel less Brent
14.19

 
18.17

 
(3.98
)
U.S. West Coast:
 
 
 
 
 
CARBOB 87 gasoline less ANS
19.72

 
21.18

 
(1.46
)
CARB diesel less ANS
17.16

 
17.09

 
0.07

CARBOB 87 gasoline less WTI
25.89

 
31.26

 
(5.37
)
CARB diesel less WTI
23.33

 
27.17

 
(3.84
)
New York Harbor corn crush (dollars per gallon)
0.68

 
0.28

 
0.40

_______________
See note references on page 43.



42


Retail and Ethanol Operating Highlights
(millions of dollars, except per gallon amounts)

 
Three Months Ended June 30,
 
2014
 
2013
 
Change
Ethanol:
 
 
 
 
 
Operating income
$
187

 
$
95

 
$
92

Production (thousand gallons per day)
3,276

 
3,508

 
(232
)
 
 
 
 
 
 
Gross margin per gallon of production (c)
$
1.04

 
$
0.65

 
$
0.39

Operating costs per gallon of production:
 
 

 
 
Operating expenses
0.37

 
0.32

 
0.05

Depreciation and amortization expense
0.04

 
0.03

 
0.01

Total operating costs per gallon of production
0.41

 
0.35

 
0.06

Operating income per gallon of production
$
0.63

 
$
0.30

 
$
0.33

 
 
 
 
 
 
Retail:
 
 
 
 
 
Operating income
$

 
$
39

 
$
(39
)
_______________
See note references below.

The following notes relate to references on pages 39 through 43.
(a)
In May 2014, we decided to abandon our Aruba Refinery, except for the associated crude oil and refined products terminal assets that we continue to operate. This transaction is more fully described in Note 3 to Condensed Notes to Consolidated Financial Statements. As a result of our decision, the results attributable to the Aruba Refinery operations have been presented as discontinued operations and the operating highlights for the refining segment and the U.S. Gulf Coast region exclude the Aruba Refinery for all periods presented.
(b)
On May 1, 2013, we completed the separation of our retail business to CST. This transaction is more fully discussed in Note 4 of Condensed Notes to Consolidated Financial Statements. As a result and effective May 1, 2013, our results of operations no longer include those of CST, except for our share of CST’s results of operations associated with the equity interest in CST retained by us at that time, which is reflected in “other income, net” in the three months ended June 30, 2013.
(c)
Throughput margin per barrel represents operating revenues less cost of sales of our refining segment divided by throughput volumes. Gross margin per gallon of production represents operating revenues less cost of sales of our ethanol segment divided by production volumes.
(d)
Other products primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, sulfur, and asphalt.
(e)
The regions reflected herein contain the following refineries: the U.S. Gulf Coast region includes the Corpus Christi East, Corpus Christi West, Houston, Meraux, Port Arthur, St. Charles, Texas City, and Three Rivers Refineries; the U.S. Mid-Continent region includes the Ardmore, McKee, and Memphis Refineries; the North Atlantic region includes the Pembroke and Quebec City Refineries; and the U.S. West Coast region includes the Benicia and Wilmington Refineries.
(f)
U.S. Mid-Continent product specifications for gasoline changed on September 16, 2013 to CBOB gasoline. Therefore, average market reference prices for comparable products meeting the new specifications required in this region are provided for all periods presented.

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



43


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

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

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

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

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

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




44


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

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

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

Ethanol
Ethanol segment operating income was $187 million in the second quarter of 2014 compared to $95 million in the second quarter of 2013. The $92 million increase in operating income was due primarily to a $102 million increase in gross margin (a $0.39 per gallon increase), partially offset by a $9 million increase in operating expenses.
Ethanol segment gross margin per gallon increased to $1.04 per gallon in the second quarter of 2014 from $0.65 per gallon in the second quarter of 2013 due primarily to the following:

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

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

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

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




45


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

“Interest and debt expense, net of capitalized interest” for the second quarter of 2014 increased $20 million from the second quarter of 2013. This increase was due primarily to a $27 million decrease in capitalized interest due to completion of several large capital projects in the second quarter of 2013, including the new hydrocracker at our St. Charles Refinery, partially offset by a $6 million favorable impact from the decrease in average borrowings between the quarters.
Income tax expense increased $67 million from the second quarter of 2013 to the second quarter of 2014 due to higher income from continuing operations before income tax expense, partially offset by the impact of an increase in our U.S. manufacturing deduction during the second quarter of 2014 and income taxes related to the separation of CST in the second quarter of 2013 that did not recur.

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




46


Financial Highlights (a)
(millions of dollars, except per share amounts)

 
Six Months Ended June 30,
 
2014
 
2013 (b)
 
Change
Operating revenues
$
68,577

 
$
67,508

 
$
1,069

Costs and expenses:
 
 
 
 
 
Cost of sales
62,797

 
62,208

 
589

Operating expenses:
 
 
 
 
 
Refining
1,939

 
1,788

 
151

Retail

 
226

 
(226
)
Ethanol
240

 
179

 
61

General and administrative expenses
330

 
409

 
(79
)
Depreciation and amortization expense:
 
 
 
 
 
Refining
788

 
727

 
61

Retail

 
41

 
(41
)
Ethanol
24

 
22

 
2

Corporate
23

 
45

 
(22
)
Total costs and expenses
66,141

 
65,645

 
496

Operating income
2,436

 
1,863

 
573

Other income, net
27

 
25

 
2

Interest and debt expense, net of capitalized interest
(198
)
 
(161
)
 
(37
)
Income from continuing operations before income tax expense
2,265

 
1,727

 
538

Income tax expense
772

 
616

 
156

Income from continuing operations
1,493

 
1,111

 
382

Income (loss) from discontinued operations
(64
)
 
6

 
(70
)
Net income
1,429

 
1,117

 
312

Less: Net income (loss) attributable to noncontrolling interests
13

 
(3
)
 
16

Net income attributable to Valero stockholders
$
1,416

 
$
1,120

 
$
296

 
 
 
 
 
 
Net income attributable to Valero stockholders:
 
 
 
 
 
Continuing operations
$
1,480

 
$
1,114

 
$
366

Discontinued operations
(64
)
 
6

 
(70
)
Total
$
1,416

 
$
1,120

 
$
296

 
 
 
 
 
 
Earnings per common share – assuming dilution:
 
 
 
 
 
Continuing operations
$
2.77

 
$
2.02

 
$
0.75

Discontinued operations
(0.12
)
 
0.01

 
(0.13
)
Total
$
2.65

 
$
2.03

 
$
0.62

_______________
See note references on page 51.



47


Refining Operating Highlights (a)
(millions of dollars, except per barrel amounts)

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

 
$
2,127

 
$
232

 
 
 
 
 
 
Throughput margin per barrel (c)
$
10.36

 
$
9.92

 
$
0.44

Operating costs per barrel:
 
 
 
 
 
Operating expenses
3.95

 
3.83

 
0.12

Depreciation and amortization expense
1.60

 
1.55

 
0.05

Total operating costs per barrel
5.55

 
5.38

 
0.17

Operating income per barrel
$
4.81

 
$
4.54

 
$
0.27

 
 
 
 
 
 
Throughput volumes (thousand barrels per day):
 
 
 
 
 
Feedstocks:
 
 
 
 
 
Heavy sour crude oil
453

 
491

 
(38
)
Medium/light sour crude oil
491

 
441

 
50

Sweet crude oil
1,074

 
992

 
82

Residuals
219

 
270

 
(51
)
Other feedstocks
140

 
101

 
39

Total feedstocks
2,377

 
2,295

 
82

Blendstocks and other
334

 
291

 
43

Total throughput volumes
2,711

 
2,586

 
125

 
 
 
 
 
 
Yields (thousand barrels per day):
 
 
 
 
 
Gasolines and blendstocks
1,307

 
1,239

 
68

Distillates
1,029

 
910

 
119

Other products (d)
410

 
461

 
(51
)
Total yields
2,746

 
2,610

 
136

_______________
See note references on page 51.




48


Refining Operating Highlights by Region (e)
(millions of dollars, except per barrel amounts)
 
Six Months Ended June 30,
 
2014
 
2013
 
Change
U.S. Gulf Coast (a):
 
 
 
 
 
Operating income
$
1,543

 
$
999

 
$
544

Throughput volumes (thousand barrels per day)
1,576

 
1,476

 
100

 
 
 
 
 
 
Throughput margin per barrel (c)
$
10.75

 
$
9.02

 
$
1.73

Operating costs per barrel:
 
 
 

 
 
Operating expenses
3.72

 
3.72

 

Depreciation and amortization expense
1.62

 
1.56

 
0.06

Total operating costs per barrel
5.34

 
5.28

 
0.06

Operating income per barrel
$
5.41

 
$
3.74

 
$
1.67

 
 
 
 
 
 
U.S. Mid-Continent:
 
 
 
 
 
Operating income
$
480

 
$
820

 
$
(340
)
Throughput volumes (thousand barrels per day)
412

 
423

 
(11
)
 
 
 
 
 
 
Throughput margin per barrel (c)
$
12.33

 
$
15.80

 
$
(3.47
)
Operating costs per barrel:
 
 
 

 
 
Operating expenses
4.17

 
3.53

 
0.64

Depreciation and amortization expense
1.72

 
1.57

 
0.15

Total operating costs per barrel
5.89

 
5.10

 
0.79

Operating income per barrel
$
6.44

 
$
10.70

 
$
(4.26
)
 
 
 
 
 
 
North Atlantic:
 
 
 
 
 
Operating income
$
343

 
$
256

 
$
87

Throughput volumes (thousand barrels per day)
466

 
427

 
39

 
 
 
 
 
 
Throughput margin per barrel (c)
$
8.63

 
$
7.89

 
$
0.74

Operating costs per barrel:
 
 
 

 
 
Operating expenses
3.45

 
3.57

 
(0.12
)
Depreciation and amortization expense
1.11

 
1.01

 
0.10

Total operating costs per barrel
4.56

 
4.58

 
(0.02
)
Operating income per barrel
$
4.07

 
$
3.31

 
$
0.76

 
 
 
 
 
 
U.S. West Coast:
 
 
 
 
 
Operating income (loss)
$
(7
)
 
$
52

 
$
(59
)
Throughput volumes (thousand barrels per day)
257

 
260

 
(3
)
 
 
 
 
 
 
Throughput margin per barrel (c)
$
7.98

 
$
8.76

 
$
(0.78
)
Operating costs per barrel:
 
 
 

 
 
Operating expenses
5.95

 
5.27

 
0.68

Depreciation and amortization expense
2.18

 
2.38

 
(0.20
)
Total operating costs per barrel
8.13

 
7.65

 
0.48

Operating income (loss) per barrel
$
(0.15
)
 
$
1.11

 
$
(1.26
)
 
 
 
 
 
 
Total refining operating income
$
2,359

 
$
2,127

 
$
232

_______________
See note references on page 51.



49


Average Market Reference Prices and Differentials
(dollars per barrel, except as noted)

 
Six Months Ended June 30,
 
2014
 
2013
 
Change
Feedstocks:
 
 
 
 
 
Brent crude oil
$
108.82

 
$
108.00

 
$
0.82

Brent less WTI crude oil
7.93

 
13.75

 
(5.82
)
Brent less ANS crude oil
1.28

 
0.70

 
0.58

Brent less LLS crude oil
3.15

 
(2.13
)
 
5.28

Brent less Mars crude oil
7.32

 
2.93

 
4.39

Brent less Maya crude oil
16.20

 
7.57

 
8.63

LLS crude oil
105.67

 
110.13

 
(4.46
)
LLS less Mars crude oil
4.17

 
5.06

 
(0.89
)
LLS less Maya crude oil
13.05

 
9.70

 
3.35

WTI crude oil
100.89

 
94.25

 
6.64

 
 
 
 
 
 
Natural gas (dollars per million British thermal units)
4.90

 
3.72

 
1.18

 
 
 
 
 
 
Products:
 
 
 
 
 
U.S. Gulf Coast:
 
 
 
 
 
CBOB gasoline less Brent
4.56

 
6.11

 
(1.55
)
Ultra-low-sulfur diesel less Brent
13.99

 
16.88

 
(2.89
)
Propylene less Brent
(1.19
)
 
(0.14
)
 
(1.05
)
CBOB gasoline less LLS
7.71

 
3.98

 
3.73

Ultra-low-sulfur diesel less LLS
17.14

 
14.75

 
2.39

Propylene less LLS
1.96

 
(2.27
)
 
4.23

U.S. Mid-Continent:
 
 
 
 
 
CBOB gasoline less WTI (f)
14.55

 
24.97

 
(10.42
)
Ultra-low-sulfur diesel less WTI
23.43

 
32.39

 
(8.96
)
North Atlantic:
 
 
 
 
 
CBOB gasoline less Brent
8.54

 
10.12

 
(1.58
)
Ultra-low-sulfur diesel less Brent
18.40

 
18.44

 
(0.04
)
U.S. West Coast:
 
 
 
 
 
CARBOB 87 gasoline less ANS
14.96

 
17.64

 
(2.68
)
CARB diesel less ANS
17.30

 
19.23

 
(1.93
)
CARBOB 87 gasoline less WTI
21.61

 
30.69

 
(9.08
)
CARB diesel less WTI
23.95

 
32.28

 
(8.33
)
New York Harbor corn crush (dollars per gallon)
0.94

 
0.10

 
0.84

_______________
See note references on page 51.



50


Retail and Ethanol Operating Highlights
(millions of dollars, except per gallon amounts)

 
Six Months Ended June 30,
 
2014
 
2013
 
Change
Ethanol:
 
 
 
 
 
Operating income
$
430

 
$
109

 
$
321

Production (thousand gallons per day)
3,186

 
3,112

 
74

 
 
 
 
 
 
Gross margin per gallon of production (c)
$
1.20

 
$
0.55

 
$
0.65

Operating costs per gallon of production:

 

 
 
Operating expenses
0.41

 
0.32

 
0.09

Depreciation and amortization expense
0.04

 
0.04

 

Total operating costs per gallon of production
0.45

 
0.36

 
0.09

Operating income per gallon of production
$
0.75

 
$
0.19

 
$
0.56

 
 
 
 
 
 
Retail:
 
 
 
 
 
Operating income
$

 
$
81

 
$
(81
)
_______________
See note references below.

The following notes relate to references on pages 47 through 51.
(a)
In May 2014, we decided to abandon our Aruba Refinery, except for the associated crude oil and refined products terminal assets that we continue to operate. This transaction is more fully described in Note 3 to Condensed Notes to Consolidated Financial Statements. As a result of our decision, the results attributable to the Aruba Refinery operations have been presented as discontinued operations and the operating highlights for the refining segment and the U.S. Gulf Coast region exclude the Aruba Refinery for all periods presented.
(b)
On May 1, 2013, we completed the separation of our retail business to CST. This transaction is more fully discussed in Note 4 of Condensed Notes to Consolidated Financial Statements. As a result and effective May 1, 2013, our results of operations no longer include those of CST, except for our share of CST’s results of operations associated with the equity interest in CST retained by us at that time, which is reflected in “other income, net” in the six months ended June 30, 2013.
(c)
Throughput margin per barrel represents operating revenues less cost of sales of our refining segment divided by throughput volumes. Gross margin per gallon of production represents operating revenues less cost of sales of our ethanol segment divided by production volumes.
(d)
Other products primarily include petrochemicals, gas oils, No. 6 fuel oil, petroleum coke, sulfur, and asphalt.
(e)
The regions reflected herein contain the following refineries: the U.S. Gulf Coast region includes the Corpus Christi East, Corpus Christi West, Houston, Meraux, Port Arthur, St. Charles, Texas City, and Three Rivers Refineries; the U.S. Mid-Continent region includes the Ardmore, McKee, and Memphis Refineries; the North Atlantic region includes the Pembroke and Quebec City Refineries; and the U.S. West Coast region includes the Benicia and Wilmington Refineries.
(f)
U.S. Mid-Continent product specifications for gasoline changed on September 16, 2013 to CBOB gasoline. Therefore, average market reference prices for comparable products meeting the new specifications required in this region are provided for all periods presented.

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



51


to our refining segment operations. In addition, operating income increased $573 million in the first six months of 2014 compared to the first six months of 2013 due primarily to a $232 million increase in refining segment operating income, a $321 million increase in ethanol segment operating income, and a $79 million decrease in general and administrative expenses, partially offset by a $81 million decrease in retail segment operating income. The reasons for these changes in the operating results of our segments and general and administrative expenses, as well as other items that affected our income, are discussed below.

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

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

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

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

Lower costs of biofuel credits - As more fully described in Note 14 of Condensed Notes to Consolidated Financial Statements, we purchase biofuel credits in order to meet our biofuel blending obligations under various government and regulatory compliance programs, and the cost of these credits (primarily RINs in the U.S.) decreased by $84 million from $267 million for the first six months of 2013 to $183 million in the first six months of 2014. This decrease was due primarily to a reduction in the market price of RINs between the two periods.



52


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

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

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

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

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

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

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

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

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



53


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

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

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

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

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

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




54


LIQUIDITY AND CAPITAL RESOURCES

Cash Flows for the Six Months Ended June 30, 2014 and 2013
Net cash provided by operating activities for the first six months of 2014 was $1.4 billion compared to $2.8 billion for the first six months of 2013. The decrease in net cash provided by operating activities was due primarily to the impact of an increase in accounts payable in the first six months of 2013 and a decrease in accounts payable in the first six months of 2014 resulting from a difference in the timing of the purchases of and payments for crude oil between the two periods. The changes in cash provided by or used in working capital during the first six months of 2014 and 2013 are shown in Note 12 of Condensed Notes to Consolidated Financial Statements.

The net cash provided by operating activities during the first six months of 2014, along with $812 million from available cash on hand, was used mainly to:
fund $1.3 billion of capital expenditures and deferred turnaround and catalyst costs;
make a scheduled long-term note repayment of $200 million;
purchase common stock for treasury of $455 million; and
pay common stock dividends of $266 million.

The net cash provided by operating activities during the first six months of 2013 combined with $735 million of net cash received in connection with the separation of our retail business (consisting of $550 million of proceeds on short-term debt, a $500 million cash distribution from CST less $315 million of cash retained by CST) were used mainly to:
fund $1.7 billion of capital expenditures and deferred turnaround and catalyst costs;
make scheduled long-term note repayments of $480 million;
purchase common stock for treasury of $560 million;
pay common stock dividends of $220 million; and
increase available cash on hand by $675 million.
Capital Investments
For 2014, we expect to incur approximately $3.0 billion for capital investments of which approximately $700 million is for deferred turnaround and catalyst costs. The capital expenditure estimate excludes expenditures related to strategic business acquisitions. We continuously evaluate our capital budget and make changes as conditions warrant.

Contractual Obligations
As of June 30, 2014, our contractual obligations included debt, capital lease obligations, operating leases, purchase obligations, and other long-term liabilities. There were no material changes outside the ordinary course of business with respect to these contractual obligations during the six months ended June 30, 2014.

As of June 30, 2014, we had an accounts receivable sales facility with a group of third-party entities and financial institutions to sell eligible trade receivables on a revolving basis up to $1.5 billion.




55


Our debt and financing agreements do not have rating agency triggers that would automatically require us to post additional collateral. However, in the event of certain downgrades of our senior unsecured debt by the ratings agencies, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. All of our ratings on our senior unsecured debt are at or above investment grade level as follows:
Rating Agency
 
Rating
Moody’s Investors Service
 
Baa2 (stable outlook)
Standard & Poor’s Ratings Services
 
BBB (stable outlook)
Fitch Ratings
 
BBB (stable outlook)
We cannot provide assurance that these ratings will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell, or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction below investment grade or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing and the cost of such financings.
Other Commercial Commitments
As of June 30, 2014, we had outstanding letters of credit under our committed lines of credit as follows (in millions):
 
 
Borrowing
Capacity
 
Expiration
 
Outstanding
Letters of Credit
Letter of credit facilities
 
$
550

 
June 2015
 
$

Revolving credit facility
 
$
3,000

 
November 2018
 
$
59

Valero Energy Partners LP Revolver
 
$
300

 
December 2018
 
$

Canadian revolving credit facility
 
C$
50

 
November 2014
 
C$
10


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

Other Matters Impacting Liquidity and Capital Resources
Pension Plan Funding
We plan to contribute approximately $38 million to our pension plans and $19 million to our postretirement plans during 2014.

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

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



56


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

Tax Matters
During the first six months of 2014, we paid approximately $400 million in tax payments that related to 2013 and that were recorded in income taxes payable as of December 31, 2013. In addition, we currently believe the cash we will pay for income taxes for 2014 will exceed amounts that we paid in 2013 and that such amounts may exceed the total income tax expense that will be reflected on our statement of income. This belief is based primarily on a decrease in deductions that we expect to claim on our U.S. federal income tax return for depreciation on our property, plant, and equipment. In prior years, the U.S. federal government enacted certain legislation that provided for the deduction of depreciation on an accelerated basis on newly built equipment as a means of encouraging capital investment by businesses. This legislation, however, generally did not extend beyond 2013. Although we expect the amount of cash required to pay our 2014 income taxes to increase compared to recent years, we believe that we will generate sufficient cash from operations and have sufficient cash on hand to make our tax payments as they become due.
The Internal Revenue Service (IRS) has ongoing tax audits related to our U.S. federal tax returns from 2002 through 2011 and we have received Revenue Agent Reports (RARs) in connection with the audits for tax years 2002 through 2009. We are vigorously contesting certain tax positions and assertions included in the RARs and we have made significant progress in resolving certain of these matters with the IRS. During the six months ended June 30, 2014, we settled the audit related to the 2004 and 2005 tax years for a group of our subsidiaries consistent with the recorded amount of uncertain tax position liabilities associated with that audit. In addition, we expect to settle our audits for tax years 2002 through 2007 within the next 12 months and we believe they will be settled for amounts that do not exceed the recorded amounts of uncertain tax position liabilities associated with those audits. As a result, we have classified a portion of our uncertain tax position liabilities as a current liability. As of June 30, 2014, the total amount of uncertain tax position liabilities, including related penalties and interest, was $437 million, with $240 million reflected as a current liability in income taxes payable and $197 million reflected in other long-term liabilities. Total uncertain tax position liabilities did not change significantly during the six months ended June 30, 2014. Should we ultimately settle for amounts consistent with our estimates, we believe that we will have sufficient cash on hand at that time to make such payments.
Cash Held by Our International Subsidiaries
We operate in countries outside the U.S. through subsidiaries incorporated in these countries, and the earnings of these subsidiaries are taxed by the countries in which they are incorporated. We intend to reinvest these earnings indefinitely in our international operations even though we are not restricted from repatriating such earnings to the U.S. in the form of cash dividends. Should we decide to repatriate such earnings, we would incur and pay taxes on the amounts repatriated. In addition, such repatriation could cause us to record deferred tax expense that could significantly impact our results of operations. We believe, however, that a substantial portion of our international cash can be returned to the U.S. without significant tax consequences through means other than a repatriation of earnings. As of June 30, 2014, $856 million of our cash and temporary cash investments was held by our international subsidiaries.

Concentration of Customers
Our refining and marketing operations have a concentration of customers in the refining industry and customers who are refined product wholesalers and retailers. These concentrations of customers may impact our overall exposure to credit risk, either positively or negatively, in that these customers may be similarly affected by changes in economic or other conditions. However, we believe that our portfolio of accounts



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

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

CRITICAL ACCOUNTING POLICIES

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

Item 3.
Quantitative and Qualitative Disclosures About Market Risk

COMMODITY PRICE RISK

We are exposed to market risks related to the volatility in the price of crude oil, refined products (primarily gasoline and distillate), grain (primarily corn), and natural gas used in our operations. To reduce the impact of price volatility on our results of operations and cash flows, we use commodity derivative instruments, including swaps, futures, and options to hedge:
inventories and firm commitments to purchase inventories generally for amounts by which our current year inventory levels (determined on a last-in, first-out (LIFO) basis) differ from our previous year-end LIFO inventory levels and
forecasted feedstock and refined product purchases, refined product sales, natural gas purchases, and corn purchases to lock in the price of those forecasted transactions at existing market prices that we deem favorable.

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

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




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The following sensitivity analysis includes all positions at the end of the reporting period with which we have market risk (in millions):
 
Derivative Instruments Held For
 
Non-Trading
Purposes
 
Trading
Purposes
June 30, 2014:
 
 
 
Gain (loss) in fair value resulting from:
 
 
 
10% increase in underlying commodity prices
$
(196
)
 
$
1

10% decrease in underlying commodity prices
196

 
(6
)
 
 
 
 
December 31, 2013:
 
 
 
Gain (loss) in fair value resulting from:
 
 
 
10% increase in underlying commodity prices
(91
)
 
3

10% decrease in underlying commodity prices
91

 
(2
)

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

COMPLIANCE PROGRAM PRICE RISK

We are exposed to market risk related to the volatility in the price of biofuel credits needed to comply with various governmental and regulatory programs. To manage this risk, we enter into contracts to purchase these credits when prices are deemed favorable. Some of these contracts are derivative instruments; however, we elect the normal purchase exception and do not record these contracts at their fair values. As of June 30, 2014, there was no gain or loss in the fair value of derivative instruments that would result from a 10 percent increase or decrease in the underlying price of the contracts. See Note 14 of Condensed Notes to Consolidated Financial Statements for a discussion about these compliance programs.




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INTEREST RATE RISK

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

 
June 30, 2014
 
Expected Maturity Dates
 
 
 
 
 
2014
 
2015
 
2016
 
2017
 
2018
 
There-
after
 
Total
 
Fair
Value
Debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed rate
$

 
$
475

 
$

 
$
950

 
$

 
$
4,824

 
$
6,249

 
$
7,740

Average interest rate
%
 
5.2
%
 
%
 
6.4
%
 
%
 
7.3
%
 
7.0
%
 
 
Floating rate
$
100

 
$
22

 
$

 
$

 
$

 
$

 
$
122

 
$
122

Average interest rate
0.8
%
 
6.1
%
 
%
 
%
 
%
 
%
 
1.8
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
 
Expected Maturity Dates
 
 
 
 
 
2014
 
2015
 
2016
 
2017
 
2018
 
There-
after
 
Total
 
Fair
Value
Debt:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed rate
$
200

 
$
475

 
$

 
$
950

 
$

 
$
4,824

 
$
6,449

 
$
7,559

Average interest rate
4.8
%
 
5.2
%
 
%
 
6.4
%
 
%
 
7.3
%
 
6.9
%
 
 
Floating rate
$
100

 
$

 
$

 
$

 
$

 
$

 
$
100

 
$
100

Average interest rate
0.9
%
 
%
 
%
 
%
 
%
 
%
 
0.9
%
 
 
FOREIGN CURRENCY RISK
As of June 30, 2014, we had commitments to purchase $692 million of U.S. dollars. Our market risk was minimal on these contracts, as the majority of them matured on or before July 31, 2014, resulting in an immaterial gain in the third quarter of 2014.

Item 4. Controls and Procedures
(a)
Evaluation of disclosure controls and procedures.
Our management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of June 30, 2014.
(b)
Changes in internal control over financial reporting.
There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.




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PART II – OTHER INFORMATION

Item 1.
Legal Proceedings
The information below describes new proceedings or material developments in proceedings that we previously reported in our annual report on Form 10-K for the year ended December 31, 2013.
Litigation
We hereby incorporate by reference into this Item our disclosures made in Part I, Item 1 of this Report included in Note 7 of Condensed Notes to Consolidated Financial Statements under the caption “Litigation Matters.”

Environmental Enforcement Matters
While it is not possible to predict the outcome of the following environmental proceedings, if any one or more of them were decided against us, we believe that there would be no material effect on our financial position, results of operations, or liquidity. We are reporting these proceedings to comply with SEC regulations, which require us to disclose certain information about proceedings arising under federal, state, or local provisions regulating the discharge of materials in the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $100,000 or more.

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

Item 1A. Risk Factors
There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2013.




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Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
(a)
Unregistered Sales of Equity Securities. Not applicable.
(b)
Use of Proceeds. Not applicable.
(c)
Issuer Purchases of Equity Securities. The following table discloses purchases of shares of our common stock made by us or on our behalf for the periods shown below.
Period
Total
Number of
Shares
Purchased
Average
Price
Paid per
Share
Total Number of
Shares Not
Purchased as Part
of Publicly
Announced Plans
or Programs (a)
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans
or Programs
Approximate Dollar
Value of Shares that
May Yet Be Purchased
Under the Plans
or Programs (b)
April 2014
3,821

$
54.41

3,821


$2.4 billion
May 2014
3,726,984

$
57.12

1,006,310

2,720,674

$2.3 billion
June 2014
300,034

$
52.16

34

300,000

$2.3 billion
Total
4,030,839

$
56.74

1,010,165

3,020,674

$2.3 billion
(a)
The shares reported in this column represent purchases settled during the three months ended June 30, 2014 relating to (a) our purchases of shares in open-market transactions to meet our obligations under employee stock compensation plans, and (b) our purchases of shares from our employees and non-employee directors in connection with the exercise of stock options, the vesting of restricted stock, and other stock compensation transactions in accordance with the terms of our stock-based compensation plans.
(b)
On February 28, 2008, we announced that our board of directors approved a $3 billion common stock purchase program. This $3 billion program has no expiration date.

Item 6. Exhibits
Exhibit
No.
Description
 
 
12.01
Statements of Computations of Ratios of Earnings to Fixed Charges.
 
 
31.01
Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal executive officer.
 
 
31.02
Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal financial officer.
 
 
32.01
Section 1350 Certifications (as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).
 
 
101
Interactive Data Files



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

 
 
 
 
 
 
VALERO ENERGY CORPORATION
(Registrant)
 
 
By:
/s/ Michael S. Ciskowski
 
 
Michael S. Ciskowski
 
 
Executive Vice President and
 
 
Chief Financial Officer
 
 
(Duly Authorized Officer and Principal
 
 
Financial and Accounting Officer)
Date: August 7, 2014



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