10-Q 1 vloform10-qx9302013.htm 10-Q
Table of Contents

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 September 30, 2013
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 October 31, 2013 was 539,562,259.

VALERO ENERGY CORPORATION AND SUBSIDIARIES
TABLE OF CONTENTS

| Page
PART I – FINANCIAL INFORMATION |
Item 1. Financial Statements |
Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012 | 1
Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2013 and 2012 | 2
Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2013 and 2012 | 3
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012 | 4
Condensed Notes to Consolidated Financial Statements | 5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 36
Item 3. Quantitative and Qualitative Disclosures About Market Risk | 61
Item 4. Controls and Procedures | 63
PART II – OTHER INFORMATION |
Item 1. Legal Proceedings | 63
Item 1A. Risk Factors | 64
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 64
Item 6. Exhibits | 65
SIGNATURE | 66

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PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Par Value)

| September 30, 2013 |  | December 31, 2012
| (Unaudited) |  |
ASSETS |  |  |
Current assets: |  |  |
Cash and temporary cash investments | $ | 1,908 |  |  | $ | 1,723 |
Receivables, net | 9,126 |  |  | 8,167 |
Inventories | 7,063 |  |  | 5,973 |
Income taxes receivable | 108 |  |  | 169 |
Deferred income taxes | 257 |  |  | 274 |
Prepaid expenses and other | 131 |  |  | 154 |
Total current assets | 18,593 |  |  | 16,460 |
Property, plant and equipment, at cost | 33,652 |  |  | 34,132 |
Accumulated depreciation | (8,010 | ) |  | (7,832 | )
Property, plant and equipment, net | 25,642 |  |  | 26,300 |
Intangible assets, net | 160 |  |  | 213 |
Deferred charges and other assets, net | 1,898 |  |  | 1,504 |
Total assets | $ | 46,293 |  |  | $ | 44,477 |
LIABILITIES AND EQUITY |  |  |
Current liabilities: |  |  |
Current portion of debt and capital lease obligations | $ | 303 |  |  | $ | 586 |
Accounts payable | 10,998 |  |  | 9,348 |
Accrued expenses | 598 |  |  | 590 |
Taxes other than income taxes | 1,287 |  |  | 1,026 |
Income taxes payable | 96 |  |  | 1 |
Deferred income taxes | 386 |  |  | 378 |
Total current liabilities | 13,668 |  |  | 11,929 |
Debt and capital lease obligations, less current portion | 6,261 |  |  | 6,463 |
Deferred income taxes | 6,312 |  |  | 5,860 |
Other long-term liabilities | 1,665 |  |  | 2,130 |
Commitments and contingencies |  |  |
Equity: |  |  |
Valero Energy Corporation stockholders’ equity: |  |  |
Common stock, $0.01 par value; 1,200,000,000 shares authorized; 673,501,593 and 673,501,593 shares issued | 7 |  |  | 7 |
Additional paid-in capital | 7,232 |  |  | 7,322 |
Treasury stock, at cost; 131,876,124 and 121,406,520 common shares | (6,856 | ) |  | (6,437 | )
Retained earnings | 17,804 |  |  | 17,032 |
Accumulated other comprehensive income | 83 |  |  | 108 |
Total Valero Energy Corporation stockholders’ equity | 18,270 |  |  | 18,032 |
Noncontrolling interests | 117 |  |  | 63 |
Total equity | 18,387 |  |  | 18,095 |
Total liabilities and equity | $ | 46,293 |  |  | $ | 44,477 |

See Condensed Notes to Consolidated Financial Statements.
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars, Except Per Share Amounts)
(Unaudited)

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2013 |  | 2012 |  | 2013 |  | 2012
Operating revenues | $ | 36,137 |  |  | $ | 34,726 |  |  | $ | 103,645 |  |  | $ | 104,555 |
Costs and expenses: |  |  |  |  |  |  |
Cost of sales | 33,931 |  |  | 31,312 |  |  | 96,139 |  |  | 95,968 |
Operating expenses: |  |  |  |  |  |  |
Refining | 954 |  |  | 930 |  |  | 2,736 |  |  | 2,762 |
Retail | — |  |  | 178 |  |  | 226 |  |  | 514 |
Ethanol | 102 |  |  | 76 |  |  | 281 |  |  | 248 |
General and administrative expenses | 170 |  |  | 174 |  |  | 579 |  |  | 509 |
Depreciation and amortization expense | 448 |  |  | 402 |  |  | 1,283 |  |  | 1,172 |
Asset impairment losses | — |  |  | 345 |  |  | — |  |  | 956 |
Total costs and expenses | 35,605 |  |  | 33,417 |  |  | 101,244 |  |  | 102,129 |
Operating income | 532 |  |  | 1,309 |  |  | 2,401 |  |  | 2,426 |
Other income (expense), net | 17 |  |  | (2 | ) |  | 42 |  |  | (1 | )
Interest and debt expense, net of capitalized interest | (102 | ) |  | (70 | ) |  | (263 | ) |  | (243 | )
Income before income tax expense | 447 |  |  | 1,237 |  |  | 2,180 |  |  | 2,182 |
Income tax expense | 123 |  |  | 564 |  |  | 739 |  |  | 1,111 |
Net income | 324 |  |  | 673 |  |  | 1,441 |  |  | 1,071 |
Less: Net income (loss) attributable to noncontrolling interests | 12 |  |  | (1 | ) |  | 9 |  |  | (2 | )
Net income attributable to Valero Energy Corporation stockholders | $ | 312 |  |  | $ | 674 |  |  | $ | 1,432 |  |  | $ | 1,073 |
Earnings per common share | $ | 0.58 |  |  | $ | 1.22 |  |  | $ | 2.62 |  |  | $ | 1.94 |
Weighted-average common shares outstanding (in millions) | 540 |  |  | 549 |  |  | 544 |  |  | 550 |
Earnings per common share – assuming dilution | $ | 0.57 |  |  | $ | 1.21 |  |  | $ | 2.61 |  |  | $ | 1.93 |
Weighted-average common shares outstanding – assuming dilution (in millions) | 545 |  |  | 556 |  |  | 549 |  |  | 556 |
Dividends per common share | $ | 0.225 |  |  | $ | 0.175 |  |  | $ | 0.625 |  |  | $ | 0.475 |

See Condensed Notes to Consolidated Financial Statements.
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of Dollars)
(Unaudited)

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2013 |  | 2012 |  | 2013 |  | 2012
Net income | $ | 324 |  |  | $ | 673 |  |  | $ | 1,441 |  |  | $ | 1,071 |
Other comprehensive income (loss): |  |  |  |  |  |  |
Foreign currency translation adjustment | 181 |  |  | 143 |  |  | (87 | ) |  | 175 |
Pension and other postretirement benefits: |  |  |  |  |  |  |
Gain arising during the period related to remeasurement due to plan amendments | — |  |  | — |  |  | 328 |  |  | — |
(Gain) loss reclassified into income related to: |  |  |  |  |  |  |
Net actuarial loss | 14 |  |  | 8 |  |  | 43 |  |  | 25 |
Prior service credit | (9 | ) |  | (5 | ) |  | (24 | ) |  | (15 | )
Net gain on pension and other postretirement benefits | 5 |  |  | 3 |  |  | 347 |  |  | 10 |
Derivative instruments designated and qualifying as cash flow hedges: |  |  |  |  |  |  |
Net gain (loss) arising during the period | 3 |  |  | 27 |  |  | (6 | ) |  | 43 |
Net gain reclassified into income | (6 | ) |  | (45 | ) |  | (1 | ) |  | (81 | )
Net loss on cash flow hedges | (3 | ) |  | (18 | ) |  | (7 | ) |  | (38 | )
Other comprehensive income, before income tax expense (benefit) | 183 |  |  | 128 |  |  | 253 |  |  | 147 |
Income tax expense (benefit) related to items of other comprehensive income | 1 |  |  | (5 | ) |  | 119 |  |  | (9 | )
Other comprehensive income | 182 |  |  | 133 |  |  | 134 |  |  | 156 |
Comprehensive income | 506 |  |  | 806 |  |  | 1,575 |  |  | 1,227 |
Less: Comprehensive income (loss) attributable to noncontrolling interests | 12 |  |  | (1 | ) |  | 9 |  |  | (2 | )
Comprehensive income attributable to Valero Energy Corporation stockholders | $ | 494 |  |  | $ | 807 |  |  | $ | 1,566 |  |  | $ | 1,229 |

See Condensed Notes to Consolidated Financial Statements.
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)

| Nine Months Ended September 30,
| 2013 |  | 2012
Cash flows from operating activities: |  |  |
Net income | $ | 1,441 |  |  | $ | 1,071 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |
Depreciation and amortization expense | 1,283 |  |  | 1,172 |
Asset impairment losses | — |  |  | 956 |
Noncash interest expense and other income, net | (7 | ) |  | 18 |
Stock-based compensation expense | 31 |  |  | 29 |
Deferred income tax expense | 488 |  |  | 576 |
Changes in current assets and current liabilities | (231 | ) |  | 1,191 |
Changes in deferred charges and credits and other operating activities, net | 30 |  |  | (66 | )
Net cash provided by operating activities | 3,035 |  |  | 4,947 |
Cash flows from investing activities: |  |  |
Capital expenditures | (1,690 | ) |  | (2,129 | )
Deferred turnaround and catalyst costs | (527 | ) |  | (339 | )
Proceeds from the sale of the Paulsboro Refinery | — |  |  | 160 |
Minor acquisitions | — |  |  | (77 | )
Other investing activities, net | (56 | ) |  | (28 | )
Net cash used in investing activities | (2,273 | ) |  | (2,413 | )
Cash flows from financing activities: |  |  |
Non-bank debt: |  |  |
Borrowings | — |  |  | 300 |
Repayments | (480 | ) |  | (862 | )
Bank credit agreements: |  |  |
Borrowings | — |  |  | 1,100 |
Repayments | — |  |  | (1,100 | )
Accounts receivable sales program: |  |  |
Proceeds from the sale of receivables | — |  |  | 1,500 |
Repayments | — |  |  | (1,650 | )
Purchase of common stock for treasury | (589 | ) |  | (148 | )
Proceeds from the exercise of stock options | 46 |  |  | 36 |
Common stock dividends | (342 | ) |  | (263 | )
Contributions from noncontrolling interests | 45 |  |  | 34 |
Separation of retail business: |  |  |
Proceeds from short-term debt | 550 |  |  | — |
Cash distributed to Valero by CST Brands, Inc. | 500 |  |  | — |
Cash held and retained by CST Brands, Inc. upon separation | (315 | ) |  | — |
Other financing activities, net | 27 |  |  | 8 |
Net cash used in financing activities | (558 | ) |  | (1,045 | )
Effect of foreign exchange rate changes on cash | (19 | ) |  | 36 |
Net increase in cash and temporary cash investments | 185 |  |  | 1,525 |
Cash and temporary cash investments at beginning of period | 1,723 |  |  | 1,024 |
Cash and temporary cash investments at end of period | $ | 1,908 |  |  | $ | 2,549 |

See Condensed Notes to Consolidated Financial Statements.
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. | BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation
As used in this report, the terms “Valero,” “we,” “us,” or “our” may refer to Valero Energy Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole.
These unaudited financial statements have been prepared in accordance with United States (U.S.) generally accepted accounting principles (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature unless disclosed otherwise. Financial information for the three and nine months ended September 30, 2013 and 2012 included in these Condensed Notes to Consolidated Financial Statements is derived from our unaudited financial statements. Operating results for the three and nine months ended September 30, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013.
The balance sheet as of December 31, 2012 has been derived from our audited financial statements as of that date. For further information, refer to our financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2012.
Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. On an ongoing basis, we review our estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.
Comprehensive Income
In February 2013, the provisions of Accounting Standards Codification (ASC) Topic 220, “Comprehensive Income,” were amended to require an entity to disclose information about the amounts reclassified out of accumulated other comprehensive income and into net income. An entity is required to present information on the face of the statement of income or in the notes to the financial statements about the effects on net income from significant amounts reclassified out of accumulated other comprehensive income if those amounts were required to be reclassified into net income in their entirety in the same reporting period they were initially charged to other comprehensive income. For other significant amounts that were not required to be reclassified into net income in their entirety in the same reporting period they were initially charged to other comprehensive income, a cross-reference is required in the notes to the financial statements to the disclosures that provide additional details about those amounts. These provisions were effective for interim and annual reporting periods beginning after December 15, 2012. The adoption of this guidance effective January 1, 2013 did not affect our financial position or results of operations, but resulted in additional disclosures, which are included in Note 7.
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Balance Sheet Offsetting Arrangements
In December 2011, the provisions of ASC Topic 210, “Balance Sheet,” were amended to require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of these arrangements on its financial position. In January 2013, the provisions of ASC Topic 210 were further amended to clarify that the scope of the previous amendment only applies to derivative instruments, including bifurcated derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either eligible for offset in the balance sheet or are subject to an agreement similar to a master netting agreement. The guidance requires entities to disclose both gross information and net information about assets and liabilities within the scope of the amendment. These provisions were effective for interim and annual reporting periods beginning on or after January 1, 2013. The adoption of this guidance effective January 1, 2013 did not affect our financial position or results of operations, but resulted in additional disclosures, which are included in Note 12.
Other
The statement of cash flows for the nine months ended September 30, 2012, which was included in our Form 10‑Q for the quarterly period ended September 30, 2012, reflected an incorrect classification of $160 million in proceeds on a note receivable related to the sale of our Paulsboro Refinery in December 2010. We previously reflected such proceeds as a component of cash flows from operating activities rather than as a component of cash flows from investing activities. The statement of cash flows for the nine months ended September 30, 2012 included in this Form 10-Q for the quarterly period ended September 30, 2013 has been corrected to properly reflect the classification of those proceeds.
New Accounting Pronouncement
In July 2013, the provisions of ASC Topic 740, “Income Taxes,” were amended to provide specific guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists at the reporting date. The amendment requires entities to present an unrecognized tax benefit as a reduction to the deferred tax asset generated by the net operating loss carryforward, similar tax loss, or tax credit carryforward, if such items are available to be used to offset the unrecognized tax benefit. These provisions are effective for interim and annual reporting periods beginning after December 15, 2013 and should be applied prospectively to all unrecognized tax benefits that exist at the effective date, with retrospective application permitted. The adoption of this guidance effective January 1, 2014 will not affect our financial position or results of operations, nor will it require any additional disclosures, but may result in a change in presentation to our consolidated balance sheets.
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. | SEPARATION OF RETAIL BUSINESS

On May 1, 2013, we completed the separation of our retail business by creating an independent public company named CST Brands, Inc. (CST) and distributing 80 percent of the outstanding shares of CST common stock to our stockholders on May 1, 2013. Each Valero stockholder received one share of CST common stock for every nine shares of Valero common stock held at the close of business on the record date of April 19, 2013. Fractional shares of CST common stock were not distributed, but instead were aggregated and sold in the open market at prevailing rates with net cash proceeds then distributed pro rata to each Valero stockholder who was entitled to receive fractional shares.
In connection with the separation, we received an aggregate of $1.05 billion in cash, consisting of $550 million from the issuance of short-term debt to a third-party financial institution on April 16, 2013 and $500 million distributed to us by CST on May 1, 2013. The cash distributed to us by CST was borrowed by CST on May 1, 2013 under its senior secured credit facility. See Note 5 for further discussion of that credit facility. Also on May 1, 2013, CST issued $550 million of its senior unsecured bonds to us, and we exchanged those bonds with the third-party financial institution in satisfaction of our short-term debt. Immediately prior to May 1, 2013, subsidiaries of CST held $315 million of cash, and CST retained that cash following the distribution on May 1, 2013. Also in connection with the separation, we incurred a tax liability of approximately $189 million primarily related to the manner in which the transaction is treated for tax purposes in Canada, and most of these taxes will not be paid until the first half of 2014. Therefore, the cash we received as a result of the separation, net of our tax liability, was $546 million. We also incurred $30 million in costs during the three months ended June 30, 2013 to effect the separation, which are included in general and administrative expenses. We expect to liquidate the remaining 20 percent of the outstanding shares of CST common stock that we own within 18 months of the date of separation.
We also entered into long-term motor fuel supply agreements with CST in the U.S. and Canada. The nature and significance of our agreements to supply motor fuel to CST through 2028 represents a continuation of activities with CST for accounting purposes. As such, the historical results of operations of our retail business have not been reported as discontinued operations in our statements of income.
Selected historical results of operations of our retail business prior to the separation are disclosed in Note 10. Subsequent to May 1, 2013, our share of CST’s results of operations associated with our retained 20 percent equity interest in CST is reflected in “other income (expense), net” and our equity investment in CST, which is accounted for under the equity method, is included in “deferred charges and other assets, net.” Our share of income taxes incurred directly by CST is reported in the equity in earnings from CST, and as such is not included in income taxes in our statements of income.
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents the carrying values of the major categories of assets and liabilities of our retail business, immediately preceding its separation on May 1, 2013, which are excluded from our consolidated balance sheet as of September 30, 2013 (in millions):

Assets |
Cash and temporary cash investments | $ | 315 |
Credit card receivables from Valero | 44 |
Other receivables, net | 109 |
Inventories | 170 |
Deferred income taxes | 14 |
Prepaid expenses and other | 13 |
Total current assets | 665 |
Property, plant and equipment, at cost | 1,891 |
Accumulated depreciation | (611 | )
Property, plant and equipment, net | 1,280 |
Intangible assets, net | 38 |
Deferred charges and other assets, net | 191 |
Total assets | $ | 2,174 |
Liabilities |
Current portion of capital lease obligations | $ | 2 |
Trade payable to Valero | 242 |
Other accounts payable | 96 |
Accrued expenses | 31 |
Taxes other than income taxes | 20 |
Total current liabilities | 391 |
Debt and capital lease obligations, less current portion | 1,053 |
Deferred income taxes | 83 |
Other long-term liabilities | 112 |
Total liabilities | $ | 1,639 |

We retained certain environmental and other liabilities related to our former retail business and we have indemnified CST for certain self-insurance liabilities related to its employees and property.
On October 24, 2013, we borrowed $525 million under a short-term debt agreement, as further described in Note 5, with a third-party financial institution in anticipation of the liquidation of our remaining 20 percent of the outstanding shares of CST common stock. We intend to exchange our shares of CST common stock with the third-party financial institution in satisfaction of our short-term debt.
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. | IMPAIRMENTS

Aruba Refinery
In March 2012, we suspended the operations of the Aruba Refinery because of its inability to generate positive cash flows on a sustained basis subsequent to its restart in January 2011 and the sensitivity of its profitability to sour crude oil differentials, which had narrowed significantly in the fourth quarter of 2011. Shortly thereafter, we received a non-binding offer to purchase the refinery for $350 million, plus working capital as of the closing date. Because of our decision to suspend the operations and the possibility of selling the refinery, we evaluated the refinery for potential impairment as of March 31, 2012 and concluded that it was impaired. We recognized an asset impairment loss of $595 million in March 2012. We did not, however, classify the Aruba Refinery as “held for sale” in our balance sheet because all of the accounting criteria required for that classification had not been met.
In September 2012, we decided to reorganize the Aruba Refinery into a crude oil and refined products terminal in response to the withdrawal of the non-binding offer to purchase the refinery. We bifurcated the idled crude oil processing units and related infrastructure (refining assets) from the terminal assets and evaluated the refining assets for potential impairment as of September 30, 2012. We concluded that the refining assets were impaired and recognized an asset impairment loss of $308 million in September 2012. We also recognized an asset impairment loss of $25 million related to materials and supplies inventories that supported the refining operations, resulting in a total asset impairment loss of $333 million that was recognized in September 2012 related to the Aruba Refinery. The terminal assets were not impaired.
We have continued to maintain the refining assets to allow them to be restarted and do not consider them to be abandoned. Therefore, we have not reflected the Aruba Refinery as a discontinued operation in our financial statements. It is possible, however, that we may abandon these assets in the future. Should we ultimately decide to abandon these assets, we may be required under our land lease agreement with the Government of Aruba to dismantle and remove the abandoned assets, which would require us to recognize an asset retirement obligation, that would be immediately charged to expense. We do not expect these amounts to be material to our financial position or results of operations.
The variation in the customary relationship between income tax expense and income before income tax expense for the three and nine months ended September 30, 2012 was primarily due to not recognizing a tax benefit associated with the asset impairment loss of $333 million and $928 million, respectively, related to the Aruba Refinery as we do not expect to realize this tax benefit.
Cancelled Capital Project
In March 2012, we wrote down the carrying value of equipment associated with a permanently cancelled capital project at one of our refineries, resulting in an asset impairment loss of $16 million.
Retail Stores
We evaluated certain convenience stores operated by our former retail segment for potential impairment as of September 30, 2012 and concluded that they were impaired. We wrote down the carrying values of these stores to their estimated fair values, which totaled $5 million, resulting in an asset impairment loss of $12 million that was recorded in September 2012.
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. | INVENTORIES

Inventories consisted of the following (in millions):

| September 30, 2013 |  | December 31, 2012
Refinery feedstocks | $ | 3,109 |  |  | $ | 2,458 |
Refined products and blendstocks | 3,582 |  |  | 2,995 |
Ethanol feedstocks and products | 148 |  |  | 191 |
Convenience store merchandise | — |  |  | 112 |
Materials and supplies | 224 |  |  | 217 |
Inventories | $ | 7,063 |  |  | $ | 5,973 |

As of September 30, 2013 and December 31, 2012, the replacement cost (market value) of last in, first out (LIFO) inventories exceeded their LIFO carrying amounts by approximately $7.1 billion and $6.7 billion, respectively.

5. | DEBT

Bank Debt and Credit Facilities
We have a $3 billion revolving credit facility (the Revolver) that has a maturity date of December 2016. The Revolver has certain restrictive covenants, including a maximum debt-to-capitalization ratio of 60 percent. As of September 30, 2013 and December 31, 2012, our debt-to-capitalization ratios, calculated in accordance with the terms of the Revolver, were 20 percent and 23 percent, respectively. We believe that we will remain in compliance with this covenant. In addition to the Revolver, one of our Canadian subsidiaries has a committed revolving credit facility under which it may borrow and obtain letters of credit up to C$50 million.
During the nine months ended September 30, 2013, we had no borrowings or repayments under our Revolver. During the nine months ended September 30, 2012, we borrowed and repaid $1.1 billion under our Revolver. We had no borrowings or repayments under the Canadian revolving credit facility during the nine months ended September 30, 2013 and 2012. As of September 30, 2013 and December 31, 2012, we had no borrowings outstanding under the Revolver or the Canadian revolving credit facility.
On March 20, 2013, in anticipation of the separation of our retail business as described in Note 2, CST entered into a credit agreement providing for $800 million of senior secured credit facilities (consisting of a $500 million term loan facility and a revolving credit facility with an aggregate principal amount of up to $300 million). Borrowings under the term loan and revolving credit facilities bear interest at the London Interbank Offered Rate (LIBOR) plus a margin or an alternate base rate, as defined in the agreement, plus a margin. The credit agreement matures on May 1, 2018 and has certain restrictive covenants. This credit agreement and related credit facilities were retained by CST after the separation from us. Therefore, we have no rights to obtain credit under nor any liabilities in connection with this credit agreement and related credit facilities.
On April 16, 2013, also in anticipation of the separation of our retail business, we borrowed $550 million under a short-term debt agreement with a third-party financial institution. On May 1, 2013, CST issued
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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
$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.
On October 24, 2013, we borrowed $525 million under a short-term debt agreement with a third-party financial institution in anticipation of the liquidation of our remaining 20 percent of the outstanding shares of CST common stock. The debt matures on December 12, 2013.
We had outstanding letters of credit under our committed lines of credit as follows (in millions):

|  |  |  |  |  | Amounts Outstanding
|  | Borrowing Capacity |  | Expiration |  | September 30, 2013 |  | December 31, 2012
Letter of credit facilities |  | $ | 550 |  |  | June 2014 |  | $ | 292 |  |  | $ | 418 |
Revolver |  | $ | 3,000 |  |  | December 2016 |  | $ | 59 |  |  | $ | 59 |
Canadian revolving credit facility |  | C$ | 50 |  |  | November 2013 |  | C$ | 10 |  |  | C$ | 10 |

As of September 30, 2013 and December 31, 2012, we had $257 million and $275 million, respectively, of letters of credit outstanding under our uncommitted short-term bank credit facilities. We anticipate that we will be able to renew our Canadian revolving credit facility prior to its expiration in November 2013.
Non-Bank Debt
During the nine months ended September 30, 2013, the following activity occurred:

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

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

During the nine months ended September 30, 2012, the following activity occurred:

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

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

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

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

| Nine Months Ended September 30,
| 2013 |  | 2012
Balance as of beginning of period | $ | 100 |  |  | $ | 250 |
Proceeds from the sale of receivables | — |  |  | 1,500 |
Repayments | — |  |  | (1,650 | )
Balance as of end of period | $ | 100 |  |  | $ | 100 |

Capitalized Interest
Capitalized interest was $16 million and $59 million for the three months ended September 30, 2013 and 2012, respectively, and $101 million and $164 million for the nine months ended September 30, 2013 and 2012, respectively.

6. | COMMITMENTS AND CONTINGENCIES

Environmental Matter
We are involved, together with several other companies, in an environmental cleanup in the Village of Hartford, Illinois (the Village) and the adjacent shutdown refinery site, which we acquired as part of a prior acquisition. In cooperation with some of the other companies, we have been conducting initial mitigation and cleanup response pursuant to an administrative order issued by the U.S. Environmental Protection Agency (EPA). The EPA is seeking further cleanup obligations from us and other potentially responsible parties for the Village. In parallel with the Village cleanup, we are also in litigation with the State of Illinois Environmental Protection Agency and other potentially responsible parties relating to the remediation of the shutdown refinery site. In each of these matters, we have various defenses and rights for contribution from the other potentially responsible parties. We have accrued for our own expected contribution obligations. However, because of the unpredictable nature of these cleanups and the methodology for allocation of liabilities, it is reasonably possible that we could incur a loss in a range of $0 to $200 million in excess of the amount of our accrual to ultimately resolve these matters. Factors underlying this estimated range are expected to change from time to time, and actual results may vary significantly from this estimate.
Litigation Matters
We are party to claims and legal proceedings arising in the ordinary course of business. We have not recorded a loss contingency liability with respect to some of these matters because we have determined that it is remote that a loss has been incurred. For other matters, we have recorded a loss contingency liability where we have determined that it is probable that a loss has been incurred and that the loss is reasonably estimable. These loss contingency liabilities are not material to our financial position. We re-evaluate and update our loss contingency liabilities as matters progress over time, and we believe that any changes to the recorded liabilities will not be material to our financial position or results of operations.
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One-Time Severance Benefits
As described in Note 3, we decided to reorganize the Aruba Refinery into a crude oil and refined products terminal in September 2012 resulting in a decrease in required personnel for our operations in Aruba. We notified 495 employees in September 2012 of the termination of their employment effective November 15, 2012. Benefits to each terminated employee consisted primarily of a cash payment based on a formula that considered the employee’s current compensation and years of service, among other factors. We recognized a severance liability of $41 million in September 2012, which approximated fair value. We paid $31 million of these benefits in the fourth quarter of 2012 and we paid the remaining termination benefits of $10 million during the first quarter of 2013.
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7. | 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 for the nine months ended September 30, 2013 and 2012 (in millions):

|  | 2013 |  | 2012
|  | Valero Stockholders’ Equity |  | Non- controlling Interests |  | Total Equity |  | Valero Stockholders’ Equity |  | Non- controlling Interest |  | Total Equity
Balance as of beginning of period |  | $ | 18,032 |  |  | $ | 63 |  |  | $ | 18,095 |  |  | $ | 16,423 |  |  | $ | 22 |  |  | $ | 16,445 |
Net income (loss) |  | 1,432 |  |  | 9 |  |  | 1,441 |  |  | 1,073 |  |  | (2 | ) |  | 1,071 |
Dividends |  | (342 | ) |  | — |  |  | (342 | ) |  | (263 | ) |  | — |  |  | (263 | )
Stock-based compensation expense |  | 31 |  |  | — |  |  | 31 |  |  | 29 |  |  | — |  |  | 29 |
Tax deduction in excess of stock-based compensation expense |  | 31 |  |  | — |  |  | 31 |  |  | 16 |  |  | — |  |  | 16 |
Transactions in connection with stock-based compensation plans: |  |  |  |  |  |  |  |  |  |  |  |
Stock issuances |  | 47 |  |  | — |  |  | 47 |  |  | 36 |  |  | — |  |  | 36 |
Stock repurchases |  | (220 | ) |  | — |  |  | (220 | ) |  | (138 | ) |  | — |  |  | (138 | )
Stock repurchases under buyback program |  | (396 | ) |  | — |  |  | (396 | ) |  | — |  |  | — |  |  | — |
Separation of retail business |  | (479 | ) |  | — |  |  | (479 | ) |  | — |  |  | — |  |  | — |
Contributions from noncontrolling interests |  | — |  |  | 45 |  |  | 45 |  |  | — |  |  | 34 |  |  | 34 |
Other comprehensive income |  | 134 |  |  | — |  |  | 134 |  |  | 156 |  |  | — |  |  | 156 |
Balance as of end of period |  | $ | 18,270 |  |  | $ | 117 |  |  | $ | 18,387 |  |  | $ | 17,332 |  |  | $ | 54 |  |  | $ | 17,386 |

The noncontrolling interests relate to third-party ownership interests in two joint venture companies, whose financial statements we consolidate due to our controlling interests.
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Share Activity
Activity in the number of shares of common stock and treasury stock was as follows for the nine months ended September 30, 2013 and 2012 (in millions):

| 2013 |  | 2012
| Common Stock |  | Treasury Stock |  | Common Stock |  | Treasury Stock
Balance as of beginning of period | 673 |  |  | (121 | ) |  | 673 |  |  | (117 | )
Transactions in connection with stock-based compensation plans: |  |  |  |  |  |  |
Stock issuances | — |  |  | 3 |  |  | — |  |  | 3 |
Stock repurchases | — |  |  | (5 | ) |  | — |  |  | (6 | )
Stock repurchases under buyback program | — |  |  | (9 | ) |  | — |  |  | — |
Balance as of end of period | 673 |  |  | (132 | ) |  | 673 |  |  | (120 | )

Accumulated Other Comprehensive Income
Changes in accumulated other comprehensive income by component, net of tax, were as follows for the nine months ended September 30, 2013 (in millions):

| Foreign Currency Translation Adjustment |  | Defined Benefit Pension Items |  | Gains and (Losses) on Cash Flow Hedges |  | Total
Balance as of December 31, 2012 | $ | 665 |  |  | $ | (558 | ) |  | $ | 1 |  |  | $ | 108 |
Other comprehensive income (loss) before reclassifications | (87 | ) |  | 214 |  |  | (4 | ) |  | 123 |
Amounts reclassified from accumulated other comprehensive income (loss) | — |  |  | 12 |  |  | (1 | ) |  | 11 |
Net other comprehensive income (loss) | (87 | ) |  | 226 |  |  | (5 | ) |  | 134 |
Separation of retail business | (159 | ) |  | — |  |  | — |  |  | (159 | )
Balance as of September 30, 2013 | $ | 419 |  |  | $ | (332 | ) |  | $ | (4 | ) |  | $ | 83 |

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

Details about Accumulated Other Comprehensive Income Components |  | Three Months Ended September 30, 2013 |  | Nine Months Ended September 30, 2013 |  | Affected Line Item in the Statement of Income
Amortization of items related to defined benefit pension plans: |  |  |  |  |  |
Net actuarial loss |  | $ | (14 | ) |  | $ | (43 | ) |  | (a)
Prior service credit |  | 9 |  |  | 24 |  |  | (a)
|  | (5 | ) |  | (19 | ) |  | Total before tax
|  | 2 |  |  | 7 |  |  | Tax benefit
|  | $ | (3 | ) |  | $ | (12 | ) |  | Net of tax
Gains on cash flow hedges: |  |  |  |  |  |
Commodity contracts |  | $ | 6 |  |  | $ | 1 |  |  | Cost of sales
|  | 6 |  |  | 1 |  |  | Total before tax
|  | (2 | ) |  | — |  |  | Tax expense
|  | $ | 4 |  |  | $ | 1 |  |  | Net of tax
Total reclassifications for the period |  | $ | 1 |  |  | $ | (11 | ) |  | Net of tax

_________________________

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

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8. | EMPLOYEE BENEFIT PLANS

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

| Pension Plans |  | Other Postretirement Benefit Plans
| 2013 |  | 2012 |  | 2013 |  | 2012
Three months ended September 30: |  |  |  |  |  |  |
Service cost | $ | 34 |  |  | $ | 35 |  |  | $ | 3 |  |  | $ | 3 |
Interest cost | 21 |  |  | 23 |  |  | 4 |  |  | 5 |
Expected return on plan assets | (33 | ) |  | (31 | ) |  | — |  |  | — |
Amortization of: |  |  |  |  |  |  |
Net actuarial loss | 14 |  |  | 8 |  |  | — |  |  | — |
Prior service cost (credit) | (5 | ) |  | 1 |  |  | (4 | ) |  | (6 | )
Net periodic benefit cost | $ | 31 |  |  | $ | 36 |  |  | $ | 3 |  |  | $ | 2 |
Nine months ended September 30: |  |  |  |  |  |  |
Service cost | $ | 105 |  |  | $ | 105 |  |  | $ | 9 |  |  | $ | 9 |
Interest cost | 65 |  |  | 69 |  |  | 13 |  |  | 16 |
Expected return on plan assets | (99 | ) |  | (93 | ) |  | — |  |  | — |
Amortization of: |  |  |  |  |  |  |
Net actuarial loss | 43 |  |  | 25 |  |  | — |  |  | — |
Prior service cost (credit) | (14 | ) |  | 2 |  |  | (10 | ) |  | (17 | )
Net periodic benefit cost | $ | 100 |  |  | $ | 108 |  |  | $ | 12 |  |  | $ | 8 |

On February 15, 2013, we announced changes to certain of our U.S. qualified pension plans that cover the majority of our U.S. employees who work in our refining segment and corporate operations. Benefits under our primary pension plan will change from a final average pay formula to a cash balance formula with staged effective dates that commence either on July 1, 2013 or January 1, 2015 depending on the age and service of the affected employees. All final average pay benefits will be frozen as of December 31, 2014, with all future benefits to be earned under the new cash balance formula. These plan amendments resulted in a $328 million decrease to pension liabilities and a related increase to other comprehensive income during the nine months ended September 30, 2013. The benefit of this remeasurement will be amortized into income through 2025.
As a result of these plan amendments, management reduced its discretionary contributions to our pension plans by $100 million, resulting in expected contributions to our pension plans of $45 million for 2013. During the nine months ended September 30, 2013 and 2012, we contributed $23 million and $137 million, respectively, to our pension plans and $13 million and $14 million, respectively, to our other postretirement benefit plans.
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9. | EARNINGS PER COMMON SHARE

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

| Three Months Ended September 30,
| 2013 |  | 2012
| Restricted Stock |  | Common Stock |  | Restricted Stock |  | Common Stock
Earnings per common share: |  |  |  |  |  |  |
Net income attributable to Valero stockholders |  |  | $ | 312 |  |  |  |  | $ | 674 |
Less dividends paid: |  |  |  |  |  |  |
Common stock |  |  | 121 |  |  |  |  | 96 |
Nonvested restricted stock |  |  | 1 |  |  |  |  | 1 |
Undistributed earnings |  |  | $ | 190 |  |  |  |  | $ | 577 |
Weighted-average common shares outstanding | 3 |  |  | 540 |  |  | 3 |  |  | 549 |
Earnings per common share: |  |  |  |  |  |  |
Distributed earnings | $ | 0.23 |  |  | $ | 0.23 |  |  | $ | 0.18 |  |  | $ | 0.18 |
Undistributed earnings | 0.35 |  |  | 0.35 |  |  | 1.04 |  |  | 1.04 |
Total earnings per common share | $ | 0.58 |  |  | $ | 0.58 |  |  | $ | 1.22 |  |  | $ | 1.22 |
Earnings per common share – assuming dilution: |  |  |  |  |  |  |
Net income attributable to Valero stockholders |  |  | $ | 312 |  |  |  |  | $ | 674 |
Weighted-average common shares outstanding |  |  | 540 |  |  |  |  | 549 |
Common equivalent shares: |  |  |  |  |  |  |
Stock options |  |  | 3 |  |  |  |  | 4 |
Performance awards and nonvested restricted stock |  |  | 2 |  |  |  |  | 3 |
Weighted-average common shares outstanding – assuming dilution |  |  | 545 |  |  |  |  | 556 |
Earnings per common share – assuming dilution |  |  | $ | 0.57 |  |  |  |  | $ | 1.21 |

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| Nine Months Ended September 30,
| 2013 |  | 2012
| Restricted Stock |  | Common Stock |  | Restricted Stock |  | Common Stock
Earnings per common share: |  |  |  |  |  |  |
Net income attributable to Valero stockholders |  |  | $ | 1,432 |  |  |  |  | $ | 1,073 |
Less dividends paid: |  |  |  |  |  |  |
Common stock |  |  | 340 |  |  |  |  | 261 |
Nonvested restricted stock |  |  | 2 |  |  |  |  | 2 |
Undistributed earnings |  |  | $ | 1,090 |  |  |  |  | $ | 810 |
Weighted-average common shares outstanding | 3 |  |  | 544 |  |  | 3 |  |  | 550 |
Earnings per common share: |  |  |  |  |  |  |
Distributed earnings | $ | 0.63 |  |  | $ | 0.63 |  |  | $ | 0.48 |  |  | $ | 0.48 |
Undistributed earnings | 1.99 |  |  | 1.99 |  |  | 1.46 |  |  | 1.46 |
Total earnings per common share | $ | 2.62 |  |  | $ | 2.62 |  |  | $ | 1.94 |  |  | $ | 1.94 |
Earnings per common share – assuming dilution: |  |  |  |  |  |  |
Net income attributable to Valero stockholders |  |  | $ | 1,432 |  |  |  |  | $ | 1,073 |
Weighted-average common shares outstanding |  |  | 544 |  |  |  |  | 550 |
Common equivalent shares: |  |  |  |  |  |  |
Stock options |  |  | 3 |  |  |  |  | 4 |
Performance awards and nonvested restricted stock |  |  | 2 |  |  |  |  | 2 |
Weighted-average common shares outstanding – assuming dilution |  |  | 549 |  |  |  |  | 556 |
Earnings per common share – assuming dilution |  |  | $ | 2.61 |  |  |  |  | $ | 1.93 |

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

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2013 |  | 2012 |  | 2013 |  | 2012
Stock options | 3 |  |  | 5 |  |  | 3 |  |  | 6 |

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10. | SEGMENT INFORMATION

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

|  | Refining |  | Retail |  | Ethanol |  | Corporate |  | Total
Three months ended September 30, 2013: |  |  |  |  |  |  |  |  |  |
Operating revenues from external customers |  | $ | 34,747 |  |  | $ | — |  |  | $ | 1,390 |  |  | $ | — |  |  | $ | 36,137 |
Intersegment revenues |  | — |  |  | — |  |  | 16 |  |  | — |  |  | 16 |
Operating income (loss) |  | 600 |  |  | — |  |  | 113 |  |  | (181 | ) |  | 532 |
Three months ended September 30, 2012: |  |  |  |  |  |  |  |  |  |
Operating revenues from external customers |  | 30,543 |  |  | 3,092 |  |  | 1,091 |  |  | — |  |  | 34,726 |
Intersegment revenues |  | 2,348 |  |  | — |  |  | 15 |  |  | — |  |  | 2,363 |
Operating income (loss) |  | 1,528 |  |  | 41 |  |  | (73 | ) |  | (187 | ) |  | 1,309 |
Nine months ended September 30, 2013: |  |  |  |  |  |  |  |  |  |
Operating revenues from external customers |  | 95,864 |  |  | 3,896 |  |  | 3,885 |  |  | — |  |  | 103,645 |
Intersegment revenues |  | 2,876 |  |  | — |  |  | 86 |  |  | — |  |  | 2,962 |
Operating income (loss) |  | 2,733 |  |  | 81 |  |  | 222 |  |  | (635 | ) |  | 2,401 |
Nine months ended September 30, 2012: |  |  |  |  |  |  |  |  |  |
Operating revenues from external customers |  | 92,181 |  |  | 9,089 |  |  | 3,285 |  |  | — |  |  | 104,555 |
Intersegment revenues |  | 6,806 |  |  | — |  |  | 75 |  |  | — |  |  | 6,881 |
Operating income (loss) |  | 2,773 |  |  | 253 |  |  | (59 | ) |  | (541 | ) |  | 2,426 |

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

| September 30, 2013 |  | December 31, 2012
Refining | $ | 43,035 |  |  | $ | 39,490 |
Retail | — |  |  | 2,043 |
Ethanol | 879 |  |  | 929 |
Corporate | 2,379 |  |  | 2,015 |
Total assets | $ | 46,293 |  |  | $ | 44,477 |

11. | SUPPLEMENTAL CASH FLOW INFORMATION

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

| Nine Months Ended September 30,
| 2013 |  | 2012
Decrease (increase) in current assets: |  |  |
Receivables, net | $ | (1,135 | ) |  | $ | 1,133 |
Inventories | (1,335 | ) |  | (116 | )
Income taxes receivable | (122 | ) |  | 172 |
Prepaid expenses and other | 8 |  |  | (25 | )
Increase (decrease) in current liabilities: |  |  |
Accounts payable | 2,031 |  |  | (150 | )
Accrued expenses | 51 |  |  | 10 |
Taxes other than income taxes | 276 |  |  | 55 |
Income taxes payable | (5 | ) |  | 112 |
Changes in current assets and current liabilities | $ | (231 | ) |  | $ | 1,191 |

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 nine months ended September 30, 2013 exclude the change in current assets and current liabilities resulting from the separation of our retail business as described in Note 2;

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

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

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

There were no significant noncash investing activities for the nine months ended September 30, 2013. Noncash financing activities for the nine months ended September 30, 2013 included the exchange of CST’s senior unsecured bonds with the third-party financial institution in satisfaction of our short-term debt as described in Note 2.
There were no significant noncash investing or financing activities for the nine months ended September 30, 2012.
Cash flows related to interest and income taxes were as follows (in millions):

| Nine Months Ended September 30,
| 2013 |  | 2012
Interest paid in excess of amount capitalized | $ | 237 |  |  | $ | 206 |
Income taxes paid, net | 347 |  |  | 238 |

12. | FAIR VALUE MEASUREMENTS

General
GAAP requires that certain assets and liabilities be measured at fair value on a recurring or nonrecurring basis in our balance sheets, which are presented below under “Recurring Fair Value Measurements” and “Nonrecurring Fair Value Measurements.” Recurring fair value measurements of assets or liabilities are those that GAAP requires or permits in the balance sheet at the end of each reporting period, such as derivative financial instruments. Nonrecurring fair value measurements of assets or liabilities are those that GAAP requires or permits in the balance sheet in particular circumstances, such as the impairment of property, plant and equipment.
GAAP also requires the disclosure of the fair values of financial instruments when an option to elect fair value accounting has been provided, but such election has not been made. A debt obligation is an example of such a financial instrument. The disclosure of the fair values of financial instruments not recognized at fair value in our balance sheet is presented below under “Other Financial Instruments.”
GAAP provides a framework for measuring fair value and establishes a three-level fair value hierarchy that prioritizes inputs to valuation techniques based on the degree to which objective prices in external active markets are available to measure fair value. Following is a description of each of the levels of the fair value hierarchy.

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

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• | 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.

Recurring Fair Value Measurements
The tables below present information (in millions) about our assets and liabilities recognized at their fair values in our balance sheets categorized according to the fair value hierarchy of the inputs utilized by us to determine the fair values as of September 30, 2013 and December 31, 2012.
We have elected to offset the fair value amounts recognized for multiple similar derivative contracts executed with the same counterparty, including any related cash collateral assets or obligations as shown below; however, fair value amounts by hierarchy level are presented on a gross basis in the tables below. We have no derivative contracts that are subject to master netting arrangements that are reflected gross on the balance sheet.

| September 30, 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 | $ | 1,345 |  |  | $ | 26 |  |  | $ | — |  |  | $ | 1,371 |  |  | $ | (1,331 | ) |  | $ | (5 | ) |  | $ | 35 |  |  | $ | — |
Investments of certain benefit plans | 92 |  |  | — |  |  | 11 |  |  | 103 |  |  | N/A |  |  | N/A |  |  | 103 |  |  | N/A |
Total | $ | 1,437 |  |  | $ | 26 |  |  | $ | 11 |  |  | $ | 1,474 |  |  | $ | (1,331 | ) |  | $ | (5 | ) |  | $ | 138 |  |  |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity derivative contracts | $ | 1,314 |  |  | $ | 37 |  |  | $ | — |  |  | $ | 1,351 |  |  | $ | (1,331 | ) |  | $ | (12 | ) |  | $ | 8 |  |  | $ | (79 | )
Physical purchase contracts | — |  |  | 17 |  |  | — |  |  | 17 |  |  | N/A |  |  | N/A |  |  | 17 |  |  | N/A |
Foreign currency contracts | 5 |  |  | — |  |  | — |  |  | 5 |  |  | N/A |  |  | N/A |  |  | 5 |  |  | N/A |
Total | $ | 1,319 |  |  | $ | 54 |  |  | $ | — |  |  | $ | 1,373 |  |  | $ | (1,331 | ) |  | $ | (12 | ) |  | $ | 30 |  |  |

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| December 31, 2012
|  |  | Total Gross Fair Value |  | Effect of Counter- party Netting |  | Effect of Cash Collateral Netting |  | Net Carrying Value on Balance Sheet |  | Cash Collateral Paid or Received Not Offset
| Fair Value Hierarchy |  |  |  |  |
| Level 1 |  | Level 2 |  | Level 3 |  |  |  |  |
Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity derivative contracts | $ | 1,143 |  |  | $ | 60 |  |  | $ | — |  |  | $ | 1,203 |  |  | $ | (1,189 | ) |  | $ | — |  |  | $ | 14 |  |  | $ | — |
Physical purchase contracts | — |  |  | 11 |  |  | — |  |  | 11 |  |  | N/A |  |  | N/A |  |  | 11 |  |  | N/A |
Foreign currency contracts | 1 |  |  | — |  |  | — |  |  | 1 |  |  | N/A |  |  | N/A |  |  | 1 |  |  | N/A |
Investments of certain benefit plans | 87 |  |  | — |  |  | 11 |  |  | 98 |  |  | N/A |  |  | N/A |  |  | 98 |  |  | N/A |
Total | $ | 1,231 |  |  | $ | 71 |  |  | $ | 11 |  |  | $ | 1,313 |  |  | $ | (1,189 | ) |  | $ | — |  |  | $ | 124 |  |  |
Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity derivative contracts | $ | 1,138 |  |  | $ | 70 |  |  | $ | — |  |  | $ | 1,208 |  |  | $ | (1,189 | ) |  | $ | (13 | ) |  | $ | 6 |  |  | $ | (114 | )
Biofuels blending obligation | — |  |  | 10 |  |  | — |  |  | 10 |  |  | N/A |  |  | N/A |  |  | 10 |  |  | N/A |
Foreign currency contracts | 1 |  |  | — |  |  | — |  |  | 1 |  |  | N/A |  |  | N/A |  |  | 1 |  |  | N/A |
Total | $ | 1,139 |  |  | $ | 80 |  |  | $ | — |  |  | $ | 1,219 |  |  | $ | (1,189 | ) |  | $ | (13 | ) |  | $ | 17 |  |  |  |

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 13, some of these contracts are designated as hedging instruments. These contracts are measured at fair value using the market approach. Exchange-traded futures are valued based on quoted prices from the exchange and are categorized in Level 1 of the fair value hierarchy. Swaps are priced using third-party broker quotes, industry pricing services, and exchange-traded curves, with appropriate consideration of counterparty credit risk, but because they have contractual terms that are not identical to exchange-traded futures instruments with a comparable market price, these financial instruments are categorized in Level 2 of the fair value hierarchy.

• | Physical purchase contracts represent the fair value of firm commitments to purchase crude oil feedstocks and the fair value of fixed-price corn purchase contracts, and as disclosed in Note 13, some of these contracts are designated as hedging instruments. The fair values of these firm commitments and purchase contracts are measured using a market approach based on quoted prices from the commodity exchange or an independent pricing service and are categorized in Level 2 of the fair value hierarchy.

• | 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.

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

• | Our biofuels blending obligation represents a liability for the purchase of biofuel credits (primarily RINs 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 13 under “Compliance Program 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 September 30, 2013 and December 31, 2012 that were measured at fair value on a recurring basis.
There was no activity during the three and nine months ended September 30, 2013 and 2012 related to the fair value amounts categorized in Level 3 as of September 30, 2013 and December 31, 2012.
Nonrecurring Fair Value Measurements
There were no assets or liabilities that were measured at fair value on a nonrecurring basis as of September 30, 2013.
The table below presents the fair value of certain assets that were measured at fair value on a nonrecurring basis as of December 31, 2012 (in millions).

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

There were no liabilities that were measured at fair value on a nonrecurring basis as of December 31, 2012.
As discussed in Note 3, during the nine months ended September 30, 2012, we recognized asset impairment losses of $928 million, $16 million, and $12 million related to our Aruba Refinery, certain equipment associated with a permanently cancelled capital project at one of our refineries, and certain convenience stores operated by our former retail segment, respectively. These impairment losses resulted from the fair value measurement of those assets on a nonrecurring basis during 2012 as follows:
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• | As of March 31, 2012, we concluded that the Aruba Refinery was impaired. As a result, we were required to determine the fair value of the Aruba Refinery and to write down its carrying value to that amount. We determined that the best measure of the refinery’s fair value at that time was the $350 million offer we received to purchase the refinery, which we accepted. The fair value of the Aruba Refinery was measured using the market approach and was categorized in Level 3 within the fair value hierarchy. The carrying value of the Aruba Refinery’s long-lived assets as of March 31, 2012 was $945 million; therefore, we recognized an asset impairment loss of $595 million in March 2012.

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

• | In September 2012, following the withdrawal of the offer to purchase the refinery, we decided to reorganize the Aruba Refinery into a crude oil and refined products terminal and evaluated the refining assets for potential impairment as of September 30, 2012. We concluded that these refining assets were impaired and determined that their carrying value was not recoverable through the future operations and disposition of the refinery, resulting in a total asset impairment loss of $333 million in September 2012.

• | As of September 30, 2012, we evaluated certain convenience stores operated by our former retail segment for potential impairment and concluded that they were impaired. We wrote down the carrying values of these stores to their estimated fair values, which totaled $5 million, and recognized an asset impairment loss of $12 million that was recorded in September 2012.

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

| September 30, 2013 |  | December 31, 2012
| Carrying Amount |  | Fair Value |  | Carrying Amount |  | Fair Value
Financial assets: |  |  |  |  |  |  |
Cash and temporary cash investments | $ | 1,908 |  |  | $ | 1,908 |  |  | $ | 1,723 |  |  | $ | 1,723 |
Equity investment in CST | 119 |  |  | 449 |  |  | — |  |  | — |
Financial liabilities: |  |  |  |  |  |  |
Debt (excluding capital leases) | 6,524 |  |  | 7,545 |  |  | 7,000 |  |  | 8,621 |

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

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

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

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

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13. | PRICE RISK MANAGEMENT ACTIVITIES

General
We are exposed to market risks related to the volatility in the price of commodities, 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 12), as summarized below under “Fair Values of Derivative Instruments.” In addition, the effect of these derivative instruments on our income is summarized below under “Effect of Derivative Instruments on Income and Other Comprehensive Income.”
When we enter into a derivative instrument, it is designated as a fair value hedge, a cash flow hedge, an economic hedge, or a trading derivative. The gain or loss on a derivative instrument designated and qualifying as a fair value hedge, as well as the offsetting loss or gain on the hedged item attributable to the hedged risk, is recognized currently in income in the same period. The effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedge is initially reported as a component of other comprehensive income and is then recorded 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 and sale exception and do not record these contracts at their fair values.
Risk Management Activities by Type of Risk
Commodity Price Risk
We are exposed to market risks related to the volatility in the price of crude oil, refined products (primarily gasoline and distillate), grain (primarily corn), soybean oil, and natural gas used in our operations. To reduce the impact of price volatility on our results of operations and cash flows, we use commodity derivative instruments, including futures, swaps, and options. We use the futures markets for the available liquidity, which provides greater flexibility in transacting our hedging and trading operations. We use swaps primarily to manage our price exposure. Our positions in commodity derivative instruments are monitored and managed on a daily basis by a risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors.
For risk management purposes, we use fair value hedges, cash flow hedges, and economic hedges. In addition to the use of derivative instruments to manage commodity price risk, we also enter into certain commodity derivative instruments for trading purposes. Our objective for entering into each type of hedge or trading derivative is described below.
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• | Fair Value Hedges – Fair value hedges are used to hedge price volatility in certain refining inventories and firm commitments to purchase inventories. The level of activity for our fair value hedges is based on the level of our operating inventories, and generally represents the amount by which our inventories differ from our previous year-end LIFO inventory levels.

As of September 30, 2013, we had the following outstanding commodity derivative instruments that were entered into to hedge crude oil and refined product inventories and commodity derivative instruments related to the physical purchase of crude oil and refined products at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).

|  | Notional Contract Volumes by Year of Maturity
Derivative Instrument |  | 2013
Crude oil and refined products: |  |
Futures – long |  | 11,986 |
Futures – short |  | 15,788 |
Physical contracts – long |  | 3,802 |

• | 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 September 30, 2013, we had the following outstanding commodity derivative instruments that were entered into to hedge forecasted purchases or sales of crude oil and refined products. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).

|  | Notional Contract Volumes by Year of Maturity
Derivative Instrument |  | 2013
Crude oil and refined products: |  |
Futures – long |  | 5,876 |
Futures – short |  | 2,759 |
Physical contracts – short |  | 3,117 |

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• | Economic Hedges – Economic hedges represent commodity derivative instruments that are not designated as fair value or cash flow hedges and are used to manage price volatility in certain (i) refinery feedstock, refined product, 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 September 30, 2013, we had the following outstanding commodity derivative instruments that were used as economic hedges and commodity derivative instruments related to the physical purchase of corn at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except those identified as natural gas contracts that are presented in billions of British thermal units, corn contracts that are presented in thousands of bushels, and soybean oil contracts that are presented in thousands of pounds).

|  | Notional Contract Volumes by Year of Maturity
Derivative Instrument |  | 2013 |  | 2014 |  | 2015
Crude oil and refined products: |  |  |  |  |  |
Swaps – long |  | 2,867 |  |  | 45 |  |  | — |
Swaps – short |  | 1,797 |  |  | 90 |  |  | — |
Futures – long |  | 31,357 |  |  | 75 |  |  | — |
Futures – short |  | 42,753 |  |  | — |  |  | — |
Natural gas: |  |  |  |  |  |
Options – long |  | 5,250 |  |  | — |  |  | — |
Corn: |  |  |  |  |  |
Futures – long |  | 19,695 |  |  | 5 |  |  | — |
Futures – short |  | 21,410 |  |  | 1,500 |  |  | 15 |
Physical contracts – long |  | 7,682 |  |  | 1,543 |  |  | — |
Soybean oil: |  |  |  |  |  |
Futures – short |  | 26,520 |  |  | — |  |  | — |

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

As of September 30, 2013, we had the following outstanding commodity and other derivative instruments that were entered into for trading purposes. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes represent thousands of barrels, except those identified as natural gas contracts that are presented in billions of British thermal units and corn contracts that are presented in thousands of bushels).

|  | Notional Contract Volumes by Year of Maturity
Derivative Instrument |  | 2013 |  | 2014
Crude oil and refined products: |  |  |  |
Swaps – long |  | 11,484 |  |  | 21,135 |
Swaps – short |  | 11,484 |  |  | 21,135 |
Futures – long |  | 121,803 |  |  | 49,298 |
Futures – short |  | 122,138 |  |  | 49,223 |
Options – long |  | 20,950 |  |  | 10,000 |
Options – short |  | 20,250 |  |  | 10,000 |
Natural gas: |  |  |  |
Futures – long |  | 1,150 |  |  | — |
Futures – short |  | 550 |  |  | — |
Options – long |  | 3,000 |  |  | — |
Corn: |  |  |  |
Futures – long |  | 3,200 |  |  | — |
Futures – short |  | 2,900 |  |  | — |

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 September 30, 2013 or December 31, 2012, or during the three and nine months ended September 30, 2013 and 2012.
Foreign Currency Risk
We are exposed to exchange rate fluctuations on transactions entered into by our international operations that are denominated in currencies other than the local (functional) currencies of those operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and purchase contracts. These contracts are not designated as hedging instruments for accounting purposes, and therefore they are classified as economic hedges. As of September 30, 2013, we had commitments to purchase $845 million
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of U.S. dollars. These commitments matured on or before October 31, 2013, resulting in an immaterial loss in the fourth quarter of 2013.
Compliance Program Price Risk
We are exposed to market risk related to the volatility in the price of credits needed to comply with various governmental and regulatory programs. The most significant programs impacting our operations are those that require us to blend biofuels into the products we produce, and we are subject to such programs in most of the countries in which we operate. These countries set annual quotas for the percentage of biofuels that must be blended into the motor fuels consumed in these countries. As a producer of motor fuels from petroleum, we are obligated to blend biofuels into the products we produce at a rate that is at least equal to the applicable quota. To the degree we are unable to blend at the applicable rate, we must purchase biofuel credits (primarily RINs in the U.S.). We are exposed to the volatility in the market price of these credits, and we manage that risk by purchasing biofuel credits when prices are deemed favorable. The cost of meeting our obligations under these compliance programs was $187 million and $72 million for the three months ended September 30, 2013 and 2012, respectively, and $454 million and $198 million for the nine months ended September 30, 2013 and 2012, respectively. These amounts are reflected in cost of sales.
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Fair Values of Derivative Instruments
The following tables provide information about the fair values of our derivative instruments as of September 30, 2013 and December 31, 2012 (in millions) and the line items in the balance sheets in which the fair values are reflected. See Note 12 for additional information related to the fair values of our derivative instruments.
As indicated in Note 12, we net fair value amounts recognized for multiple similar derivative contracts executed with the same counterparty under master netting arrangements, including cash collateral assets and obligations. The tables below, however, are presented on a gross asset and gross liability basis, which results in the reflection of certain assets in liability accounts and certain liabilities in asset accounts.

| Balance Sheet Location |  | September 30, 2013
|  | Asset Derivatives |  | Liability Derivatives
Derivatives designated as hedging instruments |  |  |  |  |
Commodity contracts: |  |  |  |  |
Futures | Receivables, net |  | $ | 45 |  |  | $ | 45 |
Derivatives not designated as hedging instruments |  |  |  |  |
Commodity contracts: |  |  |  |  |
Futures | Receivables, net |  | $ | 1,300 |  |  | $ | 1,267 |
Swaps | Receivables, net |  | 18 |  |  | 27 |
Swaps | Prepaid expenses and other |  | 5 |  |  | — |
Swaps | Accrued expenses |  | 1 |  |  | 9 |
Options | Receivables, net |  | 2 |  |  | 3 |
Physical purchase contracts | Inventories |  | — |  |  | 17 |
Foreign currency contracts | Accrued expenses |  | — |  |  | 5 |
Total |  |  | $ | 1,326 |  |  | $ | 1,328 |
Total derivatives |  |  | $ | 1,371 |  |  | $ | 1,373 |

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| Balance Sheet Location |  | December 31, 2012
|  | Asset Derivatives |  | Liability Derivatives
Derivatives designated as hedging instruments |  |  |  |  |
Commodity contracts: |  |  |  |  |
Futures | Receivables, net |  | $ | 77 |  |  | $ | 64 |
Swaps | Receivables, net |  | 15 |  |  | 13 |
Swaps | Prepaid expenses and other |  | 2 |  |  | 2 |
Total |  |  | $ | 94 |  |  | $ | 79 |
Derivatives not designated as hedging instruments |  |  |  |  |
Commodity contracts: |  |  |  |  |
Futures | Receivables, net |  | $ | 1,066 |  |  | $ | 1,073 |
Swaps | Receivables, net |  | 9 |  |  | 6 |
Swaps | Accrued expenses |  | 32 |  |  | 46 |
Options | Receivables, net |  | 1 |  |  | 4 |
Options | Accrued expenses |  | 1 |  |  | — |
Physical purchase contracts | Inventories |  | 11 |  |  | — |
Foreign currency contracts | Receivables, net |  | 1 |  |  | — |
Foreign currency contracts | Accrued expenses |  | — |  |  | 1 |
Total |  |  | $ | 1,121 |  |  | $ | 1,130 |
Total derivatives |  |  | $ | 1,215 |  |  | $ | 1,209 |

Market and Counterparty Risk
Our price risk management activities involve the receipt or payment of fixed price commitments into the future. These transactions give rise to market risk, which is the risk that future changes in market conditions may make an instrument less valuable. We closely monitor and manage our exposure to market risk on a daily basis in accordance with policies approved by our board of directors. Market risks are monitored by a risk control group to ensure compliance with our stated risk management policy. Concentrations of customers in the refining industry may impact our overall exposure to counterparty risk because these customers may be similarly affected by changes in economic or other conditions. In addition, financial services companies are the counterparties in certain of our price risk management activities, and such financial services companies may be adversely affected by periods of uncertainty and illiquidity in the credit and capital markets.
There were no significant amounts due from counterparties in the refining or financial services industry as of September 30, 2013 or December 31, 2012. We do not require any collateral or other security to support derivative instruments into which we enter. We also do not have any derivative instruments that require us to maintain a minimum investment-grade credit rating.
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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 September 30, |  | Nine Months Ended September 30,
2013 |  | 2012 | 2013 |  | 2012
Commodity contracts: |  |  |  |  |  |  |  |  |  |
Loss recognized in income on derivatives |  | Cost of sales |  | $ | (17 | ) |  | $ | (127 | ) |  | $ | (38 | ) |  | $ | (307 | )
Gain recognized in income on hedged item |  | Cost of sales |  | 19 |  |  | 101 |  |  | 41 |  |  | 238 |
Gain (loss) recognized in income on derivatives (ineffective portion) |  | Cost of sales |  | 2 |  |  | (26 | ) |  | 3 |  |  | (69 | )

For fair value hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness for the three and nine months ended September 30, 2013 and 2012. There were no amounts recognized in income for hedged firm commitments that no longer qualified as fair value hedges during the three or nine months ended September 30, 2013. There were no amounts recognized in income for hedged firm commitments that no longer qualified as fair value hedges during the three months ended September 30, 2012; however, a gain of $28 million was recognized in income during the nine months ended September 30, 2012 for hedged firm commitments that no longer qualified as fair value hedges .

Derivatives in Cash Flow Hedging Relationships |  | Location of Gain (Loss) Recognized in Income on Derivatives |  | Three Months Ended September 30, |  | Nine Months Ended September 30,
|  | 2013 |  | 2012 |  | 2013 |  | 2012
Commodity contracts: |  |  |  |  |  |  |  |  |  |
Gain (loss) recognized in OCI on derivatives (effective portion) |  |  |  | $ | 3 |  |  | $ | 27 |  |  | $ | (6 | ) |  | $ | 43 |
Gain reclassified from accumulated OCI into income (effective portion) |  | Cost of sales |  | 6 |  |  | 45 |  |  | 1 |  |  | 81 |
Gain (loss) recognized in income on derivatives (ineffective portion) |  | Cost of sales |  | 16 |  |  | (3 | ) |  | 13 |  |  | 23 |

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
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 nine months ended September 30, 2013 and 2012. For the three and nine months ended September 30, 2013, cash flow hedges primarily related to forward sales of gasoline and distillates, and associated forward purchases of crude oil, with $4 million of cumulative after-tax losses on cash flow hedges remaining in accumulated other comprehensive income. We estimate that $4 million of the deferred loss as of September 30, 2013 will be reclassified into cost of sales over the next 12 months as a result of hedged transactions that are forecasted to occur. For the three and nine months ended September 30, 2013 and 2012, there were no amounts reclassified from accumulated other comprehensive income into income as a result of the discontinuance of cash flow hedge accounting.

Derivatives Designated as Economic Hedges and Other Derivative Instruments |  | Location of Gain (Loss) Recognized in Income on Derivatives |  | Three Months Ended September 30, |  | Nine Months Ended September 30,
2013 |  | 2012 | 2013 |  | 2012
Commodity contracts |  | Cost of sales |  | $ | (76 | ) |  | $ | (333 | ) |  | $ | 205 |  |  | $ | 90 |
Foreign currency contracts |  | Cost of sales |  | (22 | ) |  | (21 | ) |  | 14 |  |  | (43 | )
Total |  |  |  | $ | (98 | ) |  | $ | (354 | ) |  | $ | 219 |  |  | $ | 47 |

Trading Derivatives |  | Location of Gain (Loss) Recognized in Income on Derivatives |  | Three Months Ended September 30, |  | Nine Months Ended September 30,
2013 |  | 2012 | 2013 |  | 2012
Commodity contracts |  | Cost of sales |  | $ | 11 |  |  | $ | (13 | ) |  | $ | 16 |  |  | $ | (9 | )
RINs fixed-price contracts |  | Cost of sales |  | — |  |  | — |  |  | (20 | ) |  | — |
Total |  |  |  | $ | 11 |  |  | $ | (13 | ) |  | $ | (4 | ) |  | $ | (9 | )

14. VALERO ENERGY PARTNERS LP
On September 19, 2013, Valero Energy Partners LP (VLP), our wholly owned subsidiary, filed a registration statement on Form S-1 with the U.S. Securities and Exchange Commission in connection with a proposed initial public offering of its common units representing limited partner interests. On October 28, 2013, VLP filed an amendment to the Form S-1. The number of common units to be offered and the price per unit have not yet been determined.
We formed VLP to own, operate, develop, and acquire crude oil and refined petroleum products pipelines, terminals, and other transportation and logistics assets. We intend to contribute assets to VLP that will include crude oil and refined petroleum products pipeline and terminal systems in the U.S. Gulf Coast and U.S. Mid-Continent regions that are integral to the operations of our Port Arthur, McKee, and Memphis Refineries.
As of the date of this report, the registration statement is not effective. The completion of the offering is subject to numerous conditions, including market conditions, and we can provide no assurance that it will be successfully completed. The information contained in this report is neither an offer to sell nor a solicitation of an offer to buy any of VLP’s common units in the initial public offering.
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Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

• | future refining margins, including gasoline and distillate margins;

• | future ethanol margins;

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

• | anticipated levels of crude oil and refined product inventories;

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

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

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

• | the effect of general economic and other conditions on refining and ethanol industry fundamentals.

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

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

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

• | demand for, and supplies of, refined products such as gasoline, diesel fuel, jet fuel, petrochemicals, and ethanol;

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

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

• | the level of consumer demand, including seasonal fluctuations;

• | refinery overcapacity or undercapacity;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Any one of these factors, or a combination of these factors, could materially affect our future results of operations and whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.
All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.
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OVERVIEW AND OUTLOOK
Overview
For the third quarter of 2013, we reported net income attributable to Valero stockholders of $312 million, or $0.57 per share (assuming dilution), compared to $674 million, or $1.21 per share (assuming dilution), for the third quarter of 2012.
The decrease in net income attributable to Valero stockholders of $362 million was primarily due to the decrease of $777 million in our operating income as outlined by business segment in the table below (in millions), partially offset by a $441 million decrease in income tax expense for the third quarter of 2013 compared to the third quarter of 2012. Income tax expense for the third quarter of 2012 was higher than the comparable 2013 period due to the asset impairment loss and severance expense described below that we recognized during the third quarter of 2012 for which we did not recognize a tax benefit.

|  | Three Months Ended September 30,
|  | 2013 |  | 2012 |  | Change
Operating income (loss) by business segment: |  |  |  |  |  |
Refining |  | $ | 600 |  |  | $ | 1,528 |  |  | $ | (928 | )
Retail |  | — |  |  | 41 |  |  | (41 | )
Ethanol |  | 113 |  |  | (73 | ) |  | 186 |
Corporate |  | (181 | ) |  | (187 | ) |  | 6 |
Total |  | $ | 532 |  |  | $ | 1,309 |  |  | $ | (777 | )

Operating income for the third quarter of 2012 was negatively impacted by asset impairment losses of $345 million, of which $333 million related to our Aruba Refinery (as further discussed in Note 3 of Condensed Notes to Consolidated Financial Statements), and severance expense of $41 million, which was also related to our Aruba Refinery (as further discussed in Note 6 of Condensed Notes to Consolidated Financial Statements). Excluding these significant items, total operating income for the third quarter of 2012 would have been $1.7 billion, reflecting a $1.2 billion decrease between the quarters, and our refining segment operating income for the third quarter of 2012 would have been $1.9 billion, reflecting a $1.3 billion decrease between the quarters.
The $1.3 billion decrease in refining segment operating income in the third quarter of 2013 compared to the third quarter of 2012 was primarily due to lower refining margins in each of our regions. The decrease in refining margins was the result of lower gasoline and diesel margins, lower discounts on light sweet and sour crude oils, and higher costs of biofuel credits (primarily Renewable Identification Numbers (RINs) needed to comply with the U.S. federal Renewable Fuel Standard (RFS)).
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 third quarter of 2013, resulting in the $41 million decrease in retail segment operating income in the third quarter of 2013 compared to the third quarter of 2012. The separation of our retail business is more fully discussed in Note 2 of Condensed Notes to Consolidated Financial Statements.
Our ethanol segment operating income in the third quarter of 2013 increased $186 million compared to the third quarter of 2012 due to higher gross margins per gallon and higher production volumes. Ethanol prices increased quarter over quarter due to a decrease in the supply of ethanol resulting from lower industry production volumes throughout 2012 and into the first quarter of 2013. We increased our production of ethanol in the second and third quarters of 2013 to capture the improved economics of higher gross margins per gallon during the quarter.
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For the first nine months of 2013, we reported net income attributable to Valero stockholders of $1.4 billion, or $2.61 per share (assuming dilution), compared to $1.1 billion, or $1.93 per share (assuming dilution), for the first nine months of 2012.
The increase in net income attributable to Valero stockholders of $359 million was primarily due to the $372 million decrease in income tax expense for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012. Consistent with the previous discussion regarding our third quarter results, income tax expense for the nine months ended September 30, 2012 was higher than the comparable 2013 period due to the asset impairment losses and severance expense that we recognized during the first nine months of 2012 described below for which we did not recognize a tax benefit.
Operating income for the first nine months of 2013 was consistent with the first nine months of 2012, decreasing only $25 million, as outlined by business segment in the following table (in millions):

|  | Nine Months Ended September 30,
|  | 2013 |  | 2012 |  | Change
Operating income (loss) by business segment: |  |  |  |  |  |
Refining |  | $ | 2,733 |  |  | $ | 2,773 |  |  | $ | (40 | )
Retail |  | 81 |  |  | 253 |  |  | (172 | )
Ethanol |  | 222 |  |  | (59 | ) |  | 281 |
Corporate |  | (635 | ) |  | (541 | ) |  | (94 | )
Total |  | $ | 2,401 |  |  | $ | 2,426 |  |  | $ | (25 | )

However, operating income for the first nine months of 2012 was negatively impacted by asset impairment losses and severance expense. For the first nine months of 2012, we recorded asset impairment losses of $956 million, of which $928 million related to our Aruba Refinery, and severance expense of $41 million, which was also related to our Aruba Refinery. Excluding these significant items, total operating income and refining segment operating income for the first nine months of 2012 would have been $3.4 billion and $3.8 billion, respectively, resulting in a $1.0 billion decrease in both total operating income and refining segment operating income in the first nine months of 2013 compared to the first nine months of 2012.
The $1.0 billion decrease in refining segment operating income in the first nine months of 2013 compared to the first nine months of 2012 was primarily due to lower refining margins in each of our regions, which resulted from lower discounts on light sweet crude oils and higher costs of biofuel credits (primarily RINs in the U.S.). The $172 million decrease in retail segment operating income in the first nine months of 2013 compared to the first nine months of 2012 was primarily due to the separation of our retail business on May 1, 2013, as previously discussed, and the reasons for the $281 million increase in ethanol segment operating income between the nine-month periods are also consistent with those previously discussed.
Outlook
Our refining segment benefits from processing sour crude oils (such as Maya crude oil) in our U.S. Gulf Coast region and light sweet crude oils (such as West Texas Intermediate crude oil) in our U.S. Mid-Continent region 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 light sweet crude oils and sour crude oils compared to the price of Brent crude oil for the third quarter of 2013 narrowed compared to the third quarter of 2012 and impacted our refining margins. For the fourth quarter of 2013, discounts on light sweet and sour crude oils have widened to date compared to the third quarter, and we expect this trend to continue for the remainder of the
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fourth quarter; however, gasoline margins are seasonally weak. Energy markets and margins are volatile, and we expect them to continue to be volatile in the near to mid-term.
We are obligated to blend biofuels into the products we produce, and because we are unable to blend biofuels at the applicable rates, we must purchase biofuel credits (primarily RINs in the U.S.) in the open market and are therefore exposed to the volatility in the market price of these credits. During the first nine months of 2013, the market price of RINs increased significantly, resulting in higher costs. As further discussed in Note 13 of Condensed Notes to Consolidated Financial Statements, the cost of meeting our obligations under various biofuel blending compliance programs was $454 million for the first nine months of 2013. To date during the fourth quarter of 2013, the market price of RINs has decreased significantly. Therefore, we estimate that the cost of meeting our obligation for the full year of 2013 will be between $500 million and $600 million. The market price of RINs, however, is volatile and is significantly impacted by biofuel blending rates that are established by the EPA. As a result, it is difficult for us to reliably predict the market price of RINs.
On September 19, 2013, Valero Energy Partners LP (VLP), our wholly owned subsidiary, filed a registration statement on Form S-1 with the U.S. Securities and Exchange Commission in connection with a proposed initial public offering of its common units representing limited partner interests. On October 28, 2013, VLP filed an amendment to the initial Form S-1. The number of common units to be offered and the price per unit have not yet been determined. We formed VLP to own, operate, develop, and acquire crude oil and refined petroleum products pipelines, terminals, and other transportation and logistics assets. We intend to contribute assets to VLP that will include crude oil and refined petroleum products pipeline and terminal systems in the U.S. Gulf Coast and U.S. Mid-Continent regions that are integral to the operations of our Port Arthur, McKee, and Memphis Refineries. As of the date of this report, the registration statement is not effective. The completion of the offering is subject to numerous conditions, including market conditions, and we can provide no assurance that it will be successfully completed. The information contained in this report is neither an offer to sell nor a solicitation of an offer to buy any of VLP’s common units in the initial public offering.
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RESULTS OF OPERATIONS
The following tables highlight our results of operations, our operating performance, and market prices that directly impact our operations. The narrative following these tables provides an analysis of our results of operations.
Financial Highlights
(millions of dollars, except per share amounts)

| Three Months Ended September 30,
| 2013 (a) |  | 2012 |  | Change
Operating revenues | $ | 36,137 |  |  | $ | 34,726 |  |  | $ | 1,411 |
Costs and expenses: |  |  |  |  |
Cost of sales | 33,931 |  |  | 31,312 |  |  | 2,619 |
Operating expenses: |  |  |  |  |
Refining (b) | 954 |  |  | 930 |  |  | 24 |
Retail | — |  |  | 178 |  |  | (178 | )
Ethanol | 102 |  |  | 76 |  |  | 26 |
General and administrative expenses | 170 |  |  | 174 |  |  | (4 | )
Depreciation and amortization expense: |  |  |  |  |
Refining | 426 |  |  | 345 |  |  | 81 |
Retail | — |  |  | 32 |  |  | (32 | )
Ethanol | 11 |  |  | 12 |  |  | (1 | )
Corporate | 11 |  |  | 13 |  |  | (2 | )
Asset impairment losses (c) | — |  |  | 345 |  |  | (345 | )
Total costs and expenses | 35,605 |  |  | 33,417 |  |  | 2,188 |
Operating income | 532 |  |  | 1,309 |  |  | (777 | )
Other income (expense), net | 17 |  |  | (2 | ) |  | 19 |
Interest and debt expense, net of capitalized interest | (102 | ) |  | (70 | ) |  | (32 | )
Income before income tax expense | 447 |  |  | 1,237 |  |  | (790 | )
Income tax expense | 123 |  |  | 564 |  |  | (441 | )
Net income | 324 |  |  | 673 |  |  | (349 | )
Less: Net income (loss) attributable to noncontrolling interests | 12 |  |  | (1 | ) |  | 13 |
Net income attributable to Valero stockholders | $ | 312 |  |  | $ | 674 |  |  | $ | (362 | )
Earnings per common share – assuming dilution | $ | 0.57 |  |  | $ | 1.21 |  |  | $ | (0.64 | )

________________
See note references on page 45.
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Refining Operating Highlights
(millions of dollars, except per barrel amounts)

| Three Months Ended September 30,
| 2013 |  | 2012 |  | Change
Refining (b) (c): |  |  |  |  |
Operating income | $ | 600 |  |  | $ | 1,528 |  |  | $ | (928 | )
Throughput margin per barrel (e) | $ | 7.76 |  |  | $ | 13.12 |  |  | $ | (5.36 | )
Operating costs per barrel: |  |  |  |  |
Operating expenses | 3.74 |  |  | 3.72 |  |  | 0.02 |
Depreciation and amortization expense | 1.67 |  |  | 1.45 |  |  | 0.22 |
Total operating costs per barrel | 5.41 |  |  | 5.17 |  |  | 0.24 |
Operating income per barrel | $ | 2.35 |  |  | $ | 7.95 |  |  | $ | (5.60 | )
Throughput volumes (thousand barrels per day): |  |  |  |  |
Feedstocks: |  |  |  |  |
Heavy sour crude | 464 |  |  | 464 |  |  | — |
Medium/light sour crude | 453 |  |  | 483 |  |  | (30 | )
Sweet crude | 1,096 |  |  | 1,038 |  |  | 58 |
Residuals | 344 |  |  | 204 |  |  | 140 |
Other feedstocks | 107 |  |  | 130 |  |  | (23 | )
Total feedstocks | 2,464 |  |  | 2,319 |  |  | 145 |
Blendstocks and other | 308 |  |  | 281 |  |  | 27 |
Total throughput volumes | 2,772 |  |  | 2,600 |  |  | 172 |
Yields (thousand barrels per day): |  |  |  |  |
Gasolines and blendstocks | 1,328 |  |  | 1,262 |  |  | 66 |
Distillates | 1,047 |  |  | 902 |  |  | 145 |
Other products (f) | 428 |  |  | 458 |  |  | (30 | )
Total yields | 2,803 |  |  | 2,622 |  |  | 181 |

_______________
See note references on page 45.
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Refining Operating Highlights by Region (g)
(millions of dollars, except per barrel amounts)

| Three Months Ended September 30,
| 2013 |  | 2012 |  | Change
U.S. Gulf Coast (b) (c): |  |  |  |  |
Operating income | $ | 350 |  |  | $ | 755 |  |  | $ | (405 | )
Throughput volumes (thousand barrels per day) | 1,560 |  |  | 1,415 |  |  | 145 |
Throughput margin per barrel (e) | $ | 7.88 |  |  | $ | 11.05 |  |  | $ | (3.17 | )
Operating costs per barrel: |  |  |  |  |
Operating expenses | 3.69 |  |  | 3.75 |  |  | (0.06 | )
Depreciation and amortization expense | 1.75 |  |  | 1.50 |  |  | 0.25 |
Total operating costs per barrel | 5.44 |  |  | 5.25 |  |  | 0.19 |
Operating income per barrel | $ | 2.44 |  |  | $ | 5.80 |  |  | $ | (3.36 | )
U.S. Mid-Continent: |  |  |  |  |
Operating income | $ | 153 |  |  | $ | 708 |  |  | $ | (555 | )
Throughput volumes (thousand barrels per day) | 441 |  |  | 452 |  |  | (11 | )
Throughput margin per barrel (e) | $ | 9.22 |  |  | $ | 22.07 |  |  | $ | (12.85 | )
Operating costs per barrel: |  |  |  |  |
Operating expenses | 3.67 |  |  | 3.56 |  |  | 0.11 |
Depreciation and amortization expense | 1.77 |  |  | 1.47 |  |  | 0.30 |
Total operating costs per barrel | 5.44 |  |  | 5.03 |  |  | 0.41 |
Operating income per barrel | $ | 3.78 |  |  | $ | 17.04 |  |  | $ | (13.26 | )
North Atlantic: |  |  |  |  |
Operating income | $ | 175 |  |  | $ | 384 |  |  | $ | (209 | )
Throughput volumes (thousand barrels per day) | 495 |  |  | 453 |  |  | 42 |
Throughput margin per barrel (e) | $ | 7.86 |  |  | $ | 13.25 |  |  | $ | (5.39 | )
Operating costs per barrel: |  |  |  |  |
Operating expenses | 3.06 |  |  | 3.21 |  |  | (0.15 | )
Depreciation and amortization expense | 0.97 |  |  | 0.84 |  |  | 0.13 |
Total operating costs per barrel | 4.03 |  |  | 4.05 |  |  | (0.02 | )
Operating income per barrel | $ | 3.83 |  |  | $ | 9.20 |  |  | $ | (5.37 | )
U.S. West Coast: |  |  |  |  |
Operating income (loss) | $ | (78 | ) |  | $ | 55 |  |  | $ | (133 | )
Throughput volumes (thousand barrels per day) | 276 |  |  | 280 |  |  | (4 | )
Throughput margin per barrel (e) | $ | 4.60 |  |  | $ | 8.91 |  |  | $ | (4.31 | )
Operating costs per barrel: |  |  |  |  |
Operating expenses | 5.39 |  |  | 4.63 |  |  | 0.76 |
Depreciation and amortization expense | 2.28 |  |  | 2.15 |  |  | 0.13 |
Total operating costs per barrel | 7.67 |  |  | 6.78 |  |  | 0.89 |
Operating income (loss) per barrel | $ | (3.07 | ) |  | $ | 2.13 |  |  | $ | (5.20 | )
Operating income for regions above | $ | 600 |  |  | $ | 1,902 |  |  | $ | (1,302 | )
Severance expense (b) | — |  |  | (41 | ) |  | 41 |
Asset impairment losses (c) | — |  |  | (333 | ) |  | 333 |
Total refining operating income | $ | 600 |  |  | $ | 1,528 |  |  | $ | (928 | )

_______________
See note references on page 45.
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Average Market Reference Prices and Differentials
(dollars per barrel, except as noted)

| Three Months Ended September 30,
| 2013 |  | 2012 |  | Change
Feedstocks: |  |  |  |  |
Brent crude oil | $ | 109.69 |  |  | $ | 109.48 |  |  | $ | 0.21 |
Brent less West Texas Intermediate (WTI) crude oil | 3.86 |  |  | 17.30 |  |  | (13.44 | )
Brent less Alaska North Slope (ANS) crude oil | (1.28 | ) |  | 0.66 |  |  | (1.94 | )
Brent less Louisiana Light Sweet (LLS) crude oil | (1.72 | ) |  | (1.06 | ) |  | (0.66 | )
Brent less Mars crude oil | 3.44 |  |  | 4.13 |  |  | (0.69 | )
Brent less Maya crude oil | 10.21 |  |  | 11.89 |  |  | (1.68 | )
LLS crude oil | 111.41 |  |  | 110.54 |  |  | 0.87 |
LLS less Mars crude oil | 5.16 |  |  | 5.19 |  |  | (0.03 | )
LLS less Maya crude oil | 11.93 |  |  | 12.95 |  |  | (1.02 | )
WTI crude oil | 105.83 |  |  | 92.18 |  |  | 13.65 |
Natural gas (dollars per million British thermal units) | 3.55 |  |  | 2.87 |  |  | 0.68 |
Products: |  |  |  |  |
U.S. Gulf Coast: |  |  |  |  |
CBOB gasoline less Brent | 3.97 |  |  | 9.33 |  |  | (5.36 | )
Ultra-low-sulfur diesel less Brent | 16.86 |  |  | 19.60 |  |  | (2.74 | )
Propylene less Brent | (5.18 | ) |  | (41.82 | ) |  | 36.64 |
CBOB gasoline less LLS | 2.25 |  |  | 8.27 |  |  | (6.02 | )
Ultra-low-sulfur diesel less LLS | 15.14 |  |  | 18.54 |  |  | (3.40 | )
Propylene less LLS | (6.90 | ) |  | (42.88 | ) |  | 35.98 |
U.S. Mid-Continent: |  |  |  |  |
CBOB gasoline less WTI (d) | 14.46 |  |  | 34.33 |  |  | (19.87 | )
Ultra-low-sulfur diesel less WTI | 22.86 |  |  | 39.47 |  |  | (16.61 | )
North Atlantic: |  |  |  |  |
CBOB gasoline less Brent | 10.99 |  |  | 15.89 |  |  | (4.90 | )
Ultra-low-sulfur diesel less Brent | 18.11 |  |  | 21.16 |  |  | (3.05 | )
U.S. West Coast: |  |  |  |  |
CARBOB 87 gasoline less ANS | 10.70 |  |  | 19.63 |  |  | (8.93 | )
CARB diesel less ANS | 17.98 |  |  | 22.90 |  |  | (4.92 | )
CARBOB 87 gasoline less WTI | 15.84 |  |  | 36.27 |  |  | (20.43 | )
CARB diesel less WTI | 23.12 |  |  | 39.54 |  |  | (16.42 | )
New York Harbor corn crush (dollars per gallon) | 0.64 |  |  | (0.27 | ) |  | 0.91 |

_______________
See note references on page 45.
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Retail and Ethanol Operating Highlights
(millions of dollars, except per gallon amounts)

| Three Months Ended September 30,
| 2013 |  | 2012 |  | Change
Retail: |  |  |  |  |
Operating income (a) (c) | $ | — |  |  | $ | 41 |  |  | $ | (41 | )
Ethanol: |  |  |  |  |
Operating income (loss) | $ | 113 |  |  | $ | (73 | ) |  | $ | 186 |
Production (thousand gallons per day) | 3,376 |  |  | 2,384 |  |  | 992 |
Gross margin per gallon of production (e) | $ | 0.73 |  |  | $ | 0.06 |  |  | $ | 0.67 |
Operating costs per gallon of production: |  |  |  |  |
Operating expenses | 0.33 |  |  | 0.34 |  |  | (0.01 | )
Depreciation and amortization expense | 0.04 |  |  | 0.05 |  |  | (0.01 | )
Total operating costs per gallon of production | 0.37 |  |  | 0.39 |  |  | (0.02 | )
Operating income (loss) per gallon of production | $ | 0.36 |  |  | $ | (0.33 | ) |  | $ | 0.69 |

_______________
See note references below.
The following notes relate to references on pages 41 through 45.

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

(b) | In September 2012, we decided to reorganize our Aruba Refinery into a crude oil and refined products terminal. These terminal operations require a considerably smaller workforce; therefore, the reorganization resulted in the termination of the majority of our employees in Aruba, and we recognized severance expense of $41 million in the third quarter of 2012. This expense is reflected in refining segment operating income for the three months ended September 30, 2012, but it is excluded from operating costs per barrel for the refining segment and the U.S. Gulf Coast region. No income tax benefits were recognized related to this severance expense.

(c) | Asset impairment losses for the three months ended September 30, 2012 include a $333 million loss on the write-down of the Aruba Refinery, which resulted from our decision in March 2012 to suspend refining operations at the refinery. Subsequently, in September 2012, we suspended refining operations indefinitely and reorganized the refinery into a crude oil and refined products terminal; however, we continue to maintain the refining assets to allow them to be restarted and do not consider them abandoned. We also recognized asset impairment losses of $12 million ($8 million after taxes) related to certain retail stores in the third quarter of 2012. The total asset impairment losses of $345 million are reflected in the operating income of the respective segments for the three months ended September 30, 2012, but the asset impairment loss associated with the Aruba Refinery is excluded from the operating costs per barrel and operating income per barrel for the refining segment and the U.S. Gulf Coast region.

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

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(e) | 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.

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

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

General
Operating revenues increased $1.4 billion (or 4 percent) in the third quarter of 2013 compared to the third quarter of 2012 primarily as a result of a 7 percent increase in throughput volumes between the two periods related to our refining segment operations. Operating income decreased $777 million in the third quarter of 2013 compared to the third quarter of 2012 primarily due to a $928 million decrease in refining segment operating income and a $41 million decrease in retail segment operating income. These decreases in operating income, however, were partially offset by a $186 million increase in ethanol 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 decreased $928 million from $1.5 billion in the third quarter of 2012 to $600 million in the third quarter of 2013. Excluding the $333 million in asset impairment losses in the third quarter of 2012 primarily related to our Aruba Refinery, which is more fully described in Note 3 of Condensed Notes to Consolidated Financial Statements, and severance expense of $41 million, which was also related to our Aruba Refinery (as further discussed in Note 6 of Condensed Notes to Consolidated Financial Statements), refining segment operating income decreased $1.3 billion, primarily due to a $1.2 billion decrease in refining margin, a $24 million increase in operating expenses, and an $81 million increase in depreciation and amortization expense.
Refining margin decreased $1.2 billion (a $5.36 per barrel decrease) for the third quarter of 2013 compared to the third quarter of 2012 primarily due to the following:

• | Decrease in gasoline and distillate margins - We experienced a decline in gasoline and distillate margins throughout all our regions during the third quarter of 2013 compared to the third quarter of 2012. For example, the WTI-based benchmark reference margin for U.S. Mid-Continent CBOB gasoline was $14.46 per barrel during the third quarter of 2013 compared to $34.33 per barrel during the third quarter of 2012, representing an unfavorable decrease of $19.87 per barrel. In addition the WTI-based benchmark reference margin for U.S. Mid-Continent ultra-low-sulfur diesel (a type of distillate) was $22.86 per barrel during the third quarter of 2013 compared to $39.47 per barrel during the third quarter of 2012, representing an unfavorable decrease of $16.61 per barrel. We estimate that the declines in gasoline and distillate margins per barrel during the third quarter of 2013 compared to the third quarter of 2012 had a negative impact to our refining margin of approximately $604 million and $37 million, respectively, for all refining regions.

• | Lower 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 third quarter of 2013, the discount in the price of light sweet crude oils and sour crude oils compared to the price of Brent crude oil narrowed significantly. For example, WTI crude oil processed in our Mid-Continent region, which

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is a light sweet crude oil, sold at a discount of $3.86 per barrel to Brent crude oil during the third quarter of 2013 compared to a discount of $17.30 per barrel during the third quarter of 2012, representing an unfavorable decrease of $13.44 per barrel. Another example is Maya crude oil, which is a sour crude oil, which sold at a discount of $10.21 per barrel to Brent crude oil during the third quarter of 2013 compared to a discount of $11.89 per barrel during the third quarter of 2012, representing an unfavorable decrease of $1.68 per barrel.Therefore, the lower discounts on the light sweet crude oils and the sour crude oils we processed negatively impacted our refining margin. We estimate that the decrease in the discounts for light sweet crude oils and sour crude oils that we processed had a negative impact to our refining margin of approximately $338 million and $100 million, respectively, quarter versus quarter.

• | Higher costs of biofuel credits - As more fully described in Note 13 of Condensed Notes to Consolidated Financial Statements, we must purchase biofuel credits in order to meet our biofuel blending obligations under various government and regulatory compliance programs, and the cost of these credits (primarily RINs in the U.S.) increased by $115 million from $72 million in the third quarter of 2012 to $187 million in the third quarter of 2013. This increase was due to an increase in the market price of RINs caused by an expectation in the market at that time of a shortage in available RINs by early next year.

The increase of $24 million in operating expenses was primarily due to a $38 million increase in energy costs related to higher natural gas prices and higher refinery utilization, a $16 million increase primarily due to property tax expense, and an $8 million increase in costs associated with the joint venture biodiesel plant at our St. Charles Refinery which began operations in June 2013. These increases were partially offset by a $41 million decrease in operating expenses due to the absence of severance expense recognized in the third quarter of 2012 by our Aruba Refinery.
The increase of $81 million in depreciation and amortization expense was due to additional depreciation expense associated with new capital projects that began operating subsequent to the third quarter of 2012, consisting primarily of the new hydrocracker at our Port Arthur Refinery that began operating in late 2012, and the new hydrocracker at our St. Charles Refinery that began operating in July 2013 and an increase in refinery turnaround and catalyst amortization.
Retail
Due to the separation of our retail business on May 1, 2013 as discussed in Note 2 of Condensed Notes to Consolidated Financial Statements, there was no retail segment operating income in the third quarter of 2013. Retail segment operating income was $41 million for the third quarter of 2012.
Ethanol
Ethanol segment operating income was $113 million in the third quarter of 2013 compared to an operating loss of $73 million in the third quarter of 2012. The $186 million increase in operating income was primarily due to a $211 million increase in gross margin (a $0.67 per gallon increase), partially offset by a $26 million increase in operating expenses.
Gross margin increased due to lower corn prices and higher production volumes for the third quarter of 2013 compared to the third quarter of 2012. Gross margin was $0.73 per gallon for the third quarter of 2013 compared to $0.06 per gallon for the third quarter of 2012. Corn prices decreased quarter over quarter as many of the corn-producing regions of the U.S. Mid-Continent recovered from the drought that began in the second quarter of 2012. For example, the CBOT corn price was $5.13 per bushel in the third quarter of 2013 compared to $7.81 per bushel in the third quarter of 2012. In addition to the decrease in corn prices, gross margin improved due to higher production volumes quarter over quarter as we increased production in response to the improved gross margin per gallon.
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The $26 million increase in operating expenses during the third quarter of 2013 was due to a $15 million increase in energy costs primarily resulting from higher natural gas prices and a $10 million increase in chemical costs during the third quarter of 2013 due to higher production.
Corporate Expenses and Other
“Interest and debt expense, net of capitalized interest” for the third quarter of 2013 increased $32 million from the third quarter of 2012. This increase was primarily due to a $43 million decrease in capitalized interest due to completion of several large capital projects including the new hydrocrackers at our Port Arthur and St. Charles Refineries, partially offset by a $9 million favorable impact from the decrease in average borrowings between the quarters.
Income tax expense decreased $441 million from the third quarter of 2012 to the third quarter of 2013 mainly as a result of lower income before income tax expense and a $22 million decrease related to a reduction in the United Kingdom’s income tax rate. The variation in the customary relationship between income tax expense and income before income tax expense for the third quarter of 2012 was primarily due to not recognizing the tax benefits associated with the asset impairment loss of $333 million and the severance loss of $41 million recognized in the third quarter of 2012 related to the Aruba Refinery as we did not expect to realize a tax benefit from those losses.
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Financial Highlights
(millions of dollars, except per share amounts)

| Nine Months Ended September 30,
| 2013 (a) |  | 2012 |  | Change
Operating revenues | $ | 103,645 |  |  | $ | 104,555 |  |  | $ | (910 | )
Costs and expenses: |  |  |  |  |
Cost of sales | 96,139 |  |  | 95,968 |  |  | 171 |
Operating expenses: |  |  |  |  |
Refining (b) | 2,736 |  |  | 2,762 |  |  | (26 | )
Retail | 226 |  |  | 514 |  |  | (288 | )
Ethanol | 281 |  |  | 248 |  |  | 33 |
General and administrative expenses | 579 |  |  | 509 |  |  | 70 |
Depreciation and amortization expense: |  |  |  |  |
Refining | 1,153 |  |  | 1,020 |  |  | 133 |
Retail | 41 |  |  | 88 |  |  | (47 | )
Ethanol | 33 |  |  | 32 |  |  | 1 |
Corporate | 56 |  |  | 32 |  |  | 24 |
Asset impairment losses (c) | — |  |  | 956 |  |  | (956 | )
Total costs and expenses | 101,244 |  |  | 102,129 |  |  | (885 | )
Operating income | 2,401 |  |  | 2,426 |  |  | (25 | )
Other income (expense), net | 42 |  |  | (1 | ) |  | 43 |
Interest and debt expense, net of capitalized interest | (263 | ) |  | (243 | ) |  | (20 | )
Income before income tax expense | 2,180 |  |  | 2,182 |  |  | (2 | )
Income tax expense | 739 |  |  | 1,111 |  |  | (372 | )
Net income | 1,441 |  |  | 1,071 |  |  | 370 |
Less: Net income (loss) attributable to noncontrolling interests | 9 |  |  | (2 | ) |  | 11 |
Net income attributable to Valero stockholders | $ | 1,432 |  |  | $ | 1,073 |  |  | $ | 359 |
Earnings per common share – assuming dilution | $ | 2.61 |  |  | $ | 1.93 |  |  | $ | 0.68 |

_______________
See note references on page 53.
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Refining Operating Highlights
(millions of dollars, except per barrel amounts)

| Nine Months Ended September 30,
| 2013 |  | 2012 |  | Change
Refining (b) (c): |  |  |  |  |
Operating income | $ | 2,733 |  |  | $ | 2,773 |  |  | $ | (40 | )
Throughput margin per barrel (e) | $ | 9.16 |  |  | $ | 10.51 |  |  | $ | (1.35 | )
Operating costs per barrel: |  |  |  |  |
Operating expenses | 3.78 |  |  | 3.81 |  |  | (0.03 | )
Depreciation and amortization expense | 1.60 |  |  | 1.43 |  |  | 0.17 |
Total operating costs per barrel | 5.38 |  |  | 5.24 |  |  | 0.14 |
Operating income per barrel | $ | 3.78 |  |  | $ | 5.27 |  |  | $ | (1.49 | )
Throughput volumes (thousand barrels per day): |  |  |  |  |
Feedstocks: |  |  |  |  |
Heavy sour crude | 482 |  |  | 435 |  |  | 47 |
Medium/light sour crude | 445 |  |  | 549 |  |  | (104 | )
Sweet crude | 1,027 |  |  | 1,005 |  |  | 22 |
Residuals | 295 |  |  | 196 |  |  | 99 |
Other feedstocks | 103 |  |  | 132 |  |  | (29 | )
Total feedstocks | 2,352 |  |  | 2,317 |  |  | 35 |
Blendstocks and other | 297 |  |  | 287 |  |  | 10 |
Total throughput volumes | 2,649 |  |  | 2,604 |  |  | 45 |
Yields (thousand barrels per day): |  |  |  |  |
Gasolines and blendstocks | 1,269 |  |  | 1,249 |  |  | 20 |
Distillates | 956 |  |  | 911 |  |  | 45 |
Other products (f) | 450 |  |  | 465 |  |  | (15 | )
Total yields | 2,675 |  |  | 2,625 |  |  | 50 |

_______________
See note references on page 53.
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Refining Operating Highlights by Region (g)
(millions of dollars, except per barrel amounts)

| Nine Months Ended September 30,
| 2013 |  | 2012 |  | Change
U.S. Gulf Coast (b) (c): |  |  |  |  |
Operating income | $ | 1,355 |  |  | $ | 1,627 |  |  | $ | (272 | )
Throughput volumes (thousand barrels per day) | 1,505 |  |  | 1,460 |  |  | 45 |
Throughput margin per barrel (e) | $ | 8.62 |  |  | $ | 9.14 |  |  | $ | (0.52 | )
Operating costs per barrel: |  |  |  |  |  |
Operating expenses | 3.69 |  |  | 3.60 |  |  | 0.09 |
Depreciation and amortization expense | 1.63 |  |  | 1.47 |  |  | 0.16 |
Total operating costs per barrel (b) (c) | 5.32 |  |  | 5.07 |  |  | 0.25 |
Operating income per barrel | $ | 3.30 |  |  | $ | 4.07 |  |  | $ | (0.77 | )
U.S. Mid-Continent: |  |  |  |  |
Operating income | $ | 973 |  |  | $ | 1,406 |  |  | $ | (433 | )
Throughput volumes (thousand barrels per day) | 429 |  |  | 418 |  |  | 11 |
Throughput margin per barrel (e) | $ | 13.52 |  |  | $ | 18.02 |  |  | $ | (4.50 | )
Operating costs per barrel: |  |  |  |  |  |
Operating expenses | 3.58 |  |  | 4.25 |  |  | (0.67 | )
Depreciation and amortization expense | 1.64 |  |  | 1.50 |  |  | 0.14 |
Total operating costs per barrel | 5.22 |  |  | 5.75 |  |  | (0.53 | )
Operating income per barrel | $ | 8.30 |  |  | $ | 12.27 |  |  | $ | (3.97 | )
North Atlantic: |  |  |  |  |
Operating income | $ | 431 |  |  | $ | 617 |  |  | $ | (186 | )
Throughput volumes (thousand barrels per day) | 450 |  |  | 463 |  |  | (13 | )
Throughput margin per barrel (e) | $ | 7.88 |  |  | $ | 8.95 |  |  | $ | (1.07 | )
Operating costs per barrel: |  |  |  |  |  |
Operating expenses | 3.38 |  |  | 3.32 |  |  | 0.06 |
Depreciation and amortization expense | 0.99 |  |  | 0.76 |  |  | 0.23 |
Total operating costs per barrel | 4.37 |  |  | 4.08 |  |  | 0.29 |
Operating income per barrel | $ | 3.51 |  |  | $ | 4.87 |  |  | $ | (1.36 | )
U.S. West Coast: |  |  |  |  |
Operating income (loss) | $ | (26 | ) |  | $ | 108 |  |  | $ | (134 | )
Throughput volumes (thousand barrels per day) | 265 |  |  | 263 |  |  | 2 |
Throughput margin per barrel (e) | $ | 7.30 |  |  | $ | 8.94 |  |  | $ | (1.64 | )
Operating costs per barrel: |  |  |  |  |  |
Operating expenses | 5.31 |  |  | 5.16 |  |  | 0.15 |
Depreciation and amortization expense | 2.34 |  |  | 2.28 |  |  | 0.06 |
Total operating costs per barrel | 7.65 |  |  | 7.44 |  |  | 0.21 |
Operating income (loss) per barrel | $ | (0.35 | ) |  | $ | 1.50 |  |  | $ | (1.85 | )
Operating income for regions above | $ | 2,733 |  |  | $ | 3,758 |  |  | $ | (1,025 | )
Severance expense (b) | — |  |  | (41 | ) |  | 41 |
Asset impairment losses (c) | — |  |  | (944 | ) |  | 944 |
Total refining operating income | $ | 2,733 |  |  | $ | 2,773 |  |  | $ | (40 | )

_______________
See note references on page 53.
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Average Market Reference Prices and Differentials
(dollars per barrel, except as noted)

| Nine Months Ended September 30,
| 2013 |  | 2012 |  | Change
Feedstocks: |  |  |  |  |
Brent crude oil | $ | 108.56 |  |  | $ | 112.26 |  |  | $ | (3.70 | )
Brent less WTI crude oil | 10.45 |  |  | 16.09 |  |  | (5.64 | )
Brent less ANS crude oil | 0.04 |  |  | 0.22 |  |  | (0.18 | )
Brent less LLS crude oil | (2.00 | ) |  | (0.95 | ) |  | (1.05 | )
Brent less Mars crude oil | 3.10 |  |  | 3.58 |  |  | (0.48 | )
Brent less Maya crude oil | 8.45 |  |  | 10.36 |  |  | (1.91 | )
LLS crude oil | 110.56 |  |  | 113.21 |  |  | (2.65 | )
LLS less Mars crude oil | 5.10 |  |  | 4.53 |  |  | 0.57 |
LLS less Maya crude oil | 10.45 |  |  | 11.31 |  |  | (0.86 | )
WTI crude oil | 98.11 |  |  | 96.17 |  |  | 1.94 |
Natural gas (dollars per million British thermal units) | 3.66 |  |  | 2.50 |  |  | 1.16 |
Products: |  |  |  |  |
U.S. Gulf Coast: |  |  |  |  |
CBOB gasoline less Brent | 5.39 |  |  | 7.34 |  |  | (1.95 | )
Ultra-low-sulfur diesel less Brent | 16.87 |  |  | 16.16 |  |  | 0.71 |
Propylene less Brent | (1.82 | ) |  | (21.56 | ) |  | 19.74 |
CBOB gasoline less LLS | 3.39 |  |  | 6.39 |  |  | (3.00 | )
Ultra-low-sulfur diesel less LLS | 14.87 |  |  | 15.21 |  |  | (0.34 | )
Propylene less LLS | (3.82 | ) |  | (22.51 | ) |  | 18.69 |
U.S. Mid-Continent: |  |  |  |  |
CBOB gasoline less WTI (d) | 21.47 |  |  | 26.65 |  |  | (5.18 | )
Ultra-low-sulfur diesel less WTI | 29.21 |  |  | 32.51 |  |  | (3.30 | )
North Atlantic: |  |  |  |  |
CBOB gasoline less Brent | 10.41 |  |  | 11.52 |  |  | (1.11 | )
Ultra-low-sulfur diesel less Brent | 18.33 |  |  | 17.71 |  |  | 0.62 |
U.S. West Coast: |  |  |  |  |
CARBOB 87 gasoline less ANS | 15.33 |  |  | 17.35 |  |  | (2.02 | )
CARB diesel less ANS | 18.81 |  |  | 18.76 |  |  | 0.05 |
CARBOB 87 gasoline less WTI | 25.74 |  |  | 33.22 |  |  | (7.48 | )
CARB diesel less WTI | 29.22 |  |  | 34.63 |  |  | (5.41 | )
New York Harbor corn crush (dollars per gallon) | 0.28 |  |  | (0.12 | ) |  | 0.40 |

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See note references on page 53.
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Retail and Ethanol Operating Highlights
(millions of dollars, except per gallon amounts)

| Nine Months Ended September 30,
| 2013 |  | 2012 |  | Change
Retail: |  |  |  |  |
Operating income (a) | $ | 81 |  |  | $ | 253 |  |  | $ | (172 | )
Ethanol: |  |  |  |  |
Operating income (loss) | $ | 222 |  |  | $ | (59 | ) |  | $ | 281 |
Production (thousand gallons per day) | 3,201 |  |  | 3,069 |  |  | 132 |
Gross margin per gallon of production (e) | $ | 0.61 |  |  | $ | 0.26 |  |  | $ | 0.35 |
Operating costs per gallon of production: |  |  |  |  |
Operating expenses | 0.32 |  |  | 0.29 |  |  | 0.03 |
Depreciation and amortization expense | 0.04 |  |  | 0.04 |  |  | — |
Total operating costs per gallon of production | 0.36 |  |  | 0.33 |  |  | 0.03 |
Operating income (loss) per gallon of production | $ | 0.25 |  |  | $ | (0.07 | ) |  | $ | 0.32 |

_______________
See note references below.
The following notes relate to references on pages 49 through 53.

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

(b) | In September 2012, we decided to reorganize our Aruba Refinery into a crude oil and refined products terminal. These terminal operations require a considerably smaller workforce; therefore, the reorganization resulted in the termination of the majority of our employees in Aruba,and we recognized severance expense of $41 million in the third quarter of 2012. This expense is reflected in refining segment operating income for the nine months ended September 30, 2012, but it is excluded from operating costs per barrel for the refining segment and the U.S. Gulf Coast region. No income tax benefits were recognized related to this severance expense.

(c) | Asset impairment losses for the nine months ended September 30, 2012 include a $928 million loss on the write-down of the Aruba Refinery, which resulted from our decision in March 2012 to suspend refining operations at the refinery. Subsequently, in September 2012, we suspended refining operations indefinitely and reorganized the refinery into a crude oil and refined products terminal; however, we continue to maintain the refining assets to allow them to be restarted and do not consider them abandoned. We also recognized asset impairment losses of $16 million ($10 million after taxes) related to equipment associated with a permanently cancelled capital project at another refinery and $12 million ($8 million after taxes) related to certain retail stores in the third quarter of 2012. The total asset impairment losses of $956 million are reflected in the operating income of the respective segments for the nine months ended September 30, 2012, but the asset impairment losses associated with the Aruba Refinery and the cancelled capital project are excluded from the operating costs per barrel and operating income per barrel for the refining segment and the U.S. Gulf Coast region.

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

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(e) | 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.

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

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

General
Operating revenues decreased $910 million (or 1 percent) in the first nine months of 2013 compared to the first nine months of 2012 primarily as a result of lower average refined product prices between the two periods related to our refining segment operations. In addition, operating income decreased $25 million in the first nine months of 2013 compared to the first nine months of 2012 primarily due to a $40 million decrease in refining segment operating income, a $172 million decrease in retail segment operating income, and a $70 million increase in general and administrative expenses, partially offset by a $281 million increase in ethanol segment operating income. The reasons for these changes in the operating results of our segments and general and administrative expenses, as well as other items that affected our income, are discussed below.
Refining
Refining segment operating income decreased $40 million from $2.8 billion in the first nine months of 2012 to $2.7 billion in the first nine months of 2013. Excluding the $944 million in asset impairment losses in the first nine months of 2012 primarily related to our Aruba Refinery, which is more fully described in Note 3 of Condensed Notes to Consolidated Financial Statements, refining segment operating income decreased $1.0 billion, primarily due to an $877 million decrease in refining margin and a $133 million increase in depreciation and amortization expense, partially offset by a $26 million decrease in operating expenses.
Refining margin decreased $877 million (a $1.35 per barrel decrease) in the first nine months of 2013 compared to the first nine months of 2012, primarily due to the following:

• | Lower discounts on light sweet 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 nine months of 2013, the discount in the price of light sweet crude oils compared to the price of Brent crude oil narrowed significantly. For example, WTI crude oil processed in our Mid-Continent region, which is a light sweet crude oil, sold at a discount of $10.45 per barrel to Brent crude oil in the first nine months of 2013 compared to a discount of $16.09 per barrel in the first nine months of 2012, representing an unfavorable decrease of $5.64 per barrel. Therefore, the lower discount on the light sweet crude oils we processed negatively impacted our refining margin. We estimate that the decrease in the discounts for light sweet crude oils that we processed during the first nine months of 2013 had a negative impact to our refining margin of approximately $480 million.

• | Higher costs of biofuel credits - As more fully described in Note 13 of Condensed Notes to Consolidated Financial Statements, we must purchase biofuel credits in order to meet our biofuel blending obligation under various government and regulatory compliance programs, and the cost of these credits (primarily RINs in the U.S.) increased by $256 million from $198 million for the first nine months of 2012 to $454 million in the first nine months of 2013. This increase was due to an increase in the market price of RINs caused by an expectation in the market at that time of a shortage in available RINs.

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The decrease of $26 million in operating expenses was primarily due to a $72 million decrease in operating expenses incurred by the Aruba Refinery, whose operations were suspended in March 2012, a $47 million decrease in maintenance expenses due to lower maintenance activities in 2013, $41 million of severance expense recognized in the third quarter of 2012 related to our Aruba Refinery that did not recur in the first nine months of 2013, and a $27 million decrease in insurance reserves related to the favorable settlement of a lawsuit. These decreases were partially offset by a $150 million increase in energy costs related to higher natural gas costs and higher refinery utilization.
The increase of $133 million in depreciation and amortization expense was due to additional depreciation expense associated with new capital projects that began operating subsequent to the third quarter of 2012, consisting primarily of the new hydrocracker at our Port Arthur Refinery that began operating in late 2012, and the new hydrocracker at our St. Charles Refinery that began operating during the third quarter of 2013 and an increase in refinery turnaround and catalyst amortization.
Retail
Retail segment operating income was $81 million for the first nine months of 2013 compared to $253 million for the first nine months of 2012. The $172 million decrease was primarily due to the separation of our retail business on May 1, 2013, which is more fully described in Note 2 of Notes to Consolidated Financial Statements. As a result of the separation, retail segment operating income for the first nine months of 2013 reflects the operations of our former retail business for only the first four months of 2013.
Ethanol
Ethanol segment operating income was $222 million for the first nine months of 2013 compared to an operating loss of $59 million for the first nine months of 2012. The $281 million increase in operating income was primarily due to a $315 million increase in gross margin (a $0.35 per gallon increase), partially offset by a $33 million increase in operating expenses.
Gross margin increased primarily due to higher ethanol prices between the first nine months of 2012 and the first nine months of 2013. Gross margin per gallon was $0.61 per gallon for the first nine months of 2013 compared to $0.26 per gallon for the first nine months of 2012. Ethanol prices increased period over period due to a decrease in the supply of ethanol in the market. The decrease in supply resulted from reduced production in 2012 and early 2013 as the industry responded to a narrowing of gross margins, which were due to higher corn prices primarily caused by the drought in the corn-producing regions of the U.S. Mid-Continent that began in the second quarter of 2012. By the first quarter of 2013, ethanol inventory levels in the U.S. had declined to their lowest level in over three years and as a result, prices increased significantly beginning late in the first quarter of 2013. These price increases and increased demand resulted in higher industry production volumes. In addition, our ethanol production increased 132,000 gallons per day in the first nine months of 2013 compared to the first nine months of 2012.
The $33 million increase in operating expenses during the first nine months of 2013 compared to the first nine months of 2012 was primarily due to an increase in energy costs compared to the first nine months of 2012 resulting from the higher natural gas prices during the first nine months of 2013.
Corporate Expenses and Other
General and administrative expenses increased $70 million from the first nine months of 2012 to the first nine months of 2013 primarily due to $40 million of environmental and legal reserve adjustments that were recorded during the first nine months of 2013 and $30 million for transaction costs related to the separation of our retail business on May 1, 2013. The increase in corporate depreciation and amortization expense was primarily due to $20 million of losses incurred on the sale of certain corporate property.
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“Interest and debt expense, net of capitalized interest” for the first nine months of 2013 increased $20 million from the first nine months of 2012. This increase was primarily due to a $63 million decrease in capitalized interest due to completion of several large capital projects including the new hydrocrackers at our Port Arthur and St. Charles Refineries, offset by a $35 million favorable impact from the decrease in average borrowings and a $12 million write-off of unamortized debt discounts related to the early redemption of certain industrial revenue bonds in the first quarter of 2012.
Income tax expense decreased $372 million from the first nine months of 2012 to the first nine months of 2013. The variation in the customary relationship between income tax expense and income before income tax expense for the nine months ended September 30, 2012 was primarily due to not recognizing the tax benefits associated with the asset impairment loss of $928 million and the severance expense of $41 million related to the Aruba Refinery as we did not expect to realize a tax benefit from these losses.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows for the Nine Months Ended September 30, 2013 and 2012
Net cash provided by operating activities for the first nine months of 2013 of $3.0 billion was generated primarily from operating income discussed above under “RESULTS OF OPERATIONS.” Net cash provided by operating activities for the first nine months of 2012 was $4.9 billion and was generated from operating income, excluding the asset impairment losses, combined with favorable changes in current assets and current liabilities. The changes in cash provided by or used in working capital during the first nine months of 2013 and 2012 are shown in Note 11 of Condensed Notes to Consolidated Financial Statements.
The net cash provided by operating activities 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 $2.2 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 $589 million;

• | pay common stock dividends of $342 million; and

• | increase available cash on hand by $185 million.

The net cash provided by operating activities during the first nine months of 2012 combined with $160 million of proceeds on a note receivable related to the sale of the Paulsboro Refinery, $300 million of proceeds from the remarketing of the 4.0% Gulf Opportunity Zone Revenue Bonds Series 2010, $1.1 billion in borrowings under our revolving credit facility, and $1.5 billion of proceeds from the sale of receivables under our accounts receivable sales facility were used mainly to:

• | fund $2.5 billion of capital expenditures and deferred turnaround and catalyst costs;

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

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

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

• | make a repayment under our accounts receivable sales facility of $1.7 billion;

• | purchase common stock for treasury of $148 million;

• | pay common stock dividends of $263 million; and

• | increase available cash on hand by $1.5 billion.

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Capital Investments
Our operations, especially those of our refining segment, are highly capital intensive. Each of our refineries comprises a large base of property assets, consisting of a series of interconnected, highly integrated and interdependent crude oil processing facilities and supporting logistical infrastructure (Units), and these Units are improved continuously. The cost of improvements, which consist of the addition of new Units and betterments of existing Units, can be significant. We have historically acquired our refineries at amounts significantly below their replacement costs, whereas our improvements are made at full replacement value. As such, the costs for improving our refinery assets increase over time and are significant in relation to the amounts we paid to acquire our refineries. We plan for these improvements by developing a multi-year capital program that is updated and revised based on changing internal and external factors.
We make improvements to our refineries in order to maintain and enhance their operating reliability, to meet environmental obligations with respect to reducing emissions and removing prohibited elements from the products we produce, or to enhance their profitability. Reliability and environmental improvements generally do not increase the throughput capacities of our refineries. Improvements that enhance refinery profitability may increase throughput capacity, but many of these improvements allow our refineries to process different types of crude oil and refine crude oil into products with higher market values. Therefore, many of our improvements do not increase throughput capacity significantly.
During the nine months ended September 30, 2013, we expended $1.7 billion for capital expenditures and $527 million for deferred turnaround and catalyst costs. Capital expenditures for the nine months ended September 30, 2013 included $55 million of costs related to environmental projects.
For 2013, we expect to incur approximately $2.85 billion for capital investments of which approximately $80 million is for environmental projects and approximately $650 million is for deferred turnaround and catalyst costs. The capital expenditure estimate excludes expenditures related to strategic business acquisitions. We continuously evaluate our capital budget and make changes as conditions warrant.
Contractual Obligations
As of September 30, 2013, our contractual obligations included debt, capital lease obligations, operating leases, purchase obligations, and other long-term liabilities. There were no material changes outside the ordinary course of our business with respect to these contractual obligations during the nine months ended September 30, 2013.
As of September 30, 2013, 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. In July 2013, we amended this facility to extend the maturity date to July 2014.
Our debt and financing agreements do not have rating agency triggers that would automatically require us to post additional collateral. However, in the event of certain downgrades of our senior unsecured debt to below investment grade ratings by Moody’s Investors Service, Standard & Poor’s Ratings Services, and Fitch Ratings, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. All of our ratings on our senior unsecured debt are at or above investment grade level as follows:

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

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We cannot provide assurance that these ratings will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell, or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction below investment grade or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing and the cost of such financings.
Other Commercial Commitments
As of September 30, 2013, we had outstanding letters of credit under our committed lines of credit as follows (in millions):

|  | Borrowing Capacity |  | Expiration |  | Outstanding Letters of Credit
Letter of credit facilities |  | $ | 550 |  |  | June 2014 |  | $ | 292 |
Revolving credit facility |  | $ | 3,000 |  |  | December 2016 |  | $ | 59 |
Canadian revolving credit facility |  | C$ | 50 |  |  | November 2013 |  | C$ | 10 |

As of September 30, 2013, we had no amounts borrowed under our revolving credit facilities. The letters of credit outstanding as of September 30, 2013 expire during 2013 and 2014. We anticipate that we will be able to renew our Canadian revolving credit facility prior to its expiration in November 2013.
Other Matters Impacting Liquidity and Capital Resources
Pension Plan Funded Status
In February 2013, we announced amendments to certain of our pension plans that reduced our benefit costs and obligations for 2013 and future years, as further discussed in Note 8 of Condensed Notes to Consolidated Financial Statements. As a result of these plan amendments, management reduced its discretionary contributions to our pension plans by $100 million, resulting in expected contributions to our pension plans of $45 million for 2013. In addition, we plan to contribute approximately $21 million to our other postretirement benefit plans during 2013.
Stock Purchase Programs
As of September 30, 2013, we have approvals under common stock purchase programs to purchase approximately $3.0 billion of our common stock.
Environmental Matters
Our operations are subject to extensive environmental regulations by governmental authorities relating to the discharge of materials into the environment, waste management, pollution prevention measures, greenhouse gas emissions, and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our operating facilities could require material additional expenditures to comply with environmental laws and regulations. See Note 6 of Condensed Notes to Consolidated Financial Statements for a further discussion of our environmental matters.
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Tax Matters
We currently believe that, beginning in 2014, the cash we will pay for income taxes will increase and that such amount may exceed the total income tax expense that will be reflected on our statement of income primarily due to an expected decrease in deductions that we will claim on our U.S. federal income tax return for depreciation on our property, plant and equipment. In prior years, the U.S. federal government enacted certain legislation that provided for the deduction of depreciation on an accelerated basis on newly built equipment as a means of encouraging capital investment by businesses. This legislation, however, generally does not extend beyond 2013. Although we expect the amount of cash required to pay our 2014 income taxes to increase compared to recent prior 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.
As of September 30, 2013, the Internal Revenue Service (IRS) has ongoing tax audits related to our U.S. federal tax returns from 2002 through 2011. We have received Revenue Agent Reports in connection with the 2002 through 2009 audits, and we are vigorously contesting certain tax positions and assertions from the IRS. We have made significant progress during the nine months ended September 30, 2013 in resolving certain of these matters with the IRS and have agreed to settle the audit related to the 2004 and 2005 tax years for a group of our subsidiaries. We expect to finalize the settlement agreement within the next six months for an amount consistent with the recorded amount of unrecognized tax benefits associated with that audit. We are continuing to work with the IRS to resolve the remaining matters and we believe that they will also be resolved for amounts that do not exceed the recorded amounts of unrecognized tax benefits associated with these matters. As of September 30, 2013, the total amount of unrecognized tax benefits was $378 million, with $8 million reflected in “income taxes payable” and $370 million reflected in “other long-term liabilities”, and this total amount did not change significantly during the nine months ended September 30, 2013. We do not believe that settlement agreements related to the remaining audits will be finalized and that cash will be paid to the IRS in connection with such settlements within the next 12 months, but the complexity of these matters makes it difficult to predict the timing of their resolution. 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 September 30, 2013, $1.2 billion of our cash and temporary cash investments was held by our international subsidiaries.
Financial Regulatory Reform
In July 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (Wall Street Reform Act). Key provisions of the Wall Street Reform Act create new statutory requirements that require most derivative instruments to be traded on exchanges and routed through clearinghouses, as well as impose new recordkeeping and reporting responsibilities on market participants. While certain final rules implementing the Wall Street Reform Act became effective in the fourth quarter of 2012, others continue to become effective in 2013 and 2014. Although we cannot predict the ultimate impact of these rules, which may result in higher clearing costs and more reporting requirements with respect to our derivative activities, we believe they will not have a material impact on our financial position, results of operations, or liquidity.
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Concentration of Customers
Our refining and marketing operations have a concentration of customers in the refining industry and customers who are refined product wholesalers and retailers. These concentrations of customers may impact our overall exposure to credit risk, either positively or negatively, in that these customers may be similarly affected by changes in economic or other conditions. However, we believe that our portfolio of accounts receivable is sufficiently diversified to the extent necessary to minimize potential credit risk. Historically, we have not had any significant problems collecting our accounts receivable.
Sources of Liquidity
We believe that we have sufficient funds from operations and, to the extent necessary, from borrowings under our credit facilities, to fund our ongoing operating requirements. We expect that, to the extent necessary, we can raise additional funds from time to time through equity or debt financings in the public and private capital markets or the arrangement of additional credit facilities. However, there can be no assurances regarding the availability of any future financings or additional credit facilities or whether such financings or additional credit facilities can be made available on terms that are acceptable to us.
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in accordance 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. Our critical accounting policies are disclosed in our annual report on Form 10-K for the year ended December 31, 2012.
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Item 3. | Quantitative and Qualitative Disclosures About Market Risk

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

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

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

We use the futures markets for the available liquidity, which provides greater flexibility in transacting our hedging and trading operations. We use swaps primarily to manage our price exposure. We also enter into certain commodity derivative instruments for trading purposes to take advantage of existing market conditions related to future results of operations and cash flows.
Our positions in commodity derivative instruments are monitored and managed on a daily basis by a risk control group to ensure compliance with our stated risk management policy that has been approved by our board of directors.
The following sensitivity analysis includes all positions at the end of the reporting period with which we have market risk (in millions):

| Derivative Instruments Held For
| Non-Trading Purposes |  | Trading Purposes
September 30, 2013: |  |  |
Gain (loss) in fair value resulting from: |  |  |
10% increase in underlying commodity prices | $ | (123 | ) |  | $ | (13 | )
10% decrease in underlying commodity prices | 123 |  |  | (2 | )
December 31, 2012: |  |  |
Gain (loss) in fair value resulting from: |  |  |
10% increase in underlying commodity prices | (131 | ) |  | (9 | )
10% decrease in underlying commodity prices | 135 |  |  | (1 | )

See Note 13 of Condensed Notes to Consolidated Financial Statements for notional volumes associated with these derivative contracts as of September 30, 2013.
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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 September 30, 2013 or December 31, 2012.

| September 30, 2013
| Expected Maturity Dates |  |  |  |
| 2013 |  | 2014 |  | 2015 |  | 2016 |  | 2017 |  | There- after |  | Total |  | Fair Value
Debt: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate | $ | — |  |  | $ | 200 |  |  | $ | 475 |  |  | $ | — |  |  | $ | 950 |  |  | $ | 4,824 |  |  | $ | 6,449 |  |  | $ | 7,445 |
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 | % |  |
| December 31, 2012
| Expected Maturity Dates |  |  |  |
| 2013 |  | 2014 |  | 2015 |  | 2016 |  | 2017 |  | There- after |  | Total |  | Fair Value
Debt: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate | $ | 480 |  |  | $ | 200 |  |  | $ | 475 |  |  | $ | — |  |  | $ | 950 |  |  | $ | 4,824 |  |  | $ | 6,929 |  |  | $ | 8,521 |
Average interest rate | 5.5 | % |  | 4.8 | % |  | 5.2 | % |  | — | % |  | 6.4 | % |  | 7.3 | % |  | 6.8 | % |  |
Floating rate | $ | 100 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 100 |  |  | $ | 100 |
Average interest rate | 0.9 | % |  | — | % |  | — | % |  | — | % |  | — | % |  | — | % |  | 0.9 | % |  |

FOREIGN CURRENCY RISK
As of September 30, 2013, we had commitments to purchase $845 million of U.S. dollars. Our market risk was minimal on these contracts, as they matured on or before October 31, 2013, resulting in an immaterial loss in the fourth quarter of 2013.
COMPLIANCE PROGRAM PRICE RISK
We are exposed to market risk related to the volatility in the price of credits needed to comply with various governmental and regulatory programs. We manage this risk by purchasing credits when prices are deemed favorable. See Note 13 of Condensed Notes to Consolidated Financial Statements for a discussion about these compliance programs.
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Item 4. Controls and Procedures

(a) | Evaluation of disclosure controls and procedures.

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

(b) | Changes in internal control over financial reporting.

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

Item 1. | Legal Proceedings

The information below describes new proceedings or material developments in proceedings that we previously reported in our annual report on Form 10-K for the year ended December 31, 2012, or our quarterly report on Form 10-Q for the quarters ended March 31, 2013 and June 30, 2013.
Litigation
We hereby incorporate by reference into this Item our disclosures made in Part I, Item 1 of this Report included in Note 6 of Condensed Notes to Consolidated Financial Statements under the caption “Litigation Matters.”
Environmental Enforcement Matters
While it is impossible to predict the outcome of the following environmental proceedings, if any one or more of them were decided against us, we believe that there would be no material effect on our financial position or results of operations. We are reporting these proceedings to comply with SEC regulations, which require us to disclose certain information about proceedings arising under federal, state, or local provisions regulating the discharge of materials in the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $100,000 or more.
EPA (McKee Refinery). In our quarterly report on Form 10-Q for the quarter ended June 30, 2013, we disclosed that our McKee Refinery had received a proposed penalty of $112,000 from the EPA relating to alleged violations under the EPA’s Risk Management Program. In the third quarter of 2013, we entered into a Consent Agreement and Final Order with the EPA to resolve this matter.
EPA (Fuels Enforcement). In the third quarter of 2013, we paid $350,000 to the EPA to settle and resolve alleged violations under the Clean Air Act and the EPA’s Renewable Fuel Standard. The settlement pertained to invalid RINs unlawfully sold to us by a third party. In addition to payment of the civil penalty, the settlement involved our adoption of certain protocols to minimize the risk of any future acquisition of invalid RINs.
EPA (Linden ethanol plant). In our annual report on Form 10-K for the year ended December 31, 2012, we disclosed that the EPA was seeking penalties in connection with alleged excess air emissions at our Linden,
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Indiana ethanol plant. In the third quarter of 2013, we entered into a Consent Agreement and Final Order with the EPA to resolve this matter.
Bay Area Air Quality Management District (BAAQMD) (Benicia Refinery and asphalt plant). In our annual report on Form 10-K for the year ended December 31, 2012, we reported that we had multiple outstanding violation notices (VNs) issued by the BAAQMD for alleged air regulation and air permit violations at our Benicia Refinery and asphalt plant. In the third quarter of 2013, we settled 33 VNs from 2011 and 2012.
Item 1A. Risk Factors
There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the year ended December 31, 2012.

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)
July 2013 | 1,532 |  | $ | 34.24 |  | 1,532 |  | — |  | $3.0 billion
August 2013 | 9,081 |  | $ | 35.90 |  | 9,081 |  | — |  | $3.0 billion
September 2013 | 801,136 |  | $ | 35.86 |  | 655,272 |  | 145,864 |  | $3.0 billion
Total | 811,749 |  | $ | 35.86 |  | 665,885 |  | 145,864 |  | $3.0 billion

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

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

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Item 6. Exhibits

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

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

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

Date: November 5, 2013
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