10-Q 1 vlo6301210q.htm VALERO ENERGY CORPORATION JUNE 30, 2012 FORM 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 June 30, 2012
OR

o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
| For the transition period from _______________ to _______________

Commission File Number 1-13175
VALERO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)

Delaware |  | 74-1828067
(State or other jurisdiction of |  | (I.R.S. Employer
incorporation or organization) |  | Identification No.)

One Valero Way
San Antonio, Texas
(Address of principal executive offices)
78249
(Zip Code)
(210) 345-2000
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes R No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer R | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No R
The number of shares of the registrant’s only class of common stock, $0.01 par value, outstanding as of July 31, 2012 was 551,605,943.

VALERO ENERGY CORPORATION AND SUBSIDIARIES
TABLE OF CONTENTS

| Page
PART I – FINANCIAL INFORMATION |
Item 1. Financial Statements |
Consolidated Balance Sheets as of June 30, 2012 and December 31, 201 1 | 3
Consolidated Statements of Income for the Three and Six Months Ended June 30, 2012 and 201 1 | 4
Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2012 and 2011 | 5
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2012 and 2011 | 6
Condensed Notes to Consolidated Financial Statements | 7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 35
Item 3. Quantitative and Qualitative Disclosures About Market Risk | 58
Item 4. Controls and Procedures | 60
PART II – OTHER INFORMATION |
Item 1. Legal Proceedings | 61
Item 1A. Risk Factors | 61
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 62
Item 6. Exhibits | 62
SIGNATURE | 63

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

| June 30, 2012 |  | December 31, 2011
| (Unaudited) |  |
ASSETS |  |  |
Current assets: |  |  |
Cash and temporary cash investments | $ | 1,295 |  |  | $ | 1,024 |
Receivables, net | 6,624 |  |  | 8,706 |
Inventories | 5,443 |  |  | 5,623 |
Income taxes receivable | 287 |  |  | 212 |
Deferred income taxes | 246 |  |  | 283 |
Prepaid expenses and other | 138 |  |  | 124 |
Total current assets | 14,033 |  |  | 15,972 |
Property, plant and equipment, at cost | 32,832 |  |  | 32,253 |
Accumulated depreciation | (7,311 | ) |  | (7,076 | )
Property, plant and equipment, net | 25,521 |  |  | 25,177 |
Intangible assets, net | 218 |  |  | 227 |
Deferred charges and other assets, net | 1,416 |  |  | 1,407 |
Total assets | $ | 41,188 |  |  | $ | 42,783 |
LIABILITIES AND EQUITY |  |  |
Current liabilities: |  |  |
Current portion of debt and capital lease obligations | $ | 582 |  |  | $ | 1,009 |
Accounts payable | 7,998 |  |  | 9,472 |
Accrued expenses | 527 |  |  | 595 |
Taxes other than income taxes | 1,334 |  |  | 1,264 |
Income taxes payable | 61 |  |  | 119 |
Deferred income taxes | 296 |  |  | 249 |
Total current liabilities | 10,798 |  |  | 12,708 |
Debt and capital lease obligations, less current portion | 6,460 |  |  | 6,732 |
Deferred income taxes | 5,411 |  |  | 5,017 |
Other long-term liabilities | 1,896 |  |  | 1,881 |
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 | 7,477 |  |  | 7,486 |
Treasury stock, at cost; 122,106,373 and 116,689,450 common shares | (6,568 | ) |  | (6,475 | )
Retained earnings | 15,542 |  |  | 15,309 |
Accumulated other comprehensive income | 119 |  |  | 96 |
Total Valero Energy Corporation stockholders’ equity | 16,577 |  |  | 16,423 |
Noncontrolling interest | 46 |  |  | 22 |
Total equity | 16,623 |  |  | 16,445 |
Total liabilities and equity | $ | 41,188 |  |  | $ | 42,783 |

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 June 30, |  | Six Months Ended June 30,
| 2012 |  | 2011 |  | 2012 |  | 2011
Operating revenues (a) | $ | 34,662 |  |  | $ | 31,293 |  |  | $ | 69,829 |  |  | $ | 57,601 |
Costs and expenses: |  |  |  |  |  |  |
Cost of sales | 31,621 |  |  | 28,380 |  |  | 64,656 |  |  | 52,948 |
Operating expenses: |  |  |  |  |  |  |
Refining | 868 |  |  | 813 |  |  | 1,832 |  |  | 1,557 |
Retail | 170 |  |  | 169 |  |  | 336 |  |  | 331 |
Ethanol | 85 |  |  | 104 |  |  | 172 |  |  | 199 |
General and administrative expenses | 171 |  |  | 151 |  |  | 335 |  |  | 281 |
Depreciation and amortization expense | 386 |  |  | 386 |  |  | 770 |  |  | 751 |
Asset impairment loss | — |  |  | — |  |  | 611 |  |  | — |
Total costs and expenses | 33,301 |  |  | 30,003 |  |  | 68,712 |  |  | 56,067 |
Operating income | 1,361 |  |  | 1,290 |  |  | 1,117 |  |  | 1,534 |
Other income (expense), net | (5 | ) |  | 10 |  |  | 1 |  |  | 27 |
Interest and debt expense, net of capitalized interest | (74 | ) |  | (107 | ) |  | (173 | ) |  | (224 | )
Income from continuing operations before income tax expense | 1,282 |  |  | 1,193 |  |  | 945 |  |  | 1,337 |
Income tax expense | 452 |  |  | 449 |  |  | 547 |  |  | 489 |
Income from continuing operations | 830 |  |  | 744 |  |  | 398 |  |  | 848 |
Loss from discontinued operations, net of income taxes | — |  |  | (1 | ) |  | — |  |  | (7 | )
Net income | 830 |  |  | 743 |  |  | 398 |  |  | 841 |
Less: Net loss attributable to noncontrolling interest | (1 | ) |  | (1 | ) |  | (1 | ) |  | (1 | )
Net income attributable to Valero Energy Corporation stockholders | $ | 831 |  |  | $ | 744 |  |  | $ | 399 |  |  | $ | 842 |
Net income attributable to Valero Energy Corporation stockholders: |  |  |  |  |  |  |
Continuing operations | $ | 831 |  |  | $ | 745 |  |  | $ | 399 |  |  | $ | 849 |
Discontinued operations | — |  |  | (1 | ) |  | — |  |  | (7 | )
Total | $ | 831 |  |  | $ | 744 |  |  | $ | 399 |  |  | $ | 842 |
Earnings per common share: |  |  |  |  |  |  |
Continuing operations | $ | 1.50 |  |  | $ | 1.31 |  |  | $ | 0.72 |  |  | $ | 1.49 |
Discontinued operations | — |  |  | — |  |  | — |  |  | (0.01 | )
Total | $ | 1.50 |  |  | $ | 1.31 |  |  | $ | 0.72 |  |  | $ | 1.48 |
Weighted-average common shares outstanding (in millions) | 550 |  |  | 567 |  |  | 550 |  |  | 567 |
Earnings per common share – assuming dilution: |  |  |  |  |  |  |
Continuing operations | $ | 1.50 |  |  | $ | 1.30 |  |  | $ | 0.72 |  |  | $ | 1.48 |
Discontinued operations | — |  |  | — |  |  | — |  |  | (0.01 | )
Total | $ | 1.50 |  |  | $ | 1.30 |  |  | $ | 0.72 |  |  | $ | 1.47 |
Weighted-average common shares outstanding – assuming dilution (in millions) | 555 |  |  | 574 |  |  | 556 |  |  | 573 |
Dividends per common share | $ | 0.15 |  |  | $ | 0.05 |  |  | $ | 0.30 |  |  | $ | 0.10 |

Supplemental information: |  |  |  |  |  |  |
(a) Includes excise taxes on sales by our U.S. retail system | $ | 241 |  |  | $ | 227 |  |  | $ | 475 |  |  | $ | 441 |

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 June 30, |  | Six Months Ended June 30,
| 2012 |  | 2011 |  | 2012 |  | 2011
Net income | $ | 830 |  |  | $ | 743 |  |  | $ | 398 |  |  | $ | 841 |
Other comprehensive income (loss): |  |  |  |  |  |  |
Foreign currency translation adjustment | (91 | ) |  | 20 |  |  | 32 |  |  | 112 |
Pension and other postretirement benefits: |  |  |  |  |  |  |
(Gain) loss reclassified into income related to: |  |  |  |  |  |  |
Prior service credit | (6 | ) |  | (5 | ) |  | (10 | ) |  | (10 | )
Net actuarial loss | 9 |  |  | 4 |  |  | 17 |  |  | 7 |
Net gain (loss) on pension and other postretirement benefits | 3 |  |  | (1 | ) |  | 7 |  |  | (3 | )
Derivative instruments designated and qualifying as cash flow hedges: |  |  |  |  |  |  |
Net gain (loss) arising during the period | (31 | ) |  | — |  |  | 16 |  |  | — |
Net (gain) loss reclassified into income | 12 |  |  | — |  |  | (36 | ) |  | — |
Loss on cash flow hedges | (19 | ) |  | — |  |  | (20 | ) |  | — |
Other comprehensive income (loss), before income tax benefit | (107 | ) |  | 19 |  |  | 19 |  |  | 109 |
Income tax benefit related to items of other comprehensive income (loss) | (5 | ) |  | — |  |  | (4 | ) |  | (1 | )
Other comprehensive income (loss) | (102 | ) |  | 19 |  |  | 23 |  |  | 110 |
Comprehensive income | 728 |  |  | 762 |  |  | 421 |  |  | 951 |
Less: Comprehensive loss attributable to noncontrolling interest | (1 | ) |  | (1 | ) |  | (1 | ) |  | (1 | )
Comprehensive income attributable to Valero Energy Corporation stockholders | $ | 729 |  |  | $ | 763 |  |  | $ | 422 |  |  | $ | 952 |

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)

| Six Months Ended June 30,
| 2012 |  | 2011
Cash flows from operating activities: |  |  |
Net income | $ | 398 |  |  | $ | 841 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |
Depreciation and amortization expense | 770 |  |  | 751 |
Asset impairment loss | 611 |  |  | — |
Noncash interest expense and other income, net | 11 |  |  | 21 |
Stock-based compensation expense | 20 |  |  | 23 |
Deferred income tax expense | 480 |  |  | 166 |
Changes in current assets and current liabilities | 725 |  |  | 1,147 |
Changes in deferred charges and credits and other operating activities, net | (21 | ) |  | 5 |
Net cash provided by operating activities | 2,994 |  |  | 2,954 |
Cash flows from investing activities: |  |  |
Capital expenditures | (1,420 | ) |  | (969 | )
Deferred turnaround and catalyst costs | (264 | ) |  | (432 | )
Advance payment related to acquisition of Pembroke Refinery | — |  |  | (37 | )
Minor acquisitions | (66 | ) |  | (37 | )
Other investing activities, net | 9 |  |  | (19 | )
Net cash used in investing activities | (1,741 | ) |  | (1,494 | )
Cash flows from financing activities: |  |  |
Non-bank debt: |  |  |
Borrowings | 300 |  |  | — |
Repayments | (862 | ) |  | (718 | )
Bank credit agreements: |  |  |
Borrowings | 1,100 |  |  | — |
Repayments | (1,100 | ) |  | — |
Accounts receivable sales program: |  |  |
Proceeds from the sale of receivables | 1,300 |  |  | — |
Repayments | (1,450 | ) |  | — |
Purchase of common stock for treasury | (147 | ) |  | — |
Proceeds from the exercise of stock options | 11 |  |  | 30 |
Common stock dividends | (166 | ) |  | (57 | )
Contributions from noncontrolling interest | 25 |  |  | 9 |
Other financing activities, net | (2 | ) |  | 7 |
Net cash used in financing activities | (991 | ) |  | (729 | )
Effect of foreign exchange rate changes on cash | 9 |  |  | 42 |
Net increase in cash and temporary cash investments | 271 |  |  | 773 |
Cash and temporary cash investments at beginning of period | 1,024 |  |  | 3,334 |
Cash and temporary cash investments at end of period | $ | 1,295 |  |  | $ | 4,107 |

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
General
As used in this report, the terms “Valero,” “we,” “us,” or “our” may refer to Valero Energy Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole.
These unaudited financial statements have been prepared in accordance with United States (U.S.) generally accepted accounting principles (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities Exchange Act of 1934. Accordingly, they do not include all of the information and notes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature unless disclosed otherwise. Financial information for the three and six months ended June 30, 2012 and 2011 included in these Condensed Notes to Consolidated Financial Statements is derived from our unaudited financial statements. Operating results for the three and six months ended June 30, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012.
The balance sheet as of December 31, 2011 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, 2011.
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
Effective January 1, 2012, we adopted the provisions of Accounting Standards Codification (ASC) Topic 220, “Comprehensive Income,” and have elected to present comprehensive income in a statement that is separate from the statement of income but placed directly after the statement of income.
Fair Value Measurements
Effective January 1, 2012, we adopted the provisions of ASC Topic 820, “Fair Value Measurement,” which clarified the application of existing fair value measurement requirements and changed certain fair value measurement and disclosure requirements. The adoption of these provisions did not affect our financial position or results of operations as these requirements only affected disclosures as reflected in Note 12.
New Accounting Pronouncements
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. The guidance requires entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the balance sheet and instruments and transactions subject to an agreement similar to a master
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
netting arrangement. These provisions are effective for interim and annual reporting periods beginning on January 1, 2013. The adoption of this guidance effective January 1, 2013 will not affect our financial position or results of operations, but may result in additional disclosures.

2. | ACQUISITIONS

The acquired refining and marketing businesses discussed below involve the production and marketing of refined petroleum products. These acquisitions are consistent with our general business strategy and complement our existing refining and marketing network.
Meraux Acquisition
On October 1, 2011, we acquired the Meraux Refinery and related logistics assets from Murphy Oil Corporation for an initial payment of $586 million, which was funded from available cash. In the fourth quarter of 2011, we recorded an adjustment related to inventories acquired that reduced the purchase price to $547 million. The assets acquired and liabilities assumed in this acquisition were recognized at their acquisition-date estimated fair values, as disclosed in Note 2 of Notes to Consolidated Financial Statements included in our annual report on Form 10-K for the year ended December 31, 2011, and no adjustments to those estimated amounts have been made during the six months ended June 30, 2012. We are, however, awaiting the completion of an independent appraisal and other evaluations of the fair values of the assets acquired and liabilities assumed.
Pembroke Acquisition
On August 1, 2011, we acquired 100 percent of the outstanding shares of Chevron Limited from a subsidiary of Chevron Corporation (Chevron), and we subsequently changed the name of Chevron Limited to Valero Energy Ltd. On the acquisition date, we initially paid $1.8 billion from available cash, of which $1.1 billion was for working capital. In the fourth quarter of 2011, we recorded adjustments to working capital (primarily inventory), resulting in an adjusted purchase price of $1.7 billion. The assets acquired and liabilities assumed in this acquisition were recognized at their acquisition-date estimated fair values, as disclosed in Note 2 of Notes to Consolidated Financial Statements included in our annual report on Form 10-K for the year ended December 31, 2011, and no adjustments to those estimated amounts have been made during the six months ended June 30, 2012. We are, however, awaiting the completion of an independent appraisal and other evaluations of the fair values of the assets acquired and liabilities assumed. This acquisition is referred to as the Pembroke Acquisition.
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. | IMPAIRMENT

In March 2012, we suspended the operations of the Aruba Refinery because of the refinery’s 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 narrowed significantly in the fourth quarter of 2011. We considered the use of alternative feedstocks or configuration changes that might improve the refinery’s cash flows and we also considered a temporary or permanent shutdown of the refinery facilities. We ultimately decided to shut down the refinery and to maintain it in a state that would allow for operations to be resumed.
On March 28, 2012, we received a non-binding indication of interest from an unrelated interested party to purchase the Aruba Refinery for $350 million, plus working capital as of the closing date, subject to completion of due diligence and further negotiations. We accepted this offer, subject to the finalization of the purchase and sale agreement. Negotiations are currently ongoing and no final agreement has been reached to sell the refinery. The Aruba Refinery is classified as “held and used” because all of the accounting criteria required for “held for sale” classification have not been met.
Because of our decision to suspend the operations of the Aruba Refinery and the possibility that we may sell the refinery, we evaluated the refinery for potential impairment and concluded that the Aruba Refinery was impaired as of March 31, 2012. 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 as of March 31, 2012 was the $350 million offer described above, which was based on the interested party’s specific knowledge of the refinery, experience in the refining and marketing industry, and extensive knowledge of the current economic factors of our business. 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.
The operations of the Aruba Refinery remained suspended throughout the second quarter of 2012, and the interested party has continued its negotiations process, including discussions with the Government of Aruba. As a result, we updated our impairment evaluation of the Aruba Refinery as of June 30, 2012 and concluded that the refinery was not further impaired as of that date. The carrying value of the Aruba Refinery’s long-lived assets as of June 30, 2012 was $347 million, reflecting the revised carrying value of $350 million established as of March 31, 2012 less depreciation recognized in the second quarter of 2012.
There is no certainty that we will sell the refinery to the interested party, or to any other party, and if we ultimately sell the refinery, there is no certainty that we will sell it for $350 million. In addition, should we be unable to sell the refinery, we may have to recognize an additional asset impairment loss.
The variation in the customary relationship between income tax expense and income from continuing operations before income tax expense for the six months ended June 30, 2012 was primarily due to not recognizing the tax benefit associated with the asset impairment loss of $595 million related to the Aruba Refinery as we do not expect to realize this tax benefit.
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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):

| June 30, 2012 |  | December 31, 2011
Refinery feedstocks | $ | 2,140 |  |  | $ | 2,474 |
Refined products and blendstocks | 2,797 |  |  | 2,633 |
Ethanol feedstocks and products | 178 |  |  | 195 |
Convenience store merchandise | 105 |  |  | 103 |
Materials and supplies | 223 |  |  | 218 |
Inventories | $ | 5,443 |  |  | $ | 5,623 |

As of June 30, 2012 and December 31, 2011, the replacement cost (market value) of last in, first out (LIFO) inventories exceeded their LIFO carrying amounts by approximately $6.5 billion and $6.8 billion, respectively.

5. | DEBT

Non-Bank Debt
During the six months ended June 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 (GO Zone Bonds), 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.

During the six months ended June 30, 2011, the following activity occurred:

• | in May 2011, we made a scheduled debt repayment of $200 million related to our 6.125% senior notes;

• | in April 2011, we made scheduled debt repayments of $8 million related to out Series 1997A 5.45%, Series 1997B 5.40%, and Series 1997C 5.40% industrial revenue bonds;

• | in February 2011, we made a scheduled debt repayment of $210 million related to our 6.75% senior notes; and

• | also in February 2011, we paid $300 million to acquire the GO Zone Bonds, which were subject to mandatory tender.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 June 30, 2012 and December 31, 2011, our debt-to-capitalization ratios, calculated in accordance with the terms of the Revolver, were 26 percent and 29 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$115 million.
During the six months ended June 30, 2012, we borrowed and repaid $1.1 billion under our Revolver. During the six months ended June 30, 2011, we had no borrowings or repayments under our Revolver. We had no borrowings or repayments under the Canadian revolving credit facility during the six months ended June 30, 2012 and 2011. As of June 30, 2012 and December 31, 2011, we had no borrowings outstanding under the Revolver or the Canadian revolving credit facility.
We had outstanding letters of credit under our committed lines of credit as follows (in millions):

|  |  |  |  |  | Amounts Outstanding
|  | Borrowing Capacity |  | Expiration |  | June 30, 2012 |  | December 31, 2011
Letter of credit facilities |  | $ | 550 |  |  | June 2013 |  | $ | 300 |  |  | $ | 300 |
Revolver |  | $ | 3,000 |  |  | December 2016 |  | $ | 70 |  |  | $ | 119 |
Canadian revolving credit facility |  | C$ | 115 |  |  | December 2012 |  | C$ | 11 |  |  | C$ | 20 |

In July 2012, one of our letter of credit facilities was amended to extend its maturity date through June 2013 and to increase its borrowing capacity by $50 million. The borrowing capacity and expiration shown in the table above reflect these changes.
As of June 30, 2012 and December 31, 2011, we had $649 million and $391 million, respectively, of letters of credit outstanding under our uncommitted short-term bank credit facilities.
Accounts Receivable Sales Facility
As of June 30, 2012, we had an accounts receivable sales facility with a group of third-party entities and financial institutions to sell on a revolving basis up to $1.0 billion of eligible trade receivables. In July 2012, we amended our agreement to increase the facility to $1.5 billion and to extend the maturity date to July 2013. Proceeds from the sale of receivables under this facility are reflected as debt. Under this program, one of our marketing subsidiaries (Valero Marketing) sells eligible receivables, without recourse, to another of our subsidiaries (Valero Capital), whereupon the receivables are no longer owned by Valero Marketing. Valero Capital, in turn, sells an undivided percentage ownership interest in the eligible receivables, without recourse, to the third-party entities and financial institutions. To the extent that Valero Capital retains an ownership interest in the receivables it has purchased from Valero Marketing, such interest is included in our financial statements solely as a result of the consolidation of the financial statements of Valero Capital with those of Valero Energy Corporation; the receivables are not available to satisfy the claims of the creditors of Valero Marketing or Valero Energy Corporation.
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Changes in the amounts outstanding under our accounts receivable sales facility were as follows (in millions):

| Six Months Ended June 30,
| 2012 |  | 2011
Balance as of beginning of period | $ | 250 |  |  | $ | 100 |
Proceeds from the sale of receivables | 1,300 |  |  | — |
Repayments | (1,450 | ) |  | — |
Balance as of end of period | $ | 100 |  |  | $ | 100 |

Capitalized Interest
Capitalized interest was $53 million and $33 million for the three months ended June 30, 2012 and 2011, respectively, and $105 million and $60 million for the six months ended June 30, 2012 and 2011, respectively.

6. | COMMITMENTS AND CONTINGENCIES

Environmental Matters
The U.S. Environmental Protection Agency (EPA) began regulating greenhouse gases on January 2, 2011, under the Clean Air Act Amendments of 1990 (Clean Air Act). Any new construction or material expansions will require that, among other things, a greenhouse gas permit be issued at either or both the state or federal level in accordance with the Clean Air Act and regulations, and we will be required to undertake a technology review to determine appropriate controls to be implemented with the project in order to reduce greenhouse gas emissions. The determination would be on a case by case basis, and the EPA has provided only general guidance on which controls will be required.
Furthermore, the EPA is currently developing refinery-specific greenhouse gas regulations and performance standards that are expected to impose, on new and existing operations, greenhouse gas emission limits and/or technology requirements. These control requirements may affect a wide range of refinery operations but have not yet been delineated. Any such controls, however, could result in material increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.
Certain states and foreign governments have pursued regulation of greenhouse gases independent of the EPA. For example, the California Global Warming Solutions Act, also known as AB 32, directs the California Air Resources Board (CARB) to develop and issue regulations to reduce greenhouse gas emissions in California to 1990 levels by 2020. The CARB has issued a variety of regulations aimed at reaching this goal, including a Low Carbon Fuel Standard (LCFS) as well as a statewide cap-and-trade program.

• | The LCFS was scheduled to become effective in 2011, but rulings by the U.S. District Court stayed enforcement of the LCFS until certain legal challenges to the LCFS were resolved. Most notably, the court determined that the LCFS violates the Commerce Clause of the U.S. Constitution to the extent that the standard discriminates against out-of-state crude oils and corn ethanol. CARB appealed the lower court’s ruling to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit Court).

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Ninth Circuit Court lifted the stay on April 23, 2012. We anticipate that the Ninth Circuit Court will hear arguments on the merits of the appeal this year, with a final ruling sometime thereafter.

• | A California statewide cap-and-trade program will begin in late 2012. Initially, the program will apply only to stationary sources of greenhouse gases (e.g., refinery and power plant greenhouse gas emissions). Greenhouse gas emissions from fuels that we sell in California will be covered by the program beginning in 2015. We anticipate that free allocations of credits will be available in the early years of the program to cover most of our stationary emissions, but we expect that compliance costs will increase significantly beginning in 2015, when transportation fuels are included in the program.

• | Complying with AB 32, including the LCFS and the cap-and-trade program, could result in material increased compliance costs for us, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of, and decreases in the demand for, the products we produce. To the degree we are unable to recover these increased costs, these matters could have a material adverse effect on our financial position, results of operations, and liquidity.

In the first quarter of 2012, CARB adopted amendments to its Clean Fuels Outlet (CFO) Regulation. CARB states that the CFO Regulation is intended to provide outlets of clean fuel to meet the needs of alternative fuel vehicles. We understand that CARB is preparing to submit the CFO Regulation to the State Office of Administrative Law for approval. Under the regulation, projections of zero-emission vehicle availability in the California market would trigger a requirement for major refiners and importers of gasoline, including us, to install clean fuel outlets in designated areas in proportion to each refiner or importer’s share in the California gasoline market. We expect this regulation to be challenged, but we could be required to make significant capital expenditures if the regulation is implemented as presently adopted.
The EPA has disapproved certain permitting programs of the Texas Commission on Environmental Quality (TCEQ) that historically have streamlined the environmental permitting process in Texas. For example, the EPA disapproved the TCEQ pollution control standard permit, thus requiring conventional permitting for future pollution control equipment. The Fifth Circuit Court of Appeals recently overturned the EPA’s disapproval and sent it back to the EPA to re-evaluate the decision. Litigation is pending from industry groups and others against the EPA for each of these actions. In some instances, the EPA’s decisions have been initially upheld and others are still pending before the courts. The EPA has also objected to numerous Title V permits in Texas and other states, including permits at our Port Arthur, Corpus Christi East, and McKee Refineries. Environmental activist groups have filed a notice of intent to sue the EPA, seeking to require the EPA to assume control of these permits from the TCEQ. Finally, as part of its regulation of greenhouse gases discussed above, the EPA has federalized the permitting of greenhouse gas emissions in Texas. This creates a dual permitting structure that must be navigated for material projects in Texas. All of these developments have created substantial uncertainty regarding existing and future permitting. Because of this uncertainty, we are unable to determine the costs or effects of the EPA’s actions on our permitting activity. The EPA’s disruption of the Texas permitting system could result in material increased compliance costs for us, increased capital expenditures, increased operating costs, and additional operating restrictions for our business, resulting in an increase in the cost of, and decreases in the demand for, the products we produce, which could have a material adverse effect on our financial position, results of operations, and liquidity.
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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Tax Matters
We are subject to extensive tax liabilities imposed by multiple jurisdictions, including income taxes, transactional taxes (excise/duty, sales/use, and value-added taxes), payroll taxes, franchise taxes, withholding taxes, and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. Many of these liabilities are subject to periodic audits by the respective taxing authority. Subsequent changes to our tax liabilities as a result of these audits may subject us to interest and penalties.
As of June 30, 2012, the Internal Revenue Service (IRS) has ongoing tax audits related to our U.S. federal tax returns from 2002 through 2009. We have received Revenue Agent Reports on our tax years for 2002 through 2007 and we are vigorously contesting the tax positions and assertions from the IRS. Although we believe our tax liabilities are fairly stated and properly reflected in our financial statements, should the IRS eventually prevail, it could result in a material amount of our deferred tax liabilities being reclassified to current liabilities which could have a material adverse effect on our liquidity.
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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7. | EQUITY

The following is a reconciliation of the beginning and ending balances (in millions) of equity attributable to our stockholders, equity attributable to the noncontrolling interest, and total equity for the six months ended June 30, 2012 and 2011:

|  | 2012 |  | 2011
|  | Valero Stockholders’ Equity |  | Non- controlling Interest |  | Total Equity |  | Valero Stockholders’ Equity |  | Non- controlling Interest |  | Total Equity
Balance as of beginning of period |  | $ | 16,423 |  |  | $ | 22 |  |  | $ | 16,445 |  |  | $ | 15,025 |  |  | $ | — |  |  | $ | 15,025 |
Net income (loss) |  | 399 |  |  | (1 | ) |  | 398 |  |  | 842 |  |  | (1 | ) |  | 841 |
Dividends |  | (166 | ) |  | — |  |  | (166 | ) |  | (57 | ) |  | — |  |  | (57 | )
Stock-based compensation expense |  | 20 |  |  | — |  |  | 20 |  |  | 23 |  |  | — |  |  | 23 |
Tax deduction in excess of stock-based compensation expense |  | 3 |  |  | — |  |  | 3 |  |  | 11 |  |  | — |  |  | 11 |
Transactions in connection with stock-based compensation plans: |  |  |  |  |  |  |  |  |  |  |  |
Stock issuances |  | 11 |  |  | — |  |  | 11 |  |  | 30 |  |  | — |  |  | 30 |
Stock repurchases |  | (136 | ) |  | — |  |  | (136 | ) |  | (2 | ) |  | — |  |  | (2 | )
Contributions from noncontrolling interest |  | — |  |  | 25 |  |  | 25 |  |  | — |  |  | 11 |  |  | 11 |
Other comprehensive income |  | 23 |  |  | — |  |  | 23 |  |  | 110 |  |  | — |  |  | 110 |
Balance as of end of period |  | $ | 16,577 |  |  | $ | 46 |  |  | $ | 16,623 |  |  | $ | 15,982 |  |  | $ | 10 |  |  | $ | 15,992 |

The noncontrolling interest relates to a third-party ownership interest in Diamond Green Diesel Holdings LLC, a company whose financial statements we consolidate due to our controlling interest.
Share Activity
Activity in the number of shares of common stock and treasury stock was as follows (in millions) for the six months ended June 30, 2012 and 2011:

| 2012 |  | 2011
| Common Stock |  | Treasury Stock |  | Common Stock |  | Treasury Stock
Balance as of beginning of period | 673 |  |  | (117 | ) |  | 673 |  |  | (105 | )
Transactions in connection with stock-based compensation plans: |  |  |  |  |  |  |
Stock issuances | — |  |  | 1 |  |  | — |  |  | 2 |
Stock purchases | — |  |  | (6 | ) |  | — |  |  | — |
Balance as of end of period | 673 |  |  | (122 | ) |  | 673 |  |  | (103 | )

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Common Stock Dividends
On July 26, 2012, our board of directors declared a quarterly cash dividend of $0.175 per common share payable on September 12, 2012 to holders of record at the close of business on August 15, 2012.

8. | EMPLOYEE BENEFIT PLANS

The components of net periodic benefit cost related to our defined benefit plans were as follows (in millions) for the three and six months ended June 30, 2012 and 2011:

| Pension Plans |  | Other Postretirement Benefit Plans
| 2012 |  | 2011 |  | 2012 |  | 2011
Three months ended June 30: |  |  |  |  |  |  |
Service cost | $ | 35 |  |  | $ | 22 |  |  | $ | 3 |  |  | $ | 2 |
Interest cost | 23 |  |  | 22 |  |  | 6 |  |  | 5 |
Expected return on plan assets | (31 | ) |  | (28 | ) |  | — |  |  | — |
Amortization of: |  |  |  |  |  |  |
Prior service credit | — |  |  | — |  |  | (6 | ) |  | (5 | )
Net actuarial loss | 9 |  |  | 3 |  |  | — |  |  | 1 |
Net periodic benefit cost | $ | 36 |  |  | $ | 19 |  |  | $ | 3 |  |  | $ | 3 |
Six months ended June 30: |  |  |  |  |  |  |
Service cost | $ | 70 |  |  | $ | 45 |  |  | $ | 6 |  |  | $ | 5 |
Interest cost | 46 |  |  | 43 |  |  | 11 |  |  | 11 |
Expected return on plan assets | (62 | ) |  | (56 | ) |  | — |  |  | — |
Amortization of: |  |  |  |  |  |  |
Prior service cost (credit) | 1 |  |  | 1 |  |  | (11 | ) |  | (11 | )
Net actuarial loss | 17 |  |  | 6 |  |  | — |  |  | 1 |
Net periodic benefit cost | $ | 72 |  |  | $ | 39 |  |  | $ | 6 |  |  | $ | 6 |

Our anticipated contributions to our pension plans during 2012 have not changed from amounts previously disclosed in our financial statements for the year ended December 31, 2011. During the six months ended June 30, 2012, we contributed approximately $13 million to our pension plans. There were no significant contributions made to our pension plans during the six months ended June 30, 2011. In July 2012, we contributed $50 million to our pension plans.
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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. | EARNINGS PER COMMON SHARE

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

| Three Months Ended June 30,
| 2012 |  | 2011
| Restricted Stock |  | Common Stock |  | Restricted Stock |  | Common Stock
Earnings per common share from continuing operations: |  |  |  |  |  |  |
Net income attributable to Valero stockholders from continuing operations |  |  | $ | 831 |  |  |  |  | $ | 745 |
Less dividends paid: |  |  |  |  |  |  |
Common stock |  |  | 82 |  |  |  |  | 29 |
Nonvested restricted stock |  |  | 1 |  |  |  |  | — |
Undistributed earnings |  |  | $ | 748 |  |  |  |  | $ | 716 |
Weighted-average common shares outstanding | 3 |  |  | 550 |  |  | 3 |  |  | 567 |
Earnings per common share from continuing operations: |  |  |  |  |  |  |
Distributed earnings | $ | 0.15 |  |  | $ | 0.15 |  |  | $ | 0.05 |  |  | $ | 0.05 |
Undistributed earnings | 1.35 |  |  | 1.35 |  |  | 1.26 |  |  | 1.26 |
Total earnings per common share from continuing operations | $ | 1.50 |  |  | $ | 1.50 |  |  | $ | 1.31 |  |  | $ | 1.31 |
Earnings per common share from continuing operations – assuming dilution: |  |  |  |  |  |  |
Net income attributable to Valero stockholders from continuing operations |  |  | $ | 831 |  |  |  |  | $ | 745 |
Weighted-average common shares outstanding |  |  | 550 |  |  |  |  | 567 |
Common equivalent shares: |  |  |  |  |  |  |
Stock options |  |  | 3 |  |  |  |  | 5 |
Performance awards and unvested restricted stock |  |  | 2 |  |  |  |  | 2 |
Weighted-average common shares outstanding – assuming dilution |  |  | 555 |  |  |  |  | 574 |
Earnings per common share from continuing operations – assuming dilution |  |  | $ | 1.50 |  |  |  |  | $ | 1.30 |

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

| Six Months Ended June 30,
| 2012 |  | 2011
| Restricted Stock |  | Common Stock |  | Restricted Stock |  | Common Stock
Earnings per common share from continuing operations: |  |  |  |  |  |  |
Net income attributable to Valero stockholders from continuing operations |  |  | $ | 399 |  |  |  |  | $ | 849 |
Less dividends paid: |  |  |  |  |  |  |
Common stock |  |  | 165 |  |  |  |  | 57 |
Nonvested restricted stock |  |  | 1 |  |  |  |  | — |
Undistributed earnings |  |  | $ | 233 |  |  |  |  | $ | 792 |
Weighted-average common shares outstanding | 3 |  |  | 550 |  |  | 3 |  |  | 567 |
Earnings per common share from continuing operations: |  |  |  |  |  |  |
Distributed earnings | $ | 0.30 |  |  | $ | 0.30 |  |  | $ | 0.10 |  |  | $ | 0.10 |
Undistributed earnings | 0.42 |  |  | 0.42 |  |  | 1.39 |  |  | 1.39 |
Total earnings per common share from continuing operations | $ | 0.72 |  |  | $ | 0.72 |  |  | $ | 1.49 |  |  | $ | 1.49 |
Earnings per common share from continuing operations – assuming dilution: |  |  |  |  |  |  |
Net income attributable to Valero stockholders from continuing operations |  |  | $ | 399 |  |  |  |  | $ | 849 |
Weighted-average common shares outstanding |  |  | 550 |  |  |  |  | 567 |
Common equivalent shares: |  |  |  |  |  |  |
Stock options |  |  | 4 |  |  |  |  | 5 |
Performance awards and unvested restricted stock |  |  | 2 |  |  |  |  | 1 |
Weighted-average common shares outstanding – assuming dilution |  |  | 556 |  |  |  |  | 573 |
Earnings per common share from continuing operations – assuming dilution |  |  | $ | 0.72 |  |  |  |  | $ | 1.48 |

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

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2012 |  | 2011 |  | 2012 |  | 2011
Stock options | 6 |  |  | 6 |  |  | 6 |  |  | 6 |

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. | SEGMENT INFORMATION

The following table reflects activity related to continuing operations (in millions):

|  | Refining |  | Retail |  | Ethanol |  | Corporate |  | Total
Three months ended June 30, 2012: |  |  |  |  |  |  |  |  |  |
Operating revenues from external customers |  | $ | 30,488 |  |  | $ | 3,062 |  |  | $ | 1,112 |  |  | $ | — |  |  | $ | 34,662 |
Intersegment revenues |  | 2,203 |  |  | — |  |  | 46 |  |  | — |  |  | 2,249 |
Operating income (loss) |  | 1,364 |  |  | 172 |  |  | 5 |  |  | (180 | ) |  | 1,361 |
Three months ended June 30, 2011: |  |  |  |  |  |  |  |  |  |
Operating revenues from external customers |  | 26,921 |  |  | 3,128 |  |  | 1,244 |  |  | — |  |  | 31,293 |
Intersegment revenues |  | 2,311 |  |  | — |  |  | 52 |  |  | — |  |  | 2,363 |
Operating income (loss) |  | 1,253 |  |  | 135 |  |  | 64 |  |  | (162 | ) |  | 1,290 |
Six months ended June 30, 2012: |  |  |  |  |  |  |  |  |  |
Operating revenues from external customers |  | 61,638 |  |  | 5,997 |  |  | 2,194 |  |  | — |  |  | 69,829 |
Intersegment revenues |  | 4,458 |  |  | — |  |  | 60 |  |  | — |  |  | 4,518 |
Operating income (loss) |  | 1,245 |  |  | 212 |  |  | 14 |  |  | (354 | ) |  | 1,117 |
Six months ended June 30, 2011: |  |  |  |  |  |  |  |  |  |
Operating revenues from external customers |  | 49,483 |  |  | 5,812 |  |  | 2,306 |  |  | — |  |  | 57,601 |
Intersegment revenues |  | 4,308 |  |  | — |  |  | 100 |  |  | — |  |  | 4,408 |
Operating income (loss) |  | 1,529 |  |  | 201 |  |  | 108 |  |  | (304 | ) |  | 1,534 |

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

| June 30, 2012 |  | December 31, 2011
Refining | $ | 36,602 |  |  | $ | 38,164 |
Retail | 1,973 |  |  | 1,999 |
Ethanol | 926 |  |  | 943 |
Corporate | 1,687 |  |  | 1,677 |
Total assets | $ | 41,188 |  |  | $ | 42,783 |

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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):

| Six Months Ended June 30,
| 2012 |  | 2011
Decrease (increase) in current assets: |  |  |
Receivables, net | $ | 2,087 |  |  | $ | (1,422 | )
Inventories | 198 |  |  | 978 |
Income taxes receivable | (79 | ) |  | 175 |
Prepaid expenses and other | (15 | ) |  | (3 | )
Increase (decrease) in current liabilities: |  |  |
Accounts payable | (1,413 | ) |  | 1,147 |
Accrued expenses | (60 | ) |  | 202 |
Taxes other than income taxes | 67 |  |  | (52 | )
Income taxes payable | (60 | ) |  | 122 |
Changes in current assets and current liabilities | $ | 725 |  |  | $ | 1,147 |

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

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

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

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

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

There were no significant noncash investing or financing activities for the six months ended June 30, 2012 or 2011.
Cash flows related to interest and income taxes were as follows (in millions):

| Six Months Ended June 30,
| 2012 |  | 2011
Interest paid in excess of amount capitalized | $ | 164 |  |  | $ | 221 |
Income taxes paid, net | 204 |  |  | 10 |

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12. | FAIR VALUE MEASUREMENTS

General
GAAP requires that certain financial instruments, such as derivative instruments, be recognized at their fair values in our balance sheets. However, other financial instruments, such as debt obligations, are not required to be recognized at their fair values, but GAAP provides an option to elect fair value accounting for these instruments. GAAP requires the disclosure of the fair values of all financial instruments, regardless of whether they are recognized at their fair values or carrying amounts in our balance sheets. For financial instruments recognized at fair value, GAAP requires the disclosure of their fair values by type of instrument, along with other information, including changes in the fair values of certain financial instruments recognized in income or other comprehensive income, and this information is provided below under “Recurring Fair Value Measurements.” For financial instruments not recognized at fair value, the disclosure of their fair values is provided below under “Other Financial Instruments.”
Nonfinancial assets, such as property, plant and equipment, and nonfinancial liabilities are recognized at their carrying amounts in our balance sheets. GAAP does not permit nonfinancial assets and liabilities to be remeasured at their fair values. However, GAAP requires the remeasurement of such assets and liabilities to their fair values upon the occurrence of certain events, such as the impairment of property, plant and equipment. In addition, if such an event occurs, GAAP requires the disclosure of the fair value of the asset or liability along with other information, including the gain or loss recognized in income in the period the remeasurement occurred. This information is provided below under “Nonrecurring Fair Value Measurements.”
GAAP provides a framework for measuring fair value and establishes a three-level fair value hierarchy that prioritizes inputs to valuation techniques based on the degree to which objective prices in external active markets are available to measure fair value. Following is a description of each of the levels of the fair value hierarchy.

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

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

• | Level 3 - Unobservable inputs for the asset or liability for which there is little, if any, market activity at the measurement date. 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.

The financial instruments and nonfinancial assets and liabilities included in our disclosure of recurring and nonrecurring fair value measurements are categorized according to the fair value hierarchy based on the inputs used to measure their fair values.
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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Recurring Fair Value Measurements
The tables below present information (in millions) about our financial instruments recognized at their fair values in our balance sheets categorized according to the fair value hierarchy of the inputs utilized by us to determine the fair values as of June 30, 2012 and December 31, 2011.
Cash received from brokers of $81 million and cash collateral deposits with brokers of $136 million under master netting arrangements are included in the fair value of the commodity derivatives reflected in Level 1 as of June 30, 2012 and December 31, 2011, respectively. Certain of our commodity derivative contracts under master netting arrangements include both asset and liability positions. We have elected to offset the fair value amounts recognized for multiple similar derivative instruments executed with the same counterparty, including any related cash collateral asset or obligation under the column “Netting Adjustments” below; however, fair value amounts by hierarchy level are presented on a gross basis in the tables below.

| Fair Value Measurements Using |  |  |  |
| Quoted Prices in Active Markets (Level 1) |  | Significant Other Observable Inputs (Level 2) |  | Significant Unobservable Inputs (Level 3) |  | Netting Adjustments |  | Total Fair Value as of June 30, 2012
Assets: |  |  |  |  |  |  |  |  |
Commodity derivative contracts | $ | 2,781 |  |  | $ | 144 |  |  | $ | — |  |  | $ | (2,836 | ) |  | $ | 89 |
Physical purchase contracts | — |  |  | 18 |  |  | — |  |  | — |  |  | 18 |
Investments of certain benefit plans | 85 |  |  | — |  |  | 11 |  |  | — |  |  | 96 |
Other investments | — |  |  | — |  |  | — |  |  | — |  |  | — |
Liabilities: |  |  |  |  |  |  |  |  |
Commodity derivative contracts | 2,701 |  |  | 143 |  |  | — |  |  | (2,836 | ) |  | 8 |
Foreign currency contracts | 5 |  |  | — |  |  | — |  |  | — |  |  | 5 |

| Fair Value Measurements Using |  |  |  |
| Quoted Prices in Active Markets (Level 1) |  | Significant Other Observable Inputs (Level 2) |  | Significant Unobservable Inputs (Level 3) |  | Netting Adjustments |  | Total Fair Value as of December 31, 2011
Assets: |  |  |  |  |  |  |  |  |
Commodity derivative contracts | $ | 2,038 |  |  | $ | 78 |  |  | $ | — |  |  | $ | (1,940 | ) |  | $ | 176 |
Physical purchase contracts | — |  |  | (2 | ) |  | — |  |  | — |  |  | (2 | )
Investments of certain benefit plans | 84 |  |  | — |  |  | 11 |  |  | — |  |  | 95 |
Other investments | — |  |  | — |  |  | — |  |  | — |  |  | — |
Liabilities: |  |  |  |  |  |  |  |  |
Commodity derivative contracts | 1,864 |  |  | 101 |  |  | — |  |  | (1,940 | ) |  | 25 |
Foreign currency contracts | 3 |  |  | — |  |  | — |  |  | — |  |  | 3 |

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
A description of our financial instruments and the valuation methods used to measure those instruments at fair value 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 to purchase inventories 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, but because these commitments have contractual terms that are not identical to exchange-traded futures instruments with a comparable market price, they are categorized in Level 2 of the fair value hierarchy.

• | Investments of certain benefit plans consist of investment securities held by trusts for the purpose of satisfying a portion of our obligations under certain U.S. nonqualified benefit plans. The assets categorized in Level 1 of the fair value hierarchy are measured at fair value using a market approach based on quoted prices from national securities exchanges. The assets categorized in Level 3 of the fair value hierarchy represent insurance contracts, the fair value of which is provided by the insurer.

• | Foreign currency contracts consist of foreign currency exchange and purchase contracts entered into by our international operations to manage our exposure to exchange rate fluctuations on transactions 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.

• | Other investments consist of (i) equity securities of private companies over which we do not exercise significant influence nor whose financial statements are consolidated into our financial statements and (ii) debt securities of a private company whose financial statements are not consolidated into our financial statements. We have elected to account for these investments at their fair values. These investments are categorized in Level 3 of the fair value hierarchy as the fair values of these investments are determined using the income approach based on internally developed analyses.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following is a reconciliation of the beginning and ending balances (in millions) for fair value measurements developed using significant unobservable inputs (Level 3) for the three and six months ended June 30, 2012 and 2011.

| 2012 |  | 2011
| Investments of Certain Benefit Plans |  | Other Investments |  | Investments of Certain Benefit Plans |  | Other Investments
Three months ended June 30: |  |  |  |  |  |  |
Balance as of beginning of period | $ | 11 |  |  | $ | — |  |  | $ | 11 |  |  | $ | — |
Purchases | — |  |  | — |  |  | — |  |  | 10 |
Total gains (losses) included in income | — |  |  | — |  |  | — |  |  | (10 | )
Transfers in and/or out of Level 3 | — |  |  | — |  |  | — |  |  | — |
Balance as of end of period | $ | 11 |  |  | $ | — |  |  | $ | 11 |  |  | $ | — |
The amount of total gains (losses) included in income attributable to the change in unrealized gains (losses) relating to assets still held at end of period | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (10 | )
Six months ended June 30: |  |  |  |  |  |  |
Balance as of beginning of period | $ | 11 |  |  | $ | — |  |  | $ | 10 |  |  | $ | — |
Purchases | — |  |  | — |  |  | — |  |  | 16 |
Total gains (losses) included in income | — |  |  | — |  |  | 1 |  |  | (16 | )
Transfers in and/or out of Level 3 | — |  |  | — |  |  | — |  |  | — |
Balance as of end of period | $ | 11 |  |  | $ | — |  |  | $ | 11 |  |  | $ | — |
The amount of total gains (losses) included in income attributable to the change in unrealized gains (losses) relating to assets still held at end of period | $ | — |  |  | $ | — |  |  | $ | 1 |  |  | $ | (16 | )

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Nonrecurring Fair Value Measurements
As discussed in Note 3, we concluded that the Aruba Refinery was impaired as of March 31, 2012. 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 as of March 31, 2012 was the $350 million offer received and accepted, subject to the finalization of the purchase and sale agreement. We believe this offer represents what a market participant would pay us for the assets in their highest and best use, as more fully discussed in Note 3. 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.
We recognized an asset impairment loss of $16 million in March 2012 related to equipment associated with a capital project that was cancelled permanently in 2009. We had written down the carrying value of this equipment to fair value in 2009, but we have been unable to sell the equipment. As a result, we wrote down the carrying amount of the equipment to scrap value.
There were no assets or liabilities that were measured at fair value on a nonrecurring basis as of June 30, 2012 or December 31, 2011. During the six months ended June 30, 2012, we recognized an asset impairment loss of $611 million as described above.

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

| June 30, 2012 |  | December 31, 2011
| Carrying Amount |  | Fair Value |  | Carrying Amount |  |  | Fair Value |
Financial assets: |  |  |  |  |  |  |
Cash and temporary cash investments | $ | 1,295 |  |  | $ | 1,295 |  |  | $ | 1,024 |  |  | $ | 1,024 |
Financial liabilities: |  |  |  |  |  |  |
Debt (excluding capital leases) | 6,995 |  |  | 8,187 |  |  | 7,690 |  |  | 9,298 |

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

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

• | The fair value of debt is determined primarily using the market approach based on quoted prices in active markets (Level 1).

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

13. | PRICE RISK MANAGEMENT ACTIVITIES

We are exposed to market risks related to the volatility in the price of commodities, the price of financial instruments associated with governmental and regulatory compliance programs, interest rates, and foreign currency exchange rates, and we enter into derivative instruments to manage some of these risks. We also enter into derivative instruments to manage the price risk on other contractual derivatives into which we have entered. The only types of derivative instruments we enter into are those related to the various commodities we purchase or produce, financial instruments we must purchase to maintain compliance with various governmental and regulatory programs, interest rate swaps, and foreign currency exchange and purchase contracts, as described below. All derivative instruments are recorded as either assets or liabilities measured at their fair values (see Note 12).
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 in 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.
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 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.
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.
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of June 30, 2012, 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 |  | 2012
Crude oil and refined products: |  |
Futures – long |  | 4,869 |
Futures – short |  | 9,052 |
Physical contracts - long |  | 4,183 |

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, product or natural gas purchases or refined product sales at existing market prices that we deem favorable.
As of June 30, 2012, 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 |  | 2012
Crude oil and refined products: |  |
Swaps – long |  | 5,511 |
Swaps – short |  | 5,511 |
Futures – long |  | 18,386 |
Futures – short |  | 10,768 |
Physical contracts – short |  | 7,618 |

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Economic Hedges
Economic hedges represent commodity derivative instruments that are not designated as fair value or cash flow hedges and are used to manage price volatility in certain (i) refinery feedstock, refined product, and corn inventories, (ii) forecasted refinery feedstock, refined product, and corn purchases, and refined product sales, and (iii) fixed-price corn purchase contracts. Our objective for entering into economic hedges is consistent with the objectives discussed above for fair value hedges and cash flow hedges. However, the economic hedges are not designated as a fair value hedge or a cash flow hedge for accounting purposes, usually due to the difficulty of establishing the required documentation at the date that the derivative instrument is entered into that would allow us to achieve “hedge deferral accounting.”
As of June 30, 2012, we had the following outstanding commodity derivative instruments that were used as economic hedges and commodity derivative instruments related to the physical purchase of corn at a fixed price. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except those identified as corn contracts that are presented in thousands of bushels).

|  | Notional Contract Volumes by Year of Maturity
Derivative Instrument |  | 2012 |  | 2013
Crude oil and refined products: |  |  |  |
Swaps – long |  | 30,879 |  |  | — |
Swaps – short |  | 28,174 |  |  | — |
Futures – long |  | 58,610 |  |  | 85 |
Futures – short |  | 79,986 |  |  | — |
Corn: |  |  |  |
Futures – long |  | 49,750 |  |  | 55 |
Futures – short |  | 91,035 |  |  | 3,375 |
Physical contracts – long |  | 38,336 |  |  | 3,610 |

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Trading Derivatives
Our objective in entering into commodity derivative instruments for trading purposes is to take advantage of existing market conditions related to future results of operations and cash flows.
As of June 30, 2012, we had the following outstanding commodity derivative instruments that were entered into for trading purposes. The information presents the notional volume of outstanding contracts by type of instrument and year of maturity (volumes represent thousands of barrels, except those identified as natural gas contracts that are presented in billions of British thermal units and corn contracts that are presented in thousands of bushels).

|  | Notional Contract Volumes by Year of Maturity
Derivative Instrument |  | 2012 |  | 2013
Crude oil and refined products: |  |  |  |
Swaps – long |  | 19,043 |  |  | 27,930 |
Swaps – short |  | 17,917 |  |  | 28,321 |
Futures – long |  | 101,095 |  |  | 18,832 |
Futures – short |  | 102,208 |  |  | 17,760 |
Options – long |  | 11,900 |  |  | — |
Options – short |  | 12,271 |  |  | — |
Natural gas: |  |  |  |
Futures – long |  | 6,800 |  |  | 200 |
Futures – short |  | 6,400 |  |  | — |
Corn: |  |  |  |
Swaps - long |  | 2,605 |  |  | — |
Swaps - short |  | 12,460 |  |  | 1,580 |
Futures – long |  | 19,360 |  |  | — |
Futures – short |  | 19,360 |  |  | — |

Compliance Program Price Risk
We are exposed to market risks related to the volatility in the price of financial instruments associated with various governmental and regulatory compliance programs that we must purchase in the open market to comply with these programs. These programs are described below.
Obligation to Blend Biofuels
We are obligated to blend biofuels into the products we produce in most of the countries in which we operate, and 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 in the U.S. and the United Kingdom (U.K.), we must purchase Renewable Identification Numbers (RINs) in the U.S. and Renewable Transport Fuel Obligation certificates (RTFCs) in the U.K., and as such, we are exposed to the volatility in the market price of these financial instruments.
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
We have not entered into derivative instruments to manage this risk, but we purchase RINs and RTFCs when the price of these instruments is deemed favorable. The cost of meeting our obligations under this compliance program was $59 million and $39 million for the three months ended June 30, 2012 and 2011, respectively, and $126 million and $95 million for the six months ended June 30, 2012 and 2011. These amounts are reflected in cost of sales.
Maintaining Minimum Inventory Quantities
In the U.K., we are required to maintain a minimum quantity of crude oil and refined products as a reserve against shortages or interruptions in the supply of these products. To the degree we decide not to physically hold the minimum quantity of crude oil and refined products, we must purchase Compulsory Stock Obligation (CSO) tickets from other suppliers of refined products in the U.K. or other European Union (EU) member countries, and we make economic decisions as to the cost of maintaining certain quantities of crude oil and refined products versus the cost of purchasing CSO tickets. We have not entered into derivative instruments to manage the price volatility of CSO tickets. For the three and six months ended June 30, 2012, the cost of purchasing CSO tickets to help meet our obligations under this compliance program was $1 million and $3 million, respectively and this amount was reflected in cost of sales. We had no obligations under this compliance program prior to completing the Pembroke Acquisition in 2011.
Emission Allowances
Our Pembroke Refinery is subject to a maximum amount of carbon dioxide that it can emit each year under the EU Emissions Trading Scheme. Under this cap-and-trade program, we purchase emission allowances on the open market for the difference between the amount of carbon dioxide emitted and the maximum amount allowed under the program. Therefore, we are exposed to the volatility in the market price of these allowances. For the three months ended June 30, 2012, no costs were incurred to meet our obligation under this compliance program. For the six months ended June 30, 2012, the cost of meeting our obligation under this compliance program was $1 million, which is reflected in refining operating expenses. We had no obligations under this compliance program prior to completing the Pembroke Acquisition in 2011.
We enter into derivative instruments (futures) to reduce the impact of this risk on our results of operations and cash flows. Our positions in these 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. As of June 30, 2012, we had purchased futures contracts – long for 55,000 metric tons of EU emission allowances that were entered into as economic hedges. As of June 30, 2012, the fair value of these futures contracts was immaterial and therefore not separately presented in the table below under “Fair Values of Derivative Instruments.” For the three and six months ended June 30, 2012, the gain (loss) recognized in income on these derivative instruments designated as economic hedges were also immaterial and therefore not separately presented in the table below under “Effect of Derivative Instruments on Income and Other Comprehensive Income.”
Interest Rate Risk
Our primary market risk exposure for changes in interest rates relates to our debt obligations. We manage our exposure to changing interest rates through the use of a combination of fixed-rate and floating-rate debt. In addition, at times we have used interest rate swap agreements to manage our fixed to floating interest rate position by converting certain fixed-rate debt to floating-rate debt. We had no interest rate derivative instruments outstanding as of June 30, 2012 or December 31, 2011, or during the three and six months ended June 30, 2012 and 2011.
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Foreign Currency Risk
We are exposed to exchange rate fluctuations on transactions entered into by our international operations that are denominated in currencies other than the local (functional) currencies of those operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and purchase contracts. These contracts are not designated as hedging instruments for accounting purposes, and therefore they are classified as economic hedges. As of June 30, 2012, we had commitments to purchase $634 million of U.S. dollars. These commitments matured on or before July 31, 2012.
Fair Values of Derivative Instruments
The following tables provide information about the fair values of our derivative instruments as of June 30, 2012 and December 31, 2011 (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 instruments executed with the same counterparty under master netting arrangements. 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. In addition, in Note 12, we included cash collateral on deposit with or received from brokers in the fair value of the commodity derivatives; these cash amounts are not reflected in the tables below.

| Balance Sheet Location |  | June 30, 2012
|  | Asset Derivatives |  | Liability Derivatives
Derivatives designated as hedging instruments |  |  |  |  |
Commodity contracts: |  |  |  |  |
Futures | Accrued expenses |  | $ | 2 |  |  | $ | 1 |
Futures | Receivables, net |  | 95 |  | 95
Swaps | Receivables, net |  | 4 |  |  | 2 |
Swaps | Accrued expenses |  | 31 |  |  | 32 |
Total |  |  | $ | 132 |  |  | $ | 130 |
Derivatives not designated as hedging instruments |  |  |  |  |
Commodity contracts: |  |  |  |  |
Futures | Accrued expenses |  | $ | 1,217 |  |  | $ | 1,141 |
Futures | Receivables, net |  | 1,470 |  | 1,385
Swaps | Receivables, net |  | 45 |  |  | 46 |
Swaps | Prepaid expenses and other |  | 49 |  |  | 42 |
Swaps | Accrued expenses |  | 13 |  |  | 20 |
Options | Receivables, net |  | 1 |  |  | 1 |
Physical purchase contracts | Inventories |  | 18 |  |  | — |
Foreign currency contracts | Accrued expenses |  | — |  |  | 5 |
Total |  |  | $ | 2,813 |  |  | $ | 2,640 |
Total derivatives |  |  | $ | 2,945 |  |  | $ | 2,770 |

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

| Balance Sheet Location |  | December 31, 2011
|  | Asset Derivatives |  | Liability Derivatives
Derivatives designated as hedging instruments |  |  |  |  |
Commodity contracts: |  |  |  |  |
Futures | Receivables, net |  | $ | 264 |  |  | $ | 240 |
Swaps | Accrued expenses |  | 36 |  |  | 46 |
Total |  |  | $ | 300 |  |  | $ | 286 |
Derivatives not designated as hedging instruments |  |  |  |  |
Commodity contracts: |  |  |  |  |
Futures | Receivables, net |  | $ | 1,636 |  |  | $ | 1,624 |
Swaps | Prepaid expenses and other |  | 4 |  |  | 2 |
Swaps | Accrued expenses |  | 38 |  |  | 51 |
Options | Receivables, net |  | 2 |  |  | — |
Options | Accrued expenses |  | — |  |  | 2 |
Physical purchase contracts | Inventories |  | — |  |  | 2 |
Foreign currency contracts | Accrued expenses |  | — |  |  | 3 |
Total |  |  | $ | 1,680 |  |  | $ | 1,684 |
Total derivatives |  |  | $ | 1,980 |  |  | $ | 1,970 |

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.
As of June 30, 2012, we had net receivables related to derivative instruments of $7 million from counterparties in the refining industry and no amounts from counterparties in the financial services industry. As of December 31, 2011, we had net receivables related to derivative instruments of $2 million from counterparties in the refining industry and no amounts from counterparties in the financial services industry. These amounts represent the aggregate amount payable to us by companies in those industries, reduced by payables from us to those companies under master netting arrangements that allow for the setoff of amounts receivable from and payable to the same party. We do not require any collateral or other security to support derivative instruments into which we enter. We also do not have any derivative instruments that require us to maintain a minimum investment-grade credit rating.
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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Effect of Derivative Instruments on Income and Other Comprehensive Income
The following tables provide information about the gain or loss recognized in income and other comprehensive income on our derivative instruments and the line items in the financial statements in which such gains and losses are reflected (in millions).

Derivatives in Fair Value Hedging Relationships |  | Location of Gain (Loss) Recognized in Income on Derivatives |  | Three Months Ended June 30, |  | Six Months Ended June 30,
|  | 2012 |  | 2011 |  | 2012 |  | 2011
Commodity contracts: |  |  |  |  |  |  |  |  |  |
Gain (loss) recognized in income on derivatives |  | Cost of sales |  | $ | 87 |  |  | $ | 140 |  |  | $ | (180 | ) |  | $ | 49 |
Gain (loss) recognized in income on hedged item |  | Cost of sales |  | (91 | ) |  | (147 | ) |  | 137 |  |  | (61 | )
Loss recognized in income on derivatives (ineffective portion) |  | Cost of sales |  | (4 | ) |  | (7 | ) |  | (43 | ) |  | (12 | )

For fair value hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness for the three and six months ended June 30, 2012 and 2011. We recognized a gain of $28 million in income for hedged firm commitments that no longer qualified as fair value hedges during the three and six months ended June 30, 2012. No amounts were recognized in income for hedged firm commitments that no longer qualify as fair value hedges for the three and six months ended June 30, 2011.

Derivatives in Cash Flow Hedging Relationships |  | Location of Gain (Loss) Recognized in Income on Derivatives |  | Three Months Ended June 30, |  | Six Months Ended June 30,
|  | 2012 |  | 2011 |  | 2012 |  | 2011
Commodity contracts: |  |  |  |  |  |  |  |  |  |
Gain (loss) recognized in OCI on derivatives (effective portion) |  |  |  | $ | (31 | ) |  | $ | — |  |  | $ | 16 |  |  | $ | — |
Gain (loss) reclassified from accumulated OCI into income (effective portion) |  | Cost of sales |  | (12 | ) |  | — |  |  | 36 |  |  | — |
Gain recognized in income on derivatives (ineffective portion) |  | Cost of sales |  | 31 |  |  | — |  |  | 26 |  |  | — |

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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 six months ended June 30, 2012 and 2011. For the three and six months ended June 30, 2012, cash flow hedges primarily related to forward sales of gasoline and distillates, and associated forward purchases of crude oil, with $5 million of cumulative after-tax gains on cash flow hedges remaining in accumulated other comprehensive income. We estimate that $9 million of the deferred gains as of June 30, 2012 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 six months ended June 30, 2012 and 2011, there were no amounts reclassified from accumulated other comprehensive income into income as a result of the discontinuance of cash flow hedge accounting.

Derivatives Designated as Economic Hedges and Other Derivative Instruments |  | Location of Gain (Loss) Recognized in Income on Derivatives |  | Three Months Ended June 30, |  | Six Months Ended June 30,
| 2012 |  | 2011 |  | 2012 |  | 2011
Commodity contracts |  | Cost of sales |  | $ | 574 |  |  | $ | (72 | ) |  | $ | 423 |  |  | $ | (371 | )
Foreign currency contracts |  | Cost of sales |  | 1 |  |  | 5 |  |  | (22 | ) |  | (9 | )
Total |  |  |  | $ | 575 |  |  | $ | (67 | ) |  | $ | 401 |  |  | $ | (380 | )

The loss of $371 million on commodity contracts for the six months ended June 30, 2011 includes a $542 million loss related to forward sales of refined product.

Trading Derivatives |  | Location of Gain (Loss) Recognized in Income on Derivatives |  | Three Months Ended June 30, |  | Six Months Ended June 30,
|  | 2012 |  | 2011 |  | 2012 |  | 2011
Commodity contracts |  | Cost of sales |  | $ | 8 |  |  | $ | 8 |  |  | $ | 4 |  |  | $ | 14 |

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

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

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

• | future retail margins, including gasoline, diesel, home heating oil, and convenience store merchandise 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, retail, 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, home heating oil, 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;

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• | 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;

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

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

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

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

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

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

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

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

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

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

Any one of these factors, or a combination of these factors, could materially affect our future results of operations and whether any forward-looking statements ultimately prove to be accurate. Our forward-looking statements are not guarantees of future performance, and actual results and future performance may differ materially from those suggested in any forward-looking statements. We do not intend to update these statements unless we are required by the securities laws to do so.
All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.
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OVERVIEW AND OUTLOOK
Overview
For the second quarter of 2012, we reported net income attributable to Valero stockholders from continuing operations of $831 million, or $1.50 per share (assuming dilution), compared to $745 million, or $1.30 per share (assuming dilution), for the second quarter of 2011. The increase in net income attributable to Valero stockholders from continuing operations of $86 million was primarily due to the increase of $71 million in our operating income as outlined by business segment in the following table (in millions):

|  | Three Months Ended June 30,
|  | 2012 |  | 2011 |  | Change
Operating income (loss) by business segment: |  |  |  |  |  |
Refining |  | $ | 1,364 |  |  | $ | 1,253 |  |  | $ | 111 |
Retail |  | 172 |  |  | 135 |  |  | 37 |
Ethanol |  | 5 |  |  | 64 |  |  | (59 | )
Corporate |  | (180 | ) |  | (162 | ) |  | (18 | )
Total |  | $ | 1,361 |  |  | $ | 1,290 |  |  | $ | 71 |

The increase of $71 million in operating income was primarily due to the increase of $111 million in our refining segment’s operating income, and this increase was largely the result of the additional operating income generated by our Meraux and Pembroke Refineries, which were acquired during the last six months of 2011. The increase in our refining segment’s operating income, however, was partially offset by the decrease of $59 million in our ethanol segment’s operating income. This decrease was due to lower margins caused by excess supplies of ethanol in the U.S.
For the first six months of 2012, we reported net income attributable to Valero stockholders from continuing operations of $399 million, or $0.72 per share (assuming dilution), compared to $849 million, or $1.48 per share (assuming dilution), for the first six months of 2011. The decrease in net income attributable to Valero stockholders from continuing operations of $450 million was primarily due to the decrease of $417 million in our operating income as outlined by business segment in the following table (in millions):

|  | Six Months Ended June 30,
|  | 2012 |  | 2011 |  | Change
Operating income (loss) by business segment: |  |  |  |  |  |
Refining |  | $ | 1,245 |  |  | $ | 1,529 |  |  | $ | (284 | )
Retail |  | 212 |  |  | 201 |  |  | 11 |
Ethanol |  | 14 |  |  | 108 |  |  | (94 | )
Corporate |  | (354 | ) |  | (304 | ) |  | (50 | )
Total |  | $ | 1,117 |  |  | $ | 1,534 |  |  | $ | (417 | )

The decrease of $417 million in operating income was primarily due to the decrease of $284 million in our refining segment’s operating income, and this decrease was largely the result of the decrease in the discount of the price of sour crude oils versus the price of sweet crude oils, which was partially offset by the increase in gasoline and distillate margins. In addition, our ethanol segment’s operating income decreased by $94 million, which was due to lower margins caused by excess supplies of ethanol in the U.S.
In March 2012, we suspended the operations of the Aruba Refinery because of the refinery’s inability to generate positive cash flows on a sustained basis subsequent to its restart in January 2011 and the sensitivity
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of its profitability to sour crude oil differentials, which narrowed significantly in the fourth quarter of 2011. On March 28, 2012, we received a non-binding indication of interest from an unrelated interested party to purchase the Aruba Refinery for $350 million, plus working capital as of the closing date, subject to completion of due diligence and further negotiations. We accepted this offer, subject to the finalization of the purchase and sale agreement. Because of our decision to suspend the operations of the Aruba Refinery and the possibility that we may sell the refinery, we evaluated the refinery for potential impairment as of March 31, 2012 and recognized an asset impairment loss of $595 million at that time. The interested party has continued its negotiations process throughout the second quarter of 2012, including discussions with the Government of Aruba. This matter is more fully discussed in Note 3 of Notes to Condensed Consolidated Financial Statements.
Outlook
Throughout 2011 and the first six months of 2012, our refining business has benefited from processing sweet crude oils sourced from the inland U.S., such as West Texas Intermediate (WTI) crude oil, due to the favorable difference between the price of these crude oils versus the price of benchmark sweet crude oils, such as Louisiana Light Sweet (LLS) and Brent crude oils. Historically, the price of WTI-type crude oil has closely approximated LLS and Brent crude oils, but due to the significant development of crude oil reserves within the U.S. Mid-Continent region and increased deliveries of crude oil from Canada into the U.S. Mid-Continent region, the increased supply of WTI-type crude oil has resulted in WTI-type crude oil being priced at a significant discount to LLS and Brent crude oils. This benefit, however, may decline as various crude oil pipeline and logistics projects are completed in coming months. These projects will allow sweet crude oils from the inland U.S. to be transported to the U.S. Gulf Coast region, which is expected to result in a narrowing of the price differential of WTI-priced crude oils relative to Brent-priced crude oil. As a result, the margins for refined products for refiners that process WTI-priced crude oils may decline.
The U.S. and worldwide refining business continues to experience capacity rationalization, particularly in Europe, the U.S. East Coast, and the Caribbean, where declining product margins have negatively impacted refineries in those regions. Refineries in those regions have closed, such as the Aruba Refinery discussed above, and others may close in coming months. However, some of these refineries may continue to be operated, which could have a negative impact on refined product margins. In addition, ethanol margins continue to remain depressed in the third quarter of 2012 due to higher corn prices caused by the drought in corn-producing regions of the U.S. Mid-Continent. As a result, we have temporarily suspended operations at two of our ethanol plants and reduced utilization at other plants.
Because of these matters, we expect energy markets and margins to be volatile in the near to mid-term.
In July 2012, we announced that our board of directors has authorized us to pursue a plan to separate our retail business from Valero as part of a strategy to maximize shareholder value. We are currently reviewing several potential separation transactions, including a tax-efficient distribution of the retail business to our shareholders.
Also in July 2012, our board of directors increased our quarterly dividend from $0.15 per share to $0.175 per share.
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RESULTS OF OPERATIONS
The following tables highlight our results of operations, our operating performance, and market prices that directly impact our operations. The narrative following these tables provides an analysis of our results of operations.
Financial Highlights (a) (b)
(millions of dollars, except per share amounts)

| Three Months Ended June 30,
| 2012 |  | 2011 |  | Change
Operating revenues | $ | 34,662 |  |  | $ | 31,293 |  |  | $ | 3,369 |
Costs and expenses: |  |  |  |  |
Cost of sales | 31,621 |  |  | 28,380 |  |  | 3,241 |
Operating expenses: |  |  |  |  |
Refining | 868 |  |  | 813 |  |  | 55 |
Retail | 170 |  |  | 169 |  |  | 1 |
Ethanol | 85 |  |  | 104 |  |  | (19 | )
General and administrative expenses | 171 |  |  | 151 |  |  | 20 |
Depreciation and amortization expense: |  |  |  |  |
Refining | 338 |  |  | 339 |  |  | (1 | )
Retail | 29 |  |  | 27 |  |  | 2 |
Ethanol | 10 |  |  | 9 |  |  | 1 |
Corporate | 9 |  |  | 11 |  |  | (2 | )
Total costs and expenses | 33,301 |  |  | 30,003 |  |  | 3,298 |
Operating income | 1,361 |  |  | 1,290 |  |  | 71 |
Other income (expense), net | (5 | ) |  | 10 |  |  | (15 | )
Interest and debt expense, net of capitalized interest | (74 | ) |  | (107 | ) |  | 33 |
Income from continuing operations before income tax expense | 1,282 |  |  | 1,193 |  |  | 89 |
Income tax expense | 452 |  |  | 449 |  |  | 3 |
Income from continuing operations | 830 |  |  | 744 |  |  | 86 |
Loss from discontinued operations, net of income taxes | — |  |  | (1 | ) |  | 1 |
Net income | 830 |  |  | 743 |  |  | 87 |
Less: Net loss attributable to noncontrolling interests | (1 | ) |  | (1 | ) |  | — |
Net income attributable to Valero stockholders | $ | 831 |  |  | $ | 744 |  |  | $ | 87 |
Net income attributable to Valero stockholders: |  |  |  |  |
Continuing operations | $ | 831 |  |  | $ | 745 |  |  | $ | 86 |
Discontinued operations | — |  |  | (1 | ) |  | 1 |
Total | $ | 831 |  |  | $ | 744 |  |  | $ | 87 |
Earnings per common share – assuming dilution: |  |  |  |  |  |
Continuing operations | $ | 1.50 |  |  | $ | 1.30 |  |  | $ | 0.20 |
Discontinued operations | — |  |  | — |  |  | — |
Total | $ | 1.50 |  |  | $ | 1.30 |  |  | $ | 0.20 |

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

| Three Months Ended June 30,
| 2012 |  | 2011 |  | Change
Refining (a) (b): |  |  |  |  |
Operating income | $ | 1,364 |  |  | $ | 1,253 |  |  | $ | 111 |
Throughput margin per barrel (c) | $ | 10.63 |  |  | $ | 11.41 |  |  | $ | (0.78 | )
Operating costs per barrel: |  |  |  |  |
Operating expenses | 3.59 |  |  | 3.86 |  |  | (0.27 | )
Depreciation and amortization expense | 1.40 |  |  | 1.61 |  |  | (0.21 | )
Total operating costs per barrel | 4.99 |  |  | 5.47 |  |  | (0.48 | )
Operating income per barrel | $ | 5.64 |  |  | $ | 5.94 |  |  | $ | (0.30 | )
Throughput volumes (thousand barrels per day): |  |  |  |  |
Feedstocks: |  |  |  |  |
Heavy sour crude | 390 |  |  | 450 |  |  | (60 | )
Medium/light sour crude | 609 |  |  | 418 |  |  | 191 |
Acidic sweet crude | 136 |  |  | 128 |  |  | 8 |
Sweet crude | 886 |  |  | 679 |  |  | 207 |
Residuals | 215 |  |  | 293 |  |  | (78 | )
Other feedstocks | 122 |  |  | 105 |  |  | 17 |
Total feedstocks | 2,358 |  |  | 2,073 |  |  | 285 |
Blendstocks and other | 300 |  |  | 243 |  |  | 57 |
Total throughput volumes | 2,658 |  |  | 2,316 |  |  | 342 |
Yields (thousand barrels per day): |  |  |  |  |
Gasolines and blendstocks | 1,294 |  |  | 1,054 |  |  | 240 |
Distillates | 918 |  |  | 786 |  |  | 132 |
Other products (d) | 469 |  |  | 487 |  |  | (18 | )
Total yields | 2,681 |  |  | 2,327 |  |  | 354 |

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Refining Operating Highlights by Region (e)
(millions of dollars, except per barrel amounts)

| Three Months Ended June 30,
| 2012 |  | 2011 |  | Change
U.S. Gulf Coast (a): |  |  |  |  |
Operating income | $ | 637 |  |  | $ | 786 |  |  | $ | (149 | )
Throughput volumes (thousand barrels per day) | 1,491 |  |  | 1,432 |  |  | 59 |
Throughput margin per barrel (c) | $ | 9.50 |  |  | $ | 11.30 |  |  | $ | (1.80 | )
Operating costs per barrel: |  |  |  |  |
Operating expenses | 3.40 |  |  | 3.74 |  |  | (0.34 | )
Depreciation and amortization expense | 1.41 |  |  | 1.54 |  |  | (0.13 | )
Total operating costs per barrel | 4.81 |  |  | 5.28 |  |  | (0.47 | )
Operating income per barrel | $ | 4.69 |  |  | $ | 6.02 |  |  | $ | (1.33 | )
U.S. Mid-Continent: |  |  |  |  |
Operating income | $ | 444 |  |  | $ | 393 |  |  | $ | 51 |
Throughput volumes (thousand barrels per day) | 404 |  |  | 398 |  |  | 6 |
Throughput margin per barrel (c) | $ | 17.61 |  |  | $ | 16.50 |  |  | $ | 1.11 |
Operating costs per barrel: |  |  |  |  |
Operating expenses | 3.97 |  |  | 4.01 |  |  | (0.04 | )
Depreciation and amortization expense | 1.55 |  |  | 1.65 |  |  | (0.10 | )
Total operating costs per barrel | 5.52 |  |  | 5.66 |  |  | (0.14 | )
Operating income per barrel | $ | 12.09 |  |  | $ | 10.84 |  |  | $ | 1.25 |
North Atlantic (b): |  |  |  |  |
Operating income (loss) | $ | 172 |  |  | $ | (17 | ) |  | $ | 189 |
Throughput volumes (thousand barrels per day) | 473 |  |  | 207 |  |  | 266 |
Throughput margin per barrel (c) | $ | 8.01 |  |  | $ | 3.36 |  |  | $ | 4.65 |
Operating costs per barrel: |  |  |  |  |
Operating expenses | 3.22 |  |  | 3.04 |  |  | 0.18 |
Depreciation and amortization expense | 0.80 |  |  | 1.22 |  |  | (0.42 | )
Total operating costs per barrel | 4.02 |  |  | 4.26 |  |  | (0.24 | )
Operating income (loss) per barrel | $ | 3.99 |  |  | $ | (0.90 | ) |  | $ | 4.89 |
U.S. West Coast: |  |  |  |  |
Operating income | $ | 111 |  |  | $ | 91 |  |  | $ | 20 |
Throughput volumes (thousand barrels per day) | 290 |  |  | 279 |  |  | 11 |
Throughput margin per barrel (c) | $ | 10.95 |  |  | $ | 10.65 |  |  | $ | 0.30 |
Operating costs per barrel: |  |  |  |  |
Operating expenses | 4.62 |  |  | 4.84 |  |  | (0.22 | )
Depreciation and amortization expense | 2.11 |  |  | 2.21 |  |  | (0.10 | )
Total operating costs per barrel | 6.73 |  |  | 7.05 |  |  | (0.32 | )
Operating income per barrel | $ | 4.22 |  |  | $ | 3.60 |  |  | $ | 0.62 |
Total refining operating income | $ | 1,364 |  |  | $ | 1,253 |  |  | $ | 111 |

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

| Three Months Ended June 30,
| 2012 |  | 2011 |  | Change
Feedstocks: |  |  |  |  |
Brent crude oil | $ | 108.95 |  |  | $ | 117.17 |  |  | $ | (8.22 | )
Brent less WTI crude oil | 15.51 |  |  | 14.68 |  |  | 0.83 |
Brent less Alaska North Slope (ANS) crude oil | (0.65 | ) |  | 2.15 |  |  | (2.80 | )
Brent less LLS crude oil | 0.02 |  |  | (0.79 | ) |  | 0.81 |
Brent less Mars crude oil | 4.22 |  |  | 5.25 |  |  | (1.03 | )
Brent less Maya crude oil | 9.86 |  |  | 13.79 |  |  | (3.93 | )
LLS crude oil | 108.93 |  |  | 117.96 |  |  | (9.03 | )
LLS less Mars crude oil | 4.20 |  |  | 6.04 |  |  | (1.84 | )
LLS less Maya crude oil | 9.84 |  |  | 14.58 |  |  | (4.74 | )
WTI crude oil | 93.44 |  |  | 102.49 |  |  | (9.05 | )
Natural gas (dollars per million British thermal units) | 2.24 |  |  | 4.34 |  |  | (2.10 | )
Products: |  |  |  |  |
U.S. Gulf Coast: |  |  |  |  |
Conventional 87 gasoline less Brent | 8.32 |  |  | 11.04 |  |  | (2.72 | )
Ultra-low-sulfur diesel less Brent | 14.65 |  |  | 12.27 |  |  | 2.38 |
Propylene less Brent | (10.39 | ) |  | 26.96 |  |  | (37.35 | )
Conventional 87 gasoline less LLS | 8.34 |  |  | 10.26 |  |  | (1.92 | )
Ultra-low-sulfur diesel less LLS | 14.67 |  |  | 11.49 |  |  | 3.18 |
Propylene less LLS | (10.37 | ) |  | 26.03 |  |  | (36.40 | )
U.S. Mid-Continent: |  |  |  |  |
Conventional 87 gasoline less WTI | 27.33 |  |  | 26.38 |  |  | 0.95 |
Ultra-low-sulfur diesel less WTI | 30.32 |  |  | 28.83 |  |  | 1.49 |
North Atlantic: |  |  |  |  |
Conventional 87 gasoline less Brent | 12.43 |  |  | 8.88 |  |  | 3.55 |
Ultra-low-sulfur diesel less Brent | 16.11 |  |  | 13.96 |  |  | 2.15 |
U.S. West Coast: |  |  |  |  |
CARBOB 87 gasoline less ANS | 18.20 |  |  | 14.54 |  |  | 3.66 |
CARB diesel less ANS | 15.09 |  |  | 19.21 |  |  | (4.12 | )
CARBOB 87 gasoline less WTI | 34.36 |  |  | 27.07 |  |  | 7.29 |
CARB diesel less WTI | 31.25 |  |  | 31.74 |  |  | (0.49 | )
New York Harbor corn crush (dollars per gallon) | (0.06 | ) |  | 0.07 |  |  | (0.13 | )

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Operating Highlights (continued)
(millions of dollars, except per gallon amounts)

| Three Months Ended June 30,
| 2012 |  | 2011 |  | Change
Retail–U.S.: |  |  |  |  |
Operating income | $ | 134 |  |  | $ | 87 |  |  | $ | 47 |
Company-operated fuel sites (average) | 998 |  |  | 995 |  |  | 3 |
Fuel volumes (gallons per day per site) | 5,162 |  |  | 5,094 |  |  | 68 |
Fuel margin per gallon | $ | 0.303 |  |  | $ | 0.204 |  |  | $ | 0.099 |
Merchandise sales | $ | 320 |  |  | $ | 323 |  |  | $ | (3 | )
Merchandise margin (percentage of sales) | 30.1 | % |  | 28.4 | % |  | 1.7 | %
Margin on miscellaneous sales | $ | 22 |  |  | $ | 22 |  |  | $ | — |
Operating expenses | $ | 106 |  |  | $ | 103 |  |  | $ | 3 |
Depreciation and amortization expense | $ | 20 |  |  | $ | 18 |  |  | $ | 2 |
Retail–Canada: |  |  |  |  |
Operating income | $ | 38 |  |  | $ | 48 |  |  | $ | (10 | )
Fuel volumes (thousand gallons per day) | 3,117 |  |  | 3,182 |  |  | (65 | )
Fuel margin per gallon | $ | 0.285 |  |  | $ | 0.319 |  |  | $ | (0.034 | )
Merchandise sales | $ | 65 |  |  | $ | 68 |  |  | $ | (3 | )
Merchandise margin (percentage of sales) | 29.3 | % |  | 29.8 | % |  | (0.5 | )%
Margin on miscellaneous sales | $ | 11 |  |  | $ | 11 |  |  | $ | — |
Operating expenses | $ | 64 |  |  | $ | 66 |  |  | $ | (2 | )
Depreciation and amortization expense | $ | 9 |  |  | $ | 9 |  |  | $ | — |
Ethanol: |  |  |  |  |
Operating income | $ | 5 |  |  | $ | 64 |  |  | $ | (59 | )
Production (thousand gallons per day) | 3,352 |  |  | 3,397 |  |  | (45 | )
Gross margin per gallon of production (c) | $ | 0.32 |  |  | $ | 0.57 |  |  | $ | (0.25 | )
Operating costs per gallon of production: |  |  |  |  |
Operating expenses | 0.28 |  |  | 0.33 |  |  | (0.05 | )
Depreciation and amortization expense | 0.03 |  |  | 0.03 |  |  | — |
Total operating costs per gallon of production | 0.31 |  |  | 0.36 |  |  | (0.05 | )
Operating income per gallon of production | $ | 0.01 |  |  | $ | 0.21 |  |  | $ | (0.20 | )

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

(a) | For the three months ended June 30,2012, the financial highlights and operating highlights for the refining segment and U.S. Gulf Coast region include the results of operations of our Meraux Refinery, including related logistics assets, from the date of its acquisition on October 1, 2011.

(b) | For the three months ended June 30, 2012, the financial highlights and operating highlights for the refining segment and North Atlantic region include the results of operations of our Pembroke Refinery, including the related marketing and logistics business, from the date of its acquisition on August 1, 2011.

(c) | Throughput margin per barrel represents operating revenues less cost of sales of our refining segment divided by throughput volumes. Gross margin per gallon of production represents operating revenues less cost of sales of our ethanol segment divided by production volumes.

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

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

(f) | Average market reference prices for Brent crude oil, along with price differentials between the price of Brent crude oil and other types of crude oil, have been included in the table of Average Market Reference Prices and Differentials. The table also includes price differentials by region between the prices of certain products and the benchmark crude oil that provides a relevant indicator of product margins for each region. We previously provided feedstock and product differentials based on the price of WTI crude oil. However, the price of WTI crude oil no longer provides a reasonable benchmark price of crude oil for all regions. Beginning in late 2010, WTI crude oil began to price at a discount to benchmark sweet crude oils, such as Brent and LLS, because of increased WTI supplies resulting from greater U.S. production and increased deliveries of crude oil from Canada into the U.S. Mid-Continent region. We utilize Brent crude oil for price differentials because we believe it represents sweet crude oil prices for marginal refineries in the Atlantic Basin, and thus sets refined-product prices.

General
Operating revenues increased 11 percent (or $3.4 billion) for the second quarter of 2012 compared to the second quarter of 2011 primarily as a result of higher throughput volumes between the two periods related to our refining segment operations. The higher throughput volumes resulted primarily from the incremental throughput of 136,000 barrels per day from the Meraux Refinery, which was acquired on October 1, 2011, and incremental throughput of 250,000 barrels per day from the Pembroke Refinery, which was acquired on August 1, 2011. Operating income increased $71 million and income from continuing operations before income tax expense increased $89 million for the second quarter of 2012 compared to amounts reported for the second quarter of 2011 primarily due to a $111 million increase in refining segment operating income which was partially offset by a $59 million decrease in ethanol segment operating income discussed below.
Refining
Refining segment operating income increased 9 percent (or $111 million) from $1.3 billion for the second quarter of 2011 to $1.4 billion for the second quarter of 2012. The $111 million increase in operating income was primarily due to a $165 million increase in refining margin, partially offset by a $55 million increase in operating expenses.
The $165 million refining margin improvement was primarily due to the margin generated by our Meraux and Pembroke Refineries of $71 million and $173 million, respectively, during the second quarter of 2012. We acquired both of these refineries in the last half of 2011 as discussed above, but the increase in margin generated by these refineries was partially offset by a decrease in margin of $45 million related to our Aruba Refinery due to our decision to temporarily suspend its operations in March 2012. Those operations remained suspended throughout the second quarter of 2012.
Despite the refining margin improvement and a 15 percent increase in total throughput volumes (a 342,000 barrel per day increase) quarter over quarter, throughput margin per barrel decreased by 7 percent (or $0.78 per barrel). This decrease was largely due to decreases in product margins in the U.S. Gulf Coast region. For example, the Brent and LLS-based benchmark reference margins for U.S. Gulf Coast conventional
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87 gasoline were $8.32 per barrel and $8.34 per barrel, respectively, for the second quarter of 2012 compared to $11.04 per barrel and $10.26 per barrel, respectively, for the second quarter of 2011, representing unfavorable decreases of $2.72 per barrel and $1.92 per barrel, respectively. These decreases in U.S. Gulf Coast product margins had a significant impact to our overall refining margin because our U.S. Gulf Coast throughput volumes of 1.5 million barrels per day composed the majority (56 percent) of our total throughput volumes of 2.7 million barrels per day during the second quarter of 2012. In addition, throughput margin per barrel in the second quarter of 2012 was unfavorably impacted by the decrease in sour crude oil differentials as compared to the second quarter of 2011. For example, Maya crude oil, which is a type of sour crude oil, sold at a discount of $9.86 per barrel to Brent crude oil, which is a type of sweet crude oil, during the second quarter of 2012. This compares to a discount of $13.79 per barrel during the second quarter of 2011, representing an unfavorable decrease of $3.93 per barrel.
The increase of $55 million in refining operating expenses discussed above was primarily due to $36 million in operating expenses incurred by the Meraux Refinery, which was acquired on October 1, 2011, and $91 million in operating expenses incurred by the Pembroke Refinery, which was acquired on August 1, 2011. The remaining decrease in refining operating expenses of $72 million was primarily due to a $40 million decrease in energy costs, a $25 million decrease in maintenance expenses, and a $13 million decrease in employee-related expenses, partially offset by a $14 million increase in catalyst and chemical costs.
Retail
Retail segment operating income was $172 million for the second quarter of 2012 compared to $135 million for the second quarter of 2011. This 27 percent (or $37 million) increase was primarily due to an increase in the fuel margins generated by our U.S. retail operations of $48 million, partially offset by a decrease in the fuel margins generated by our Canadian retail operations of $11 million. The significant improvement in fuel margins in the U.S. was largely the result of decreases in the wholesale prices for gasoline and diesel in the second quarter of 2012.
Ethanol
Ethanol segment operating income was $5 million for the second quarter of 2012 compared to $64 million for the second quarter of 2011. The $59 million decrease in operating income was primarily due to a $77 million decrease in gross margin, partially offset by a $19 million decrease in operating expenses.
The decrease in gross margin was due to a 44 percent decrease in the gross margin per gallon of ethanol production (a $0.25 per gallon decrease between the comparable periods) primarily due to lower ethanol prices between the second quarter of 2011 and the second quarter of 2012. Ethanol prices in the second quarter of 2012 were pressured by a surplus of ethanol supply during the quarter due to reduced demand for ethanol associated with the decline in gasoline demand in the U.S. In addition, ethanol production decreased 45,000 gallons per day between the comparable periods, resulting from lower utilization rates during the second quarter of 2012 in response to the surplus of ethanol supply. The reduction in operating expenses was due primarily to an $18 million decrease in energy costs due to lower natural gas prices compared to the second quarter of 2011.
Corporate Expenses and Other
General and administrative expenses increased $20 million from the second quarter of 2011 to the second quarter of 2012 primarily due to $29 million in administrative costs related to our European operations, partially offset by an $11 million decrease in employee-related expenses.
“Interest and debt expense, net of capitalized interest” for the second quarter of 2012 decreased $33 million from the second quarter of 2011. This decrease was primarily due to a $21 million increase in capitalized interest due to a corresponding increase in capital expenditures between the quarters.
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Financial Highlights (a) (b)
(millions of dollars, except per share amounts)

| Six Months Ended June 30,
| 2012 |  | 2011 |  | Change
Operating revenues | $ | 69,829 |  |  | $ | 57,601 |  |  | $ | 12,228 |
Costs and expenses: |  |  |  |  |
Cost of sales (c) | 64,656 |  |  | 52,948 |  |  | 11,708 |
Operating expenses: |  |  |  |  |
Refining | 1,832 |  |  | 1,557 |  |  | 275 |
Retail | 336 |  |  | 331 |  |  | 5 |
Ethanol | 172 |  |  | 199 |  |  | (27 | )
General and administrative expenses | 335 |  |  | 281 |  |  | 54 |
Depreciation and amortization expense: |  |  |  |  |
Refining | 675 |  |  | 655 |  |  | 20 |
Retail | 56 |  |  | 55 |  |  | 1 |
Ethanol | 20 |  |  | 18 |  |  | 2 |
Corporate | 19 |  |  | 23 |  |  | (4 | )
Asset impairment loss (d) | 611 |  |  | — |  |  | 611 |
Total costs and expenses | 68,712 |  |  | 56,067 |  |  | 12,645 |
Operating income | 1,117 |  |  | 1,534 |  |  | (417 | )
Other income, net | 1 |  |  | 27 |  |  | (26 | )
Interest and debt expense, net of capitalized interest | (173 | ) |  | (224 | ) |  | 51 |
Income from continuing operations before income tax expense | 945 |  |  | 1,337 |  |  | (392 | )
Income tax expense | 547 |  |  | 489 |  |  | 58 |
Income from continuing operations | 398 |  |  | 848 |  |  | (450 | )
Income (loss) from discontinued operations, net of income taxes | — |  |  | (7 | ) |  | 7 |
Net income | 398 |  |  | 841 |  |  | (443 | )
Less: Net loss attributable to noncontrolling interests | (1 | ) |  | (1 | ) |  | — |
Net income attributable to Valero stockholders | $ | 399 |  |  | $ | 842 |  |  | $ | (443 | )
Net income attributable to Valero stockholders: |  |  |  |  |
Continuing operations | $ | 399 |  |  | $ | 849 |  |  | $ | (450 | )
Discontinued operations | — |  |  | (7 | ) |  | 7 |
Total | $ | 399 |  |  | $ | 842 |  |  | $ | (443 | )
Earnings per common share – assuming dilution: |  |  |  |  |
Continuing operations | $ | 0.72 |  |  | $ | 1.48 |  |  | $ | (0.76 | )
Discontinued operations | — |  |  | (0.01 | ) |  | 0.01 |
Total | $ | 0.72 |  |  | $ | 1.47 |  |  | $ | (0.75 | )

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

| Six Months Ended June 30,
| 2012 |  | 2011 |  | Change
Refining (a) (b): |  |  |  |  |
Operating income (c) | $ | 1,245 |  |  | $ | 1,529 |  |  | $ | (284 | )
Throughput margin per barrel (c) | $ | 9.20 |  |  | $ | 10.70 |  |  | $ | (1.50 | )
Operating costs per barrel: |  |  |  |  |  |
Operating expenses | 3.86 |  |  | 3.89 |  |  | (0.03 | )
Depreciation and amortization expense | 1.43 |  |  | 1.64 |  |  | (0.21 | )
Total operating costs per barrel (d) | 5.29 |  |  | 5.53 |  |  | (0.24 | )
Operating income per barrel | $ | 3.91 |  |  | $ | 5.17 |  |  | $ | (1.26 | )
Throughput volumes (thousand barrels per day): |  |  |  |  |
Feedstocks: |  |  |  |  |
Heavy sour crude | 420 |  |  | 412 |  |  | 8 |
Medium/light sour crude | 582 |  |  | 395 |  |  | 187 |
Acidic sweet crude | 104 |  |  | 100 |  |  | 4 |
Sweet crude | 885 |  |  | 672 |  |  | 213 |
Residuals | 192 |  |  | 271 |  |  | (79 | )
Other feedstocks | 133 |  |  | 121 |  |  | 12 |
Total feedstocks | 2,316 |  |  | 1,971 |  |  | 345 |
Blendstocks and other | 290 |  |  | 241 |  |  | 49 |
Total throughput volumes | 2,606 |  |  | 2,212 |  |  | 394 |
Yields (thousand barrels per day): |  |  |  |  |
Gasolines and blendstocks | 1,243 |  |  | 1,005 |  |  | 238 |
Distillates | 915 |  |  | 741 |  |  | 174 |
Other products (f) | 468 |  |  | 476 |  |  | (8 | )
Total yields | 2,626 |  |  | 2,222 |  |  | 404 |

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Refining Operating Highlights by Region (g)
(millions of dollars, except per barrel amounts)

| Six Months Ended June 30,
| 2012 |  | 2011 |  | Change
U.S. Gulf Coast: (a) |  |  |  |  |
Operating income (c) | $ | 872 |  |  | $ | 1,269 |  |  | $ | (397 | )
Throughput volumes (thousand barrels per day) | 1,483 |  |  | 1,366 |  |  | 117 |
Throughput margin per barrel (c) (e) | $ | 8.21 |  |  | $ | 10.52 |  |  | $ | (2.31 | )
Operating costs per barrel: |  |  |  |  |  |
Operating expenses | 3.53 |  |  | 3.80 |  |  | (0.27 | )
Depreciation and amortization expense | 1.45 |  |  | 1.58 |  |  | (0.13 | )
Total operating costs per barrel (d) | 4.98 |  |  | 5.38 |  |  | (0.40 | )
Operating income per barrel (d) | $ | 3.23 |  |  | $ | 5.14 |  |  | $ | (1.91 | )
U.S. Mid-Continent: |  |  |  |  |
Operating income (c) | $ | 698 |  |  | $ | 682 |  |  | $ | 16 |
Throughput volumes (thousand barrels per day) | 401 |  |  | 401 |  |  | — |
Throughput margin per barrel (c) (e) | $ | 15.72 |  |  | $ | 14.77 |  |  | $ | 0.95 |
Operating costs per barrel: |  |  |  |  |  |
Operating expenses | 4.64 |  |  | 3.83 |  |  | 0.81 |
Depreciation and amortization expense | 1.52 |  |  | 1.54 |  |  | (0.02 | )
Total operating costs per barrel | 6.16 |  |  | 5.37 |  |  | 0.79 |
Operating income per barrel | $ | 9.56 |  |  | $ | 9.40 |  |  | $ | 0.16 |
North Atlantic (b): |  |  |  |  |
Operating income | $ | 233 |  |  | $ | 39 |  |  | $ | 194 |
Throughput volumes (thousand barrels per day) | 467 |  |  | 208 |  |  | 259 |
Throughput margin per barrel (e) | $ | 6.84 |  |  | $ | 5.19 |  |  | $ | 1.65 |
Operating costs per barrel: |  |  |  |  |  |
Operating expenses | 3.37 |  |  | 2.93 |  |  | 0.44 |
Depreciation and amortization expense | 0.73 |  |  | 1.20 |  |  | (0.47 | )
Total operating costs per barrel | 4.10 |  |  | 4.13 |  |  | (0.03 | )
Operating income per barrel | $ | 2.74 |  |  | $ | 1.06 |  |  | $ | 1.68 |
U.S. West Coast: |  |  |  |  |
Operating income (c) | $ | 53 |  |  | $ | 81 |  |  | $ | (28 | )
Throughput volumes (thousand barrels per day) | 255 |  |  | 237 |  |  | 18 |
Throughput margin per barrel (c) (e) | $ | 8.96 |  |  | $ | 9.71 |  |  | $ | (0.75 | )
Operating costs per barrel: |  |  |  |  |  |
Operating expenses | 5.46 |  |  | 5.37 |  |  | 0.09 |
Depreciation and amortization expense | 2.35 |  |  | 2.46 |  |  | (0.11 | )
Total operating costs per barrel | 7.81 |  |  | 7.83 |  |  | (0.02 | )
Operating income per barrel | $ | 1.15 |  |  | $ | 1.88 |  |  | $ | (0.73 | )
Operating income for regions above | $ | 1,856 |  |  | $ | 2,071 |  |  | $ | (215 | )
Asset impairment loss (d) | (611 | ) |  | — |  |  | (611 | )
Loss on derivative contracts related to the forward sales of refined product (c) | — |  |  | (542 | ) |  | 542 |
Total refining operating income | $ | 1,245 |  |  | $ | 1,529 |  |  | $ | (284 | )

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

| Six Months Ended June 30,
| 2012 |  | 2011 |  | Change
Feedstocks: |  |  |  |  |
Brent crude oil | $ | 113.64 |  |  | $ | 111.17 |  |  | $ | 2.47 |
Brent less WTI crude oil | 15.48 |  |  | 12.95 |  |  | 2.53 |
Brent less ANS crude oil | (0.01 | ) |  | 3.04 |  |  | (3.05 | )
Brent less LLS crude oil | (0.91 | ) |  | (0.32 | ) |  | (0.59 | )
Brent less Mars crude oil | 3.30 |  |  | 4.49 |  |  | (1.19 | )
Brent less Maya crude oil | 9.59 |  |  | 14.81 |  |  | (5.22 | )
LLS crude oil | 114.55 |  |  | 111.49 |  |  | 3.06 |
LLS less Mars crude oil | 4.21 |  |  | 4.81 |  |  | (0.60 | )
LLS less Maya crude oil | 10.50 |  |  | 15.13 |  |  | (4.63 | )
WTI crude oil | 98.16 |  |  | 98.22 |  |  | (0.06 | )
Natural gas (dollars per million British thermal units) | 2.32 |  |  | 4.24 |  |  | (1.92 | )
Products: |  |  |  |  |
U.S. Gulf Coast: |  |  |  |  |
Conventional 87 gasoline less Brent | 7.72 |  |  | 7.36 |  |  | 0.36 |
Ultra-low-sulfur diesel less Brent | 14.44 |  |  | 12.86 |  |  | 1.58 |
Propylene less Brent | (11.44 | ) |  | 23.16 |  |  | (34.60 | )
Conventional 87 gasoline less LLS | 6.81 |  |  | 7.04 |  |  | (0.23 | )
Ultra-low-sulfur diesel less LLS | 13.53 |  |  | 12.54 |  |  | 0.99 |
Propylene less LLS | (12.35 | ) |  | 22.76 |  |  | (35.11 | )
U.S. Mid-Continent: |  |  |  |  |
Conventional 87 gasoline less WTI | 22.80 |  |  | 21.14 |  |  | 1.66 |
Ultra-low-sulfur diesel less WTI | 29.03 |  |  | 26.97 |  |  | 2.06 |
North Atlantic: |  |  |  |  |
Conventional 87 gasoline less Brent | 10.08 |  |  | 6.54 |  |  | 3.54 |
Ultra-low-sulfur diesel less Brent | 15.99 |  |  | 14.63 |  |  | 1.36 |
U.S. West Coast: |  |  |  |  |
CARBOB 87 gasoline less ANS | 16.22 |  |  | 14.95 |  |  | 1.27 |
CARB diesel less ANS | 16.69 |  |  | 19.96 |  |  | (3.27 | )
CARBOB 87 gasoline less WTI | 31.71 |  |  | 24.86 |  |  | 6.85 |
CARB diesel less WTI | 32.18 |  |  | 29.87 |  |  | 2.31 |
New York Harbor corn crush (dollars per gallon) | (0.05 | ) |  | 0.07 |  |  | (0.12 | )

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Operating Highlights (continued)
(millions of dollars, except per gallon amounts)

| Six Months Ended June 30,
| 2012 |  | 2011 |  | Change
Retail–U.S.: |  |  |  |  |
Operating income | $ | 145 |  |  | $ | 106 |  |  | $ | 39 |
Company-operated fuel sites (average) | 998 |  |  | 994 |  |  | 4 |
Fuel volumes (gallons per day per site) | 5,104 |  |  | 4,995 |  |  | 109 |
Fuel margin per gallon | $ | 0.178 |  |  | $ | 0.142 |  |  | $ | 0.036 |
Merchandise sales | $ | 608 |  |  | $ | 606 |  |  | $ | 2 |
Merchandise margin (percentage of sales) | 29.8 | % |  | 28.3 | % |  | 1.5 | %
Margin on miscellaneous sales | $ | 46 |  |  | $ | 44 |  |  | $ | 2 |
Operating expenses | $ | 210 |  |  | $ | 201 |  |  | $ | 9 |
Depreciation and amortization expense | $ | 38 |  |  | $ | 37 |  |  | $ | 1 |
Retail–Canada: |  |  |  |  |
Operating income | $ | 67 |  |  | $ | 95 |  |  | $ | (28 | )
Fuel volumes (thousand gallons per day) | 3,107 |  |  | 3,208 |  |  | (101 | )
Fuel margin per gallon | $ | 0.271 |  |  | $ | 0.318 |  |  | $ | (0.047 | )
Merchandise sales | $ | 123 |  |  | $ | 125 |  |  | $ | (2 | )
Merchandise margin (percentage of sales) | 29.3 | % |  | 29.8 | % |  | (0.5 | )%
Margin on miscellaneous sales | $ | 22 |  |  | $ | 22 |  |  | $ | — |
Operating expenses | $ | 126 |  |  | $ | 130 |  |  | $ | (4 | )
Depreciation and amortization expense | $ | 18 |  |  | $ | 18 |  |  | $ | — |
Ethanol: |  |  |  |  |
Operating income | $ | 14 |  |  | $ | 108 |  |  | $ | (94 | )
Production (thousand gallons per day) | 3.415 |  |  | 3,340 |  |  | 75 |
Gross margin per gallon of production (e) | $ | 0.33 |  |  | $ | 0.54 |  |  | $ | (0.21 | )
Operating costs per gallon of production: |  |  |  |  |
Operating expenses | 0.28 |  |  | 0.33 |  |  | (0.05 | )
Depreciation and amortization expense | 0.03 |  |  | 0.03 |  |  | — |
Total operating costs per gallon of production | 0.31 |  |  | 0.36 |  |  | (0.05 | )
Operating income per gallon of production | $ | 0.02 |  |  | $ | 0.18 |  |  | $ | (0.16 | )

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The following notes relate to references on pages 46 through 50.

(a) | For the six months ended June 30, 2012, the financial highlights and operating highlights for the refining segment and U.S. Gulf Coast region include the results of operations of our Meraux Refinery, including related logistics assets, from the date of its acquisition on October 1, 2011.

(b) | For the six months ended June 30, 2012, the financial highlights and operating highlights for the refining segment and North Atlantic region include the results of operations of our Pembroke Refinery, including the related marketing and logistics business, from the date of its acquisition on August 1, 2011.

(c) | Cost of sales for the six months ended June 30, 2011 includes a loss of $542 million ($352 million after taxes) on commodity derivative contracts related to the forward sales of refined product. These contracts were closed and realized during the first quarter of 2011. The loss is reflected in refining segment operating income for the six months ended June 30, 2011, but throughput margin per barrel for the refining segment has been restated for the amount previously presented to exclude this $542 million loss ($1.35 per barrel). In addition, operating income and throughput margin per barrel for the U.S. Gulf Coast, U.S. Mid-Continent, and U.S. West Coast regions for the six months ended June 30, 2011 have been restated from the amounts previously presented to exclude the portion of this loss that had been allocated to them of $372 million ($1.51 per barrel); $122 million ($1.68 per barrel), and $48 million ($1.11 per barrel), respectively.

(d) | In March 2012, we concluded our evaluation of strategic alternatives for our refinery in Aruba (Aruba Refinery) and announced that we would temporarily suspend the refinery’s operations by the end of March. Because of this decision, we analyzed the Aruba Refinery for potential impairment and concluded that the refinery’s net book value (carrying amount) of $945 million was not recoverable through the future operations and disposition of the refinery. We determined that the fair value of the Aruba Refinery was $350 million; therefore, we recognized an asset impairment loss of $595 million. In addition, we recognized an asset impairment loss of $16 million related to equipment associated with a permanently cancelled capital project at another refinery. The total asset impairment loss of $611 million is reflected in refining segment operating income for the six months ended June 30, 2012, but it is excluded from operating costs per barrel for the refining segment and U.S. Gulf Coast region.

(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 Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, St. Charles, Aruba, Port Arthur, and Meraux Refineries; the U.S. Mid-Continent region includes the McKee, Ardmore, 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.

(h) | Average market reference prices for Brent crude oil, along with price differentials between the price of Brent crude oil and other types of crude oil, have been included in the table of Average Market Reference Prices and Differentials. The table also includes price differentials by region between the prices of certain products and the benchmark crude oil that provides a relevant indicator of product margins for each region. We previously provided feedstock and product differentials based on the price of WTI crude oil. However, the price of WTI crude oil no longer provides a reasonable benchmark price of crude oil for all regions. Beginning in late 2010, WTI crude oil began to price at a discount to benchmark sweet crude oils, such as Brent and LLS, because of increased WTI supplies resulting from greater U.S. production and increased deliveries of crude oil from Canada into the U.S. Mid-Continent region. We utilize Brent crude oil for price differentials because we believe it represents sweet crude oil prices for marginal refineries in the Atlantic Basin, and thus sets refined-product prices.

General
Operating revenues increased 21 percent (or $12.2 billion) for the first six months of 2012 compared to the first six months of 2011 primarily as a result of higher refined product prices and higher throughput volumes between the two periods related to our refining segment operations. The higher throughput volumes resulted primarily from the incremental throughput of 130,000 barrels per day from the Meraux Refinery, which was acquired on October 1, 2011, and incremental throughput of 248,000 barrels per day from the Pembroke Refinery, which was acquired on August 1, 2011. Operating income decreased $417 million and income from continuing operations before income tax expense decreased $392 million for the first six months of 2012 compared to amounts reported for the first six months of 2011 primarily due to a $284 million decrease in refining segment operating income and a $94 million decrease in ethanol segment operating income discussed below.
Refining
Refining segment operating income decreased 19 percent (or $284 million) from $1.5 billion for the first six months of 2011 to $1.2 billion for the first six months of 2012. This decrease was impacted by the
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$542 million loss on derivative contracts in the second quarter of 2011 and the $611 million asset impairment loss in the first quarter of 2012. (See Note 3 of Condensed Notes to Consolidated Financial Statements for further discussion of this asset impairment loss). Excluding these losses, refining segment operating income decreased $215 million from $2.1 billion in the first six months of 2011 to $1.9 billion in the first six months of 2012. This $215 million decrease was due primarily to a $275 million increase in operating expenses, partially offset by an $80 million increase in refining margin.
The increase of $275 million in operating expenses was primarily due to $73 million in operating expenses incurred by the Meraux Refinery and $184 million in operating expenses incurred by the Pembroke Refinery. The remaining increase of operating expenses of $18 million was primarily due to an increase in maintenance expenses.
The $80 million refining margin improvement was due to the margin generated by our Meraux and Pembroke Refineries of $91 million and $264 million, respectively, offset by a decrease in margin generated by the other refineries of our refining segment of $275 million. We acquired our Meraux and Pembroke Refineries in the last half of 2011; therefore, the margin generated by these refineries in the first six months of 2012 was fully incremental to our overall refining margin as compared to the first six months of 2011. The $275 million decrease in refining segment margin related to our other refineries was primarily due to an unfavorable decrease in the discount of the price of sour crude oils versus the price of sweet crude oils in the first six months of 2012 as compared to the first six months of 2011, partially offset by an increase in gasoline and distillate margins in the first six months of 2012 as compared to the first six months of 2011.
We estimate that the decrease in the discount of the price of sour crude oils versus the price of sweet crude oils reduced our refining margin by approximately $800 million for the first six months of 2012 versus the comparable 2011 period. For example, Maya crude oil, which is a type of sour crude oil, sold at a discount of $9.59 per barrel to Brent crude oil, which is a type of sweet crude oil, during the first six months of 2012. This compares to a discount of $14.81 per barrel during the first six months of 2011, representing an unfavorable decrease of $5.22 per barrel. We processed 1.0 million barrels per day of sour crude oils during the first six months of 2012; therefore, changes in the discount of the price of sour crude oils versus the price of sweet crude oils have a significant impact on our refining margins.
We estimate that the increase in gasoline and distillate margins increased our refining margin by approximately $600 million for the first six months of 2012 versus the comparable 2011 period. For example, the WTI-based benchmark reference margin for U.S. Mid-Continent conventional 87 gasoline and ultra-low-sulfur diesel (a type of distillate) was $22.80 per barrel and $29.03 per barrel, respectively, for the first six months of 2012 compared to $21.14 per barrel and $26.97 per barrel, respectively, for the first six months of 2011, representing a favorable increase of $1.66 per barrel and $2.06 per barrel, respectively. Other regions also experienced increases in gasoline and distillate margins. We produced 1.2 million barrels per day of gasoline and 0.9 million barrels per day of distillate during the first six months of 2012; therefore, changes in the margin we earn on these products have a significant impact on our refining margins.
Despite the refining margin improvement of $80 million and an 18 percent increase in total throughput volumes (a 394,000 barrel per day increase) between the comparable six-month periods, throughput margin per barrel decreased by 14 percent (or $1.50 per barrel). This decrease was largely due to the decrease in the discount of the price of sour crude oils versus the price of sweet crude oils in the first six months of 2012 versus the comparable 2011 period, which unfavorably impacted the margin we earn on the products we produce.
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Retail
Retail segment operating income was $212 million for the first six months of 2012 compared to $201 million for the first six months of 2011. This 5 percent (or $11 million) increase was primarily due to an increase in merchandise margins of $9 million and an increase in fuel margins from our U.S. retail operations of $37 million, partially offset by a $33 million decrease in fuel margins from our Canadian retail operations.
Ethanol
Ethanol segment operating income was $14 million for the first six months of 2012 compared to $108 million for the first six months of 2011. The $94 million decrease in operating income was primarily due to a $119 million decrease in gross margin, partially offset by a $27 million decrease in operating expenses.
The decrease in gross margin was due to a 39 percent decrease in the gross margin per gallon of ethanol production (a $0.21 per gallon decrease between the comparable periods) primarily due to lower ethanol prices in the first six months of 2012 versus the first six months of 2011. Ethanol prices in the first half of 2012 were pressured by a surplus of ethanol supply due to reduced demand for ethanol associated with the decline in gasoline demand in the U.S. In addition, ethanol production decreased 75,000 gallons per day between the comparable periods, resulting from lower utilization rates during the first half of 2012. The reduction in operating expenses was due primarily to a $32 million decrease in energy costs due to lower natural gas prices versus the comparable period of 2011, partially offset by a $4 million increase in chemical expenses between the periods.
Corporate Expenses and Other
General and administrative expenses increased $54 million from the first six months of 2011 to the first six months of 2012 primarily due to $48 million in administrative costs related to our European operations.
“Interest and debt expense, net of capitalized interest” for the first six months of 2012 decreased $51 million from the first six months of 2011. This decrease was primarily due to an increase of $46 million in capitalized interest due to a corresponding increase in capital expenditures between the six-month periods.
Income tax expense increased $58 million from the first six months of 2011 to the first six months of 2012 even though we reported lower income from continuing operations before income tax expense. The variation in the customary relationship between income tax expense and income from continuing operations before income tax expense for the six months ended June 30, 2012 was primarily due to not recognizing the tax benefit associated with the asset impairment loss of $595 million related to the Aruba Refinery as we do not expect to realize this tax benefit.
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LIQUIDITY AND CAPITAL RESOURCES
Cash Flows for the Six Months Ended June 30, 2012 and 2011
Net cash provided by operating activities for the first six months of 2012 was $3.0 billion, which was comparable to the first six months of 2011. The changes in cash provided by or used in working capital during the first six months of 2012 and 2011 are shown in Note 11 of Condensed Notes to Consolidated Financial Statements.
The net cash provided by operating activities during the first six months of 2012 combined with $300 million of proceeds from the remarketing of the 4.0% Gulf Opportunity Zone Revenue Bonds Series 2010 (GO Zone Bonds), $1.1 billion in borrowings under our revolving credit facility, and $1.3 billion of proceeds from the sale of receivables under our accounts receivable sales facility were used mainly to:

• | fund $1.7 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 bond for $108 million;

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

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

• | make repayments under our accounts receivable sales facility of $1.5 billion;

• | purchase common stock for treasury of $147 million;

• | pay common stock dividends of $166 million; and

• | increase available cash on hand by $271 million.

The net cash provided by operating activities during the first six months of 2011 was used mainly to:

• | fund $1.4 billion of capital expenditures and deferred turnaround and catalyst costs;

• | make scheduled long-term note repayments of $418 million and acquire the GO Zone Bonds for $300 million;

• | pay common stock dividends of $57 million; and

• | increase available cash on hand by $773 million.

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 higher volumes of sour crude oil, which lowers our feedstock costs, and enables us to refine crude oil into products with higher market values. Therefore, many of our improvements do not increase throughput capacity significantly.
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During the six months ended June 30, 2012, we expended $1.4 billion for capital expenditures and $264 million for deferred turnaround and catalyst costs. Capital expenditures for the six months ended June 30, 2012 included $41 million of costs related to environmental projects.
For 2012, we expect to incur approximately $3.1 billion for capital investments (approximately $100 million of which is for environmental projects) and $530 million for deferred turnaround and catalyst costs. The capital expenditure estimate excludes expenditures related to strategic business acquisitions. We continuously evaluate our capital budget and make changes as conditions warrant.
Contractual Obligations
As of June 30, 2012, our contractual obligations included debt, capital lease obligations, operating leases, purchase obligations, and other long-term liabilities.
During the six months ended June 30, 2012, we had no material changes outside the ordinary course of our business with respect to our debt, capital lease obligations, operating leases, purchase obligations, or other long-term liabilities.
During the six months ended June 30, 2012, the following debt activity occurred:

• | 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;

• | 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;

• | in May 2012, we borrowed $1.1 billion under our revolving credit facility;

• | in June 2012, we repaid $1.1 billion under our revolving credit facility; and

• | also in June 2012, we received proceeds of $300 million from the remarketing of the 4.0% GO Zone Bonds, which are due December 1, 2040, but are subject to mandatory tender on June 1, 2022.

As of June 30, 2012, we had an accounts receivable sales facility with a group of third-party entities and financial institutions to sell on a revolving basis up to $1.0 billion of eligible trade receivables. In July 2012, we amended our agreement to increase the facility to $1.5 billion and to extend the maturity date to July 2013. During the six months ended June 30, 2012, we sold $1.3 billion of interests in eligible receivables to the third-party entities and financial institutions under this facility, and we repaid $1.5 billion under this facility. As of June 30, 2012, the amount of interests in eligible receivables sold was $100 million.
Our 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
Standard & Poor’s Ratings Services |  | BBB (negative outlook)
Moody’s Investors Service |  | Baa2 (stable 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 June 30, 2012, 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 2013 |  | $ | 300 |
Revolving credit facility |  | $ | 3,000 |  |  | December 2016 |  | $ | 70 |
Canadian revolving credit facility |  | C$ | 115 |  |  | December 2012 |  | C$ | 11 |

In July 2012, one of our letter of credit facilities was amended to extend its maturity date through June 2013 and to increase its borrowing capacity by $50 million. The borrowing capacity and expiration shown in the table above reflect these changes. As of June 30, 2012, we had no amounts borrowed under our revolving credit facilities. The letters of credit outstanding as of June 30, 2012 expire during 2012 and 2013.
Other Matters Impacting Liquidity and Capital Resources
Pension Plan Funded Status
We have minimum required contributions of $2 million during 2012 to our pension plans that have minimum funding requirements; however, we plan to contribute approximately $100 million to our pension plans during 2012. During the six months ended June 30, 2012, we contributed $13 million to our pension plans. In July 2012, we contributed $50 million to our pension plans.
Stock Purchase Programs
As of June 30, 2012, we have approvals under common stock purchase programs to purchase approximately $3.5 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.
Tax Matters
We are subject to extensive tax liabilities imposed by multiple jurisdictions, including income taxes, transactional taxes (excise/duty, sales/use, and value-added taxes), payroll taxes, franchise taxes, withholding
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taxes, and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. Many of these liabilities are subject to periodic audits by the respective taxing authority. Subsequent changes to our tax liabilities as a result of these audits may subject us to interest and penalties. See Note 6 of Condensed Notes to Consolidated Financial Statements for a further discussion of our tax matters.
As of June 30, 2012, the Internal Revenue Service (IRS) has ongoing tax audits related to our U.S. federal tax returns from 2002 through 2009, as discussed in Note 6 of Condensed Notes to Consolidated Financial Statements. We have received Revenue Agent Reports on our tax years for 2002 through 2007 and we are vigorously contesting the tax positions and assertions from the IRS. Although we believe our tax liabilities are fairly stated and properly reflected in our financial statements, should the IRS eventually prevail, it could result in a material amount of our deferred tax liabilities being reclassified to current liabilities which could have a material adverse effect on our liquidity.
Cash Held by Our International Subsidiaries
We operate in countries outside the U.S. through subsidiaries incorporated in these countries, and the earnings of these subsidiaries are taxed by the countries in which they are incorporated. We intend to reinvest these earnings indefinitely in our international operations even though we are not restricted from repatriating such earnings to the U.S. in the form of cash dividends. Should we decide to repatriate such earnings, we would incur and pay taxes on the amounts repatriated. In addition, such repatriation could cause us to record deferred tax expense that could significantly impact our results of operations. We believe, however, that a substantial portion of our international cash can be returned to the U.S. without significant tax consequences through means other than a repatriation of earnings. As of June 30, 2012, $1.1 billion of our cash and temporary cash investments was held by our international subsidiaries.
Financial Regulatory Reform
On July 21, 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. Final rules implementing the Wall Street Reform Act are expected to become effective in late 2012 and early 2013; therefore, the impact to our operations is yet unknown. However, the implementation could result in higher clearing costs and more reporting requirements with respect to our derivative activities.
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.
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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, 2011.

Item 3. | Quantitative and Qualitative Disclosures About Market Risk

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

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

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

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

| Derivative Instruments Held For
| Non-Trading Purposes |  | Trading Purposes
June 30, 2012: |  |  |
Gain (loss) in fair value resulting from: |  |  |
10% increase in underlying commodity prices | $ | (196 | ) |  | $ | (10 | )
10% decrease in underlying commodity prices | 196 |  |  | 9 |
December 31, 2011: |  |  |
Gain (loss) in fair value resulting from: |  |  |
10% increase in underlying commodity prices | (156 | ) |  | 1 |
10% decrease in underlying commodity prices | 156 |  |  | 2 |

See Note 13 of Condensed Notes to Consolidated Financial Statements for notional volumes associated with these derivative contracts as of June 30, 2012.
COMPLIANCE PROGRAM PRICE RISK
We are exposed to market risks related to the volatility in the price of financial instruments associated with
various governmental and regulatory compliance programs that we must purchase in the open market to comply with these programs. To reduce the impact of this risk on our results of operations and cash flows, we may enter into derivative instruments, such as futures. As of June 30, 2012, there was no significant gain or loss in the fair value of derivative instruments that would result from a 10 percent increase or decrease in the underlying price of the futures contracts. See Note 13 of Condensed Notes to Consolidated Financial Statements for a discussion about these compliance programs and notional volumes associated with these derivative contracts as of June 30, 2012.
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INTEREST RATE RISK
The following table provides information about our debt instruments, excluding capital lease obligations (dollars in millions), the fair values of which are sensitive to changes in interest rates. Principal cash flows and related weighted-average interest rates by expected maturity dates are presented. We had no interest rate derivative instruments outstanding as of June 30, 2012 or December 31, 2011.

| June 30, 2012
| Expected Maturity Dates |  |  |  |
| 2012 |  | 2013 |  | 2014 |  | 2015 |  | 2016 |  | There- after |  | Total |  | Fair Value
Debt: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate | $ | — |  |  | $ | 480 |  |  | $ | 200 |  |  | $ | 475 |  |  | $ | — |  |  | $ | 5,774 |  |  | $ | 6,929 |  |  | $ | 8,087 |
Average interest rate | — | % |  | 5.5 | % |  | 4.8 | % |  | 5.2 | % |  | — | % |  | 7.1 | % |  | 6.8 | % |  |
Floating rate | $ | 100 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 100 |  |  | $ | 100 |
Average interest rate | 0.6 | % |  | — | % |  | — | % |  | — | % |  | — | % |  | — | % |  | 0.6 | % |  |
| December 31, 2011
| Expected Maturity Dates |  |  |  |
| 2012 |  | 2013 |  | 2014 |  | 2015 |  | 2016 |  | There- after |  | Total |  | Fair Value
Debt: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Fixed rate | $ | 754 |  |  | $ | 484 |  |  | $ | 200 |  |  | $ | 475 |  |  | $ | — |  |  | $ | 5,578 |  |  | $ | 7,491 |  |  | $ | 9,048 |
Average interest rate | 6.9 | % |  | 5.5 | % |  | 4.8 | % |  | 5.2 | % |  | — | % |  | 7.3 | % |  | 6.9 | % |  |
Floating rate | $ | 250 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 250 |  |  | $ | 250 |
Average interest rate | 0.6 | % |  | — | % |  | — | % |  | — | % |  | — | % |  | — | % |  | 0.6 | % |  |

FOREIGN CURRENCY RISK
As of June 30, 2012, we had commitments to purchase $634 million of U.S. dollars. Our market risk was minimal on these contracts, as they matured on or before July 31, 2012, resulting in a loss of approximately $1 million in the third quarter of 2012.
Item 4. Controls and Procedures

(a) | Evaluation of disclosure controls and procedures.

Our management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of June 30, 2012.

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

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

Item 1. | Legal Proceedings

The information below describes new proceedings or material developments in proceedings that we previously reported in our annual report on Form 10-K for the year ended December 31, 2011, or our quarterly report on Form 10-Q for the quarter ended March 31, 2012.
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 not possible to predict the outcome of the following environmental proceedings, if any one or more of them were decided against us, we believe that there would be no material effect on our financial position 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 into the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $100,000 or more.
Bay Area Air Quality Management District (BAAQMD) (Benicia Refinery). In our annual report on Form 10-K for the year ended December 31, 2011, we reported that we had several 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 second quarter of 2012, we settled 14 VNs that were issued in 2010 and 2011.
South Coast Air Quality Management District (SCAQMD) (Wilmington Refinery). The SCAQMD has issued 27 notices of violation (NOVs) to our Wilmington Refinery and asphalt plant for alleged excess emission events, reporting issues, and administrative errors in 2010 and 2011. We are negotiating with the SCAQMD to resolve these matters.
Item 1A. Risk Factors
We are updating one of our risk factors to describe the cybersecurity risks that we face. Except for the modified risk factor presented below, 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, 2011.
A significant interruption in one or more of our refineries could adversely affect our business.
Our refineries are our principal operating assets. As a result, our operations could be subject to significant interruption if one or more of our refineries were to experience a major accident or mechanical failure, encounter work stoppages relating to organized labor issues, be damaged by severe weather or other natural or man-made disaster, such as an act of terrorism, or otherwise be forced to shut down. If any refinery were to experience an interruption in operations, earnings from the refinery could be materially adversely affected (to the extent not recoverable through insurance) because of lost production and repair costs. Significant interruptions in our refining system could also lead to increased volatility in prices for crude oil feedstocks and refined products, and could increase instability in the financial and insurance markets, making it more difficult for us to access capital and to obtain insurance coverage that we consider adequate.
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In addition, our information technology systems and network infrastructure are subject to unauthorized access or attack, which could result in a loss of sensitive business information, systems interruption, or the disruption of our business operations. To protect against unauthorized access or attacks, we have implemented infrastructure protection technologies and disaster recovery plans, but there can be no assurance that a technology systems breach or systems failure will not have a material adverse effect on our financial condition or results of operations.

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

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

(b) | Use of Proceeds. Not applicable.

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

Period | Total Number of Shares Purchased | Average Price Paid per Share | Total Number of Shares Not Purchased as Part of Publicly Announced Plans or Programs (a) | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (b)
April 2012 | 204,364 |  | $ | 23.97 |  | 204,364 |  | — |  | $3.46 billion
May 2012 | 588,845 |  | $ | 21.79 |  | 588,845 |  | — |  | $3.46 billion
June 2012 | 1,051,618 |  | $ | 22.30 |  | 1,051,618 |  | — |  | $3.46 billion
Total | 1,844,827 |  | $ | 22.32 |  | 1,844,827 |  | — |  | $3.46 billion

(a) | The shares reported in this column represent purchases settled during the three months ended June 30, 2012 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.

Item 6. Exhibits

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

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

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

Date: August 8, 2012
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