3rd Quarter 2011 (10-Q)

Source Quarterly 10-Q
Company Valero Energy Corporation 
Tags Financial & Operating Data
Date November 09, 2011

 UNITED STATES

 SECURITIES AND EXCHANGE COMMISSION

 Washington, D.C. 20549

 FORM 10-Q

 (Mark One)

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

 For the quarterly period ended  September 30, 2011

 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 shorter period that the registrant was required to submit and post such files). Yes  R  No  o


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

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


 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 Yes  o  No  R

 The number of shares of the registrant’s only class of common stock, $0.01 par value, outstanding as of  October 31, 2011  was  559,726,988 .

 
         
         

 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 INDEX

 
   
   
   Page 
 PART I – FINANCIAL INFORMATION   
 Item 1. Financial Statements   
 Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010  3 
 Consolidated Statements of Income for the Three and Nine Months Ended  September 30, 2011 and 2010  4 
 Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010  5 
 Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended  September 30, 2011 and 2010  6 
 Condensed Notes to Consolidated Financial Statements  7 
 Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations  38 
 Item 3. Quantitative and Qualitative Disclosures About Market Risk  64 
 Item 4. Controls and Procedures  66 
 PART II – OTHER INFORMATION   
 Item 1. Legal Proceedings  67 
 Item 1A. Risk Factors  67 
 Item 2. Unregistered Sales of Equity Securities and Use of Proceeds  68 
 Item 6. Exhibits  68 
 SIGNATURE  69 
 
 
 
 
 
 
 
 
 
 






 2

 Table of Contents


 PART I – FINANCIAL INFORMATION

 Item 1. Financial Statements


 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONSOLIDATED BALANCE SHEETS

 (Millions of Dollars, Except Par Value)

 
               
   September 30,  
 2011 
   December 31,  
 2010 
   (Unaudited)     
 ASSETS       
 Current assets:       
 Cash and temporary cash investments   $   2,829 
 
   $   3,334 
 
 Receivables, net   7,509 
 
   4,583 
 
 Inventories   5,164 
 
   4,947 
 
 Income taxes receivable   5 
 
   343 
 
 Deferred income taxes   254 
 
   190 
 
 Prepaid expenses and other   109 
 
   121 
 
 Total current assets   15,870 
 
   13,518 
 
 Property, plant and equipment, at cost   31,066 
 
   28,921 
 
 Accumulated depreciation   (6,847   )     (6,252   ) 
 Property, plant and equipment, net   24,219 
 
   22,669 
 
 Intangible assets, net   251 
 
   224 
 
 Deferred charges and other assets, net   1,343 
 
   1,210 
 
 Total assets   $   41,683 
 
   $   37,621 
 
 LIABILITIES AND EQUITY       
 Current liabilities:       
 Current portion of debt and capital lease obligations   $   867 
 
   $   822 
 
 Accounts payable   8,520 
 
   6,441 
 
 Accrued expenses   785 
 
   590 
 
 Taxes other than income taxes   1,053 
 
   671 
 
 Income taxes payable   136 
 
   3 
 
 Deferred income taxes   322 
 
   257 
 
 Total current liabilities   11,683 
 
   8,784 
 
 Debt and capital lease obligations, less current portion   6,781 
 
   7,515 
 
 Deferred income taxes   4,942 
 
   4,530 
 
 Other long-term liabilities   1,607 
 
   1,767 
 
 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   7,559 
 
   7,704 
 
 Treasury stock, at cost; 114,855,199 and 105,113,545 common shares   (6,491   )     (6,462   ) 
 Retained earnings   15,347 
 
   13,388 
 
 Accumulated other comprehensive income   232 
 
   388 
 
 Total  Valero Energy Corporation stockholders’ equity   16,654 
 
   15,025 
 
 Noncontrolling interests   16 
 
   — 
 
 Total equity   16,670 
 
   15,025 
 
 Total liabilities and equity   $   41,683 
 
   $   37,621 
 

 See Condensed Notes to Consolidated Financial Statements.




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 Table of Contents


 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONSOLIDATED STATEMENTS OF INCOME

 (Millions of Dollars, Except Per Share Amounts)

 (Unaudited)

 
                               
   Three Months Ended September 30,     Nine Months Ended September 30, 
   2011     2010     2011     2010 
 Operating revenues (a)   $   33,713 
 
   $   21,015 
 
   $   91,314 
 
   $   60,069 
 
 Costs and expenses:               
 Cost of sales   30,033 
 
   18,915 
 
   82,981 
 
   54,198 
 
 Operating expenses:               
 Refining   870 
 
   753 
 
   2,427 
 
   2,210 
 
 Retail   177 
 
   169 
 
   508 
 
   484 
 
 Ethanol   103 
 
   96 
 
   302 
 
   267 
 
 General and administrative expenses   161 
 
   139 
 
   442 
 
   367 
 
 Depreciation and amortization expense   390 
 
   353 
 
   1,141 
 
   1,043 
 
 Asset impairment loss   — 
 
   — 
 
   — 
 
   2 
 
 Total costs and expenses   31,734 
 
   20,425 
 
   87,801 
 
   58,571 
 
 Operating income   1,979 
 
   590 
 
   3,513 
 
   1,498 
 
 Other income, net   1 
 
   17 
 
   28 
 
   29 
 
 Interest and debt expense, net of capitalized interest   (88   )     (119   )     (312   )     (363   ) 
 Income from continuing operations before income tax expense   1,892 
 
   488 
 
   3,229 
 
   1,164 
 
 Income tax expense   689 
 
   185 
 
   1,178 
 
   421 
 
 Income from continuing operations   1,203 
 
   303 
 
   2,051 
 
   743 
 
 Income (loss) from discontinued operations, net of income taxes   — 
 
   (11   )     (7   )     19 
 
 Net income   1,203 
 
   292 
 
   2,044 
 
   762 
 
 Less: Net loss attributable to noncontrolling interests   — 
 
   — 
 
   (1   )     — 
 
 Net income attributable to  Valero Energy Corporation stockholders   $   1,203 
 
   $   292 
 
   $   2,045 
 
   $   762 
 
 Net income attributable to  Valero Energy Corporation stockholders:               
 Continuing operations   $   1,203 
 
   $   303 
 
   $   2,052 
 
   $   743 
 
 Discontinued operations   — 
 
   (11   )     (7   )     19 
 
 Total   $   1,203 
 
   $   292 
 
   $   2,045 
 
   $   762 
 
 Earnings per common share:               
 Continuing operations   $   2.12 
 
   $   0.54 
 
   $   3.61 
 
   $   1.31 
 
 Discontinued operations   — 
 
   (0.02   )     (0.01   )     0.03 
 
 Total   $   2.12 
 
   $   0.52 
 
   $   3.60 
 
   $   1.34 
 
 Weighted-average common shares outstanding (in millions)   564 
 
   564 
 
   566 
 
   563 
 
 Earnings per common share – assuming dilution:               
 Continuing operations   $   2.11 
 
   $   0.53 
 
   $   3.59 
 
   $   1.31 
 
 Discontinued operations   — 
 
   (0.02   )     (0.01   )     0.03 
 
 Total   $   2.11 
 
   $   0.51 
 
   $   3.58 
 
   $   1.34 
 
 Weighted-average common shares outstanding –   assuming dilution (in millions)   569 
 
   568 
 
   572 
 
   567 
 
 Dividends per common share   $   0.05 
 
   $   0.05 
 
   $   0.15 
 
   $   0.15 
 

 
                               
 Supplemental information:               
 (a) Includes excise taxes on sales by our U.S. retail system   $   229 
 
   $   234 
 
   $   670 
 
   $   667 
 

 See Condensed Notes to Consolidated Financial Statements.




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 Table of Contents


 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONSOLIDATED STATEMENTS OF CASH FLOWS

 (Millions of Dollars)

 (Unaudited)

 
               
   Nine Months Ended
 September 30, 
   2011     2010 
 Cash flows from operating activities:       
 Net income   $   2,044 
 
   $   762 
 
 Adjustments to reconcile net income to net cash provided by   operating activities:       
 Depreciation and amortization expense   1,141 
 
   1,096 
 
 Noncash interest expense and other income, net   20 
 
   8 
 
 Asset impairment loss   — 
 
   2 
 
 Gain on sale of Delaware City Refinery assets   — 
 
   (92   ) 
 Stock-based compensation expense   34 
 
   32 
 
 Deferred income tax expense   393 
 
   285 
 
 Changes in current assets and current liabilities   840 
 
   592 
 
 Changes in deferred charges and credits and other operating activities, net   (144   )     (63   ) 
 Net cash provided by operating activities   4,328 
 
   2,622 
 
 Cash flows from investing activities:       
 Capital expenditures   (1,584   )     (1,226   ) 
 Deferred turnaround and catalyst costs   (501   )     (410   ) 
 Acquisition of Pembroke Refinery, net of cash acquired   (1,675   )     — 
 
 Acquisition of pipeline and terminal facilities   (37   )     — 
 
 Acquisitions of ethanol plants   — 
 
   (260   ) 
 Proceeds from sale of the Delaware City Refinery assets and   associated terminal and pipeline assets   — 
 
   220 
 
 Other investing activities, net   (24   )     15 
 
 Net cash used in investing activities   (3,821   )     (1,661   ) 
 Cash flows from financing activities:       
 Non-bank debt:       
 Borrowings   — 
 
   1,244 
 
 Repayments   (718   )     (517   ) 
 Accounts receivable sales program:       
 Proceeds from the sale of receivables   — 
 
   1,225 
 
 Repayments   — 
 
   (1,325   ) 
 Purchase of common stock for treasury   (270   )     (2   ) 
 Issuance of common stock in connection with stock-based compensation plans   42 
 
   12 
 
 Common stock dividends   (85   )     (85   ) 
 Debt issuance costs   — 
 
   (10   ) 
 Contributions from noncontrolling interests   12 
 
   — 
 
 Other financing activities, net   17 
 
   5 
 
 Net cash provided by (used in) financing activities   (1,002   )     547 
 
 Effect of foreign exchange rate changes on cash   (10   )     19 
 
 Net increase (decrease) in cash and temporary cash investments   (505   )     1,527 
 
 Cash and temporary cash investments at beginning of period   3,334 
 
   825 
 
 Cash and temporary cash investments at end of period   $   2,829 
 
   $   2,352 
 

 See Condensed Notes to Consolidated Financial Statements.




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 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 (Millions of Dollars)

 (Unaudited)


 
                               
   Three Months Ended September 30,     Nine Months Ended September 30, 
   2011     2010     2011     2010 
 Net income   $   1,203 
 
   $   292 
 
   $   2,044 
 
   $   762 
 
 Other comprehensive income (loss):               
 Foreign currency translation adjustment   (278   )     100 
 
   (166   )     63 
 
 Pension and other postretirement benefits:               
 Net loss arising during the period,   net of income tax benefit of $-, $-, $-, and $-   — 
 
   — 
 
   — 
 
   (21   ) 
 Net gain reclassified into income,   net of income tax expense of $1, $2, $2, and $2   (1   )     (2   )     (3   )     (4   ) 
 Net loss on pension and other   postretirement benefits   (1   )     (2   )     (3   )     (25   ) 
               
 Derivative instruments designated and   qualifying as cash flow hedges:               
 Net gain (loss) arising during the period,   net of income tax (expense) benefit of   $(7), $-, $(7), and $1   13 
 
   — 
 
   13 
 
   (1   ) 
 Net gain reclassified into income,   net of income tax expense of $-, $13, $-, and $47   — 
 
   (24   )     — 
 
   (88   ) 
 Net gain (loss) on cash flow hedges   13 
 
   (24   )     13 
 
   (89   ) 
 Other comprehensive income (loss)   (266   )     74 
 
   (156   )     (51   ) 
 Comprehensive income   937 
 
   366 
 
   1,888 
 
   711 
 
 Less: Comprehensive loss attributable to   noncontrolling interests   — 
 
   — 
 
   (1   )     — 
 
 Comprehensive income attributable to    Valero Energy Corporation stockholders   $   937 
 
   $   366 
 
   $   1,889 
 
   $   711 
 

 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 consolidated financial statements have been prepared in accordance with United States 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 GAAP for complete consolidated financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. All such adjustments are of a normal recurring nature unless disclosed otherwise. Financial information for the three and  nine months ended  September 30, 2011  and  2010  included in these Condensed Notes to Consolidated Financial Statements is derived from our unaudited consolidated financial statements. Operating results for the three and  nine  months ended  September 30, 2011  are not necessarily indicative of the results that may be expected for the year ending December 31, 2011.


 The consolidated balance sheet as of  December 31, 2010  has been derived from our audited financial statements as of that date. For further information, refer to our consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2010 .

 We have evaluated subsequent events that occurred after  September 30, 2011  through the filing of this Form 10-Q. Any material subsequent events that occurred during this time have been properly recognized or disclosed in these financial statements.


 Noncontrolling Interests

 In connection with the acquisition of the Pembroke Refinery (see further discussion in Note 2), we acquired an  85 percent  interest in Mainline Pipelines Limited (MLP). MLP owns a pipeline that distributes refined products from the Pembroke Refinery to terminals in the United Kingdom.


 On  January 21, 2011 , we entered into a joint venture agreement with Darling Green Energy LLC, a subsidiary of Darling International, Inc., to form Diamond Green Diesel Holdings LLC (DGD Holdings). DGD Holdings, through its wholly owned subsidiary, Diamond Green Diesel LLC (DGD), will construct and operate a biomass-based diesel plant having a design feed capacity of  10,000  barrels per day that will process animal fats, used cooking oils, and other vegetable oils into renewable green diesel. The plant will be located next to our St. Charles Refinery. The aggregate cost of this facility is estimated to be approximately  $368 million  and the construction is expected to be completed in late 2012. The joint venture agreement requires that contributions be made to DGD Holdings based on the percentage of units held by each member, which is currently on a  50/50  basis. In addition, on  May 31, 2011 , we agreed to lend DGD up to  $221 million  in order to finance  60 percent  of the construction costs of the plant.


 Because of our controlling financial interests in MLP and DGD Holdings, we have included the financial statements of MLP and DGD Holdings in these consolidated financial statements and have separately disclosed the related noncontrolling interests.




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 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


 Significant Accounting Policies

 Reclassifications

 As discussed in Note 2, we sold our Paulsboro Refinery in December 2010. As a result, the results of operations of the Paulsboro Refinery have been reclassified to discontinued operations for the three and  nine  months ended  September 30, 2010 .


 In addition, credit card fees previously recognized in 2010 in retail operating expenses have been reclassified to cost of sales as such fees are directly and jointly related to the sale transaction. This reclassification resulted in an increase in cost of sales and a decrease in retail operating expenses of  $23 million  and  $68 million  for the three and  nine months ended September 30,   2010 , respectively.


 Use of Estimates

 The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the amounts reported in the consolidated 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.


 New Accounting Pronouncements

 In June 2011, the provisions of Accounting Standards Codification (ASC)  Topic 220, “Comprehensive Income,” were amended to allow an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In both choices, the entity is required to present reclassification adjustments on the face of the financial statements for items that are reclassified from other comprehensive income to net income in the statement where those components are presented. These provisions are effective for the first interim or annual period beginning after December 15, 2011, and are to be applied retrospectively, with early adoption permitted. The adoption of this guidance effective January 1, 2012 will not affect our financial position or results of operations because these requirements only affect disclosures.


 In May 2011, the provisions of ASC  Topic 820, “Fair Value Measurement,” were amended to clarify the application of existing fair value measurement requirements and to change certain fair value measurement and disclosure requirements. Amendments that change measurement and disclosure requirements relate to (i) fair value measurement of financial instruments that are managed within a portfolio, (ii) application of premiums and discounts in a fair value measurement, and (iii) additional disclosures about fair value measurements categorized within Level 3 of the fair value hierarchy. These provisions are effective for the first interim or annual period beginning after December 15, 2011. The adoption of this guidance effective January 1, 2012 will not affect our financial position or results of operations, but may result in additional disclosures.


 In January 2011, the provisions of ASC  Topic 310, “Receivables,” were amended to delay temporarily the effective date of disclosures relating to troubled debt restructurings, which were previously amended in July 2010, in order to allow the Financial Accounting Standards Board time to complete its deliberations on what constitutes a troubled debt restructuring. In April 2011, the provisions of ASC  Topic 310 were amended to clarify the guidance on a creditor’s evaluations of whether it has granted a concession to the debtor and whether the debtor is experiencing financial difficulties. These provisions are effective for the first interim




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 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


 or annual period beginning on or after June 15, 2011. The new guidance should be applied retrospectively to restructurings occurring on or after the beginning of the annual period of adoption, with early adoption permitted. The adoption of this guidance effective July 1, 2011 did not affect our financial position or results of operations.


   
 2.   ACQUISITIONS AND DISPOSITIONS 


 Meraux Acquisition

 On  October 1, 2011 , we acquired the Meraux Refinery and related logistics assets for an initial payment of  $586 million , including inventories of  $261 million , from  Murphy Oil Corporation, with the total purchase price funded from available cash. We expect to receive a favorable adjustment related to inventories in the fourth quarter of 2011 that will reduce the purchase price by approximately  $40 million . The Meraux Refinery has a total throughput capacity of  135,000  barrels per day and is located in Meraux, Louisiana. This acquisition is referred to as the Meraux Acquisition.


 The Meraux Acquisition is consistent with our general business strategy and complements our existing refining and marketing network.


 A determination of the acquisition-date fair values of the assets acquired and the liabilities assumed in the Meraux Acquisition is pending the completion of an independent appraisal and other evaluations. Disclosure of pro forma information for the Meraux Acquisition for the three and  nine months ended September 30,  2011 and 2010 is impracticable as historical financial information is not readily available at this time.


 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. Valero Energy Ltd owns and operates the Pembroke Refinery, which has a total throughput capacity of approximately  270,000  barrels per day and is located in Wales, United Kingdom. Valero Energy Ltd also owns, directly and through various subsidiaries, an extensive network of marketing and logistics assets throughout the United Kingdom and Ireland. On the acquisition date, we initially paid  $1.8 billion  from available cash, of which  $1.1 billion was for working capital. Subsequent to the acquisition date, the amounts paid have been favorably adjusted for working capital true-up adjustments (primarily inventory), with an adjusted purchase price of  $1.675 billion , as outlined below. We expect final settlement by year end. This acquisition is referred to as the Pembroke Acquisition.


 The Pembroke Acquisition is consistent with our general business strategy and broadens the geographic diversity of our refining and marketing network.





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 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


 The purchase price for the Pembroke Acquisition has been preliminarily allocated based on estimated fair values of the assets acquired and liabilities assumed at the acquisition date, pending the completion of an independent appraisal and other evaluations. The preliminary purchase price allocation as of September 30, 2011 was as follows (in millions):


 
       
 Current assets, net of cash acquired   $   2,217 
 
 Property, plant and equipment   777 
 
 Deferred charges and other assets   17 
 
 Intangible assets   50 
 
 Current liabilities, less current portion of debt and capital lease obligations   (1,294   ) 
 Debt and capital leases assumed, including current portion   (12   ) 
 Other long-term liabilities   (77   ) 
 Noncontrolling interest   (3   ) 
 Purchase price, net of cash acquired   $   1,675 
 


 The acquired intangible assets are subject to amortization and have preliminary estimated useful lives of  15  years. These acquired intangible assets have been preliminarily assigned to the major intangible asset classes of royalties and licenses and wholesale dealer agreements.


 During the three and  nine months ended September 30,  2011, we recognized  $18 million  and  $23 million , respectively, of costs related to the Pembroke Acquisition. These costs were expensed and are included in general and administrative expenses.


 Our consolidated statements of income include the results of operations of the Pembroke Acquisition commencing on August 1, 2011. The operating revenues and income from continuing operations associated with the Pembroke Acquisition included in our consolidated statements of income for the three and  nine months ended September 30,  2011, were as follows (in millions):


 
                       
   Three Months Ended September 30,     Nine Months Ended September 30, 
   2011     2010     2011     2010 
 Operating revenues   $   3,028 
 
   N/A     $   3,028 
 
   N/A 
 Income from continuing operations   19 
 
   N/A     19 
 
   N/A 





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 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


 The following pro forma financial information (in millions, except per share amounts) presents our consolidated results assuming the Pembroke Acquisition occurred on January 1, 2010. The pro forma financial information is not necessarily indicative of the results of future operations.


 
                               
   Three Months Ended September 30,     Nine Months Ended September 30, 
   2011     2010     2011     2010 
 Operating revenues   $   35,491 
 
   $   24,594 
 
   $   103,030 
 
   $   70,638 
 
 Income from continuing operations   attributable to Valero stockholders   1,196 
 
   306 
 
   1,941 
 
   767 
 
 Earnings per common share from   continuing operations – basic   2.11 
 
   0.54 
 
   3.41 
 
   1.36 
 
 Earnings per common share from   continuing operations – assuming dilution   2.10 
 
   0.54 
 
   3.39 
 
   1.35 
 


 Acquisition of Pipeline and Terminal Facilities

 In June 2011, we acquired  two  product terminal facilities in Louisville and Lexington, Kentucky and a minority interest in the LouLex Pipeline system, which connects the terminal facilities, from a subsidiary of Chevron for cash consideration of  $37 million . These assets provide storage and distribution facilities for our wholesale marketing business in eastern Kentucky, which is supplied primarily by our Memphis Refinery.


 Because this acquisition was not material to our results of operations, we have not presented actual results of operations for this acquisition from the acquisition date through  September 30, 2011  or pro forma results of operations for the three and  nine months ended September 30, 2011  and  2010 . The consolidated statements of income for the three and  nine  months ended  September 30, 2011  include the results of this acquisition from its acquisition date.


 Acquisitions of Ethanol Plants

 In December 2009, we signed an agreement with ASA Ethanol Holdings, LLC to buy  two  ethanol plants located in Linden, Indiana and Bloomingburg, Ohio and made a  $20 million  advance payment towards the acquisition of these plants. In January 2010, we completed the acquisition of these plants, including certain inventories, for total consideration of  $202 million .


 Also in December 2009, we received approval from a bankruptcy court to acquire  an  ethanol plant located near Jefferson, Wisconsin from Renew Energy LLC and made a  $1 million  advance payment towards the acquisition of this plant. We completed the acquisition of this plant, including certain receivables and inventories, in February 2010 for total consideration of  $79 million .





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 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


 Disposition of Paulsboro Refinery

 In  December 2010 , we sold our Paulsboro Refinery to PBF Holding Company LLC (PBF Holding) for total proceeds of  $707 million , including  $361 million  from the sale of working capital, resulting in a pre-tax loss of  $980 million  ( $610 million  after taxes). The sale proceeds consisted of  $547 million  of cash and a  $160 million  note secured by the Paulsboro Refinery. The note matures in  December 2011  and bears interest at  LIBOR plus 700 basis points . PBF Holding has the option to extend the note for six months; however, the interest rate for the additional six months will be  LIBOR plus 900 basis points .


 The results of operations of the Paulsboro Refinery are reflected in discontinued operations, and selected results prior to its sale are shown below (in millions).


 
                 
     Three Months Ended
 September 30, 2010 
   Nine Months Ended
 September 30, 2010 
 Operating revenues     $   1,195 
 
   $   3,559 
 
 Loss before income taxes     (18   )     (36   ) 


 Disposition of Delaware City Refinery Assets and Associated Terminal and Pipeline Assets

 In  June 2010 , we sold our shutdown Delaware City Refinery assets and associated terminal and pipeline assets to wholly owned subsidiaries of PBF Energy Partners LP (PBF) for  $220 million  of cash proceeds. The sale resulted in a gain of  $92 million  ( $58 million  after taxes) related to the shutdown refinery assets and a gain of  $3 million  related to the terminal and pipeline assets. The gain on the sale of the shutdown refinery assets resulted from the proceeds we received for the scrap value of the assets and the reversal of certain liabilities recorded in the fourth quarter of 2009 associated with the shutdown of the refinery, which we did not incur because of the sale, and this gain is presented in discontinued operations for the  nine  months ended  September 30, 2010 .


 Results of operations of the Delaware City Refinery are reflected in discontinued operations, and selected results prior to its sale, excluding the gain on the sale, are shown below (in millions):


 
               
   Three Months Ended September 30, 2010     Nine Months Ended September 30, 2010 
 Operating revenues   $   — 
 
   $   — 
 
 Loss before income taxes   — 
 
   (33   ) 





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 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


   
 3.   IMPAIRMENT ANALYSIS 


 In late 2008, the U.S. and worldwide economies experienced severe disruptions in their capital and commodities markets resulting in a significant slowdown that persisted throughout 2009. This slowdown negatively impacted refining industry fundamentals and the demand and price for our refined products. Because of this negative impact, we decided to shut down our Aruba Refinery temporarily in July 2009, and it remained shut until  January 2011 . We restarted our Aruba Refinery due to improvements in the U.S. and worldwide economies and the resulting improvement in refining industry fundamentals; however, we analyzed our Aruba Refinery for potential impairment as of September 30, 2011  because of its recent temporary shutdown, its negative operating cash flows subsequent to its restart, the sensitivity of its profitability to sour crude oil differentials, and our decision in July 2011 to renew our exploration of strategic alternatives for the refinery, which may include the sale of the refinery. We considered these matters in our impairment analysis and concluded that our Aruba Refinery was not impaired as of  September 30, 2011 . Our future cash flow estimates for the refinery are based on our expectation that refining industry fundamentals will continue to improve in connection with an increase in the demand for refined products. Should refining industry fundamentals fail to continue to improve or should we decide to sell the refinery, our future cash flow estimates may be negatively impacted and we could ultimately determine that the refinery is impaired. The Aruba Refinery had a net book value of  $950 million  as of September 30, 2011 ; therefore, an impairment loss could be material to our results of operations.


   
 4.   INVENTORIES 


 Inventories consisted of the following (in millions):


 
               
   September 30,  
 2011 
   December 31,  
 2010 
 Refinery feedstocks   $   2,502 
 
   $   2,225 
 
 Refined products and blendstocks   2,217 
 
   2,233 
 
 Ethanol feedstocks and products   130 
 
   201 
 
 Convenience store merchandise   102 
 
   101 
 
 Materials and supplies   213 
 
   187 
 
 Inventories   $   5,164 
 
   $   4,947 
 


 As of  September 30, 2011  and  December 31, 2010 , the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately  $7.1 billion  and  $6.1 billion , respectively.





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 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


   
 5.   DEBT 

 Non-Bank Debt

 During the  nine months ended September 30,   2011 , the following activity occurred related to our non-bank debt:

   
 •   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 our Series A  5.45% , Series B  5.40% , and Series C 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 
   
 •   in February 2011, we paid  $300 million  to acquire the Gulf Opportunity Zone Revenue Bonds Series 2010 (GO Zone Bonds), which were subject to mandatory tender. We expect to hold the GO Zone Bonds for our own account until conditions permit the remarketing of these bonds at an interest rate acceptable to us. 


 During the  nine months ended September 30,   2010 , the following activity occurred related to our non-bank debt:

   
 •   in June 2010, we made a scheduled debt repayment of  $25 million  related to our  7.25%  debentures; 
   
 •   in May 2010, we redeemed our  6.75%  senior notes with a maturity date of  May 1, 2014  for  $190 million , or  102.25%  of stated value; 
   
 •   in April 2010, we made scheduled debt repayments of  $8 million  related to our Series A  5.45% , Series B  5.40% , and Series C 5.40%  industrial revenue bonds; 
   
 •   in March 2010, we redeemed our  7.50%  senior notes with a maturity date of  June 15, 2015  for  $294 million , or  102.5%  of stated value; and 
   
 •   in February 2010, we issued  $400 million  of  4.50%  notes due in  February 2015  and  $850 million  of  6.125%  notes due in  February 2020  for total net proceeds of  $1.2 billion . 


 Bank Debt and Credit Facilities

 We have a  $2.4 billion  revolving credit facility (the Revolver) that has a maturity date of  November 2012 . The Revolver has certain restrictive covenants, including a maximum debt-to-capitalization ratio of  60 percent . As of  September 30, 2011  and  December 31, 2010 , our debt-to-capitalization ratio, calculated in accordance with the terms of the Revolver, was  22 percent  and  25 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  nine  months ended  September 30, 2011  and  2010 , we had  no  borrowings or repayments under our Revolver or the Canadian revolving credit facility. As of  September 30, 2011  and  December 31, 2010 , we had  no  borrowings outstanding under the Revolver or the Canadian revolving credit facility.





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 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


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

 
                 
             Amounts Outstanding 
     Borrowing Capacity     Expiration     September 30, 2011     December 31, 2010 
  Letter of credit facility     $200     June 2012     $—     $— 
  Letter of credit facility     $300     June 2012     $300     $100 
  Revolver     $2,400     November 2012     $74     $399 
  Canadian revolving credit facility     C$115     December 2012     C$20     C$20 


 As of  September 30, 2011  and  December 31, 2010 , we had  $346 million  and  $176 million , respectively, of letters of credit outstanding under our uncommitted short-term bank credit facilities.


 In connection with the Pembroke Acquisition, we assumed a  €2.8 million  short-term demand loan, which bears interest at EURIBOR plus a margin. We expect to repay the loan on or before  February 2012 .


 Accounts Receivable Sales Facility

 We have an accounts receivable sales facility with a group of third-party entities and financial institutions to sell on a revolving basis up to $1 billion  of eligible trade receivables. We amended our agreement in June 2011 to extend the maturity date to  June 2012 . As of September 30, 2011  and  December 31, 2010 , the amount of eligible receivables sold was  $100 million . There were no sales or repayments of eligible receivables during the  nine  months ended  September 30, 2011 . During the  nine  months ended  September 30, 2010 , we sold $1.2 billion  of eligible receivables and repaid  $1.3 billion  to the third-party entities and financial institutions. Proceeds from the sale of receivables under this facility are reflected as debt.


 Capitalized Interest

 Capitalized interest was  $41 million  and  $25 million  for the  three months ended September 30,   2011  and  2010 , respectively, and  $101 million and  $67 million  for the  nine months ended September 30,   2011  and  2010 , respectively.





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 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


   
 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). According to statements by the EPA, 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 will be on a case by case basis, and the EPA has provided only general guidance on which controls will be required. 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.


 In addition, certain states and foreign governments have pursued independent regulation of greenhouse gases. 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 is effective in 2011, with small reductions in the carbon intensity of transportation fuels sold in California. The mandated reductions in carbon intensity are scheduled to increase through 2020, after which another step-change in reductions is anticipated. The LCFS is designed to encourage substitution of traditional petroleum fuels, and, over time, it is anticipated that the LCFS will lead to a greater use of electric cars and alternative fuels, such as E85, as companies seek to generate more credits to offset petroleum fuels. The statewide cap-and-trade program will begin in 2013. 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, but we expect that compliance costs will increase significantly beginning in 2015, when 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.


 On June 30, 2010, the EPA formally disapproved the flexible permits program submitted by the Texas Commission on Environmental Quality (TCEQ) in 1994 for inclusion in its clean-air implementation plan.  The EPA determined that Texas’ flexible permit program did not meet several requirements under the federal Clean Air Act.  Our Port Arthur, Texas City, Three Rivers, McKee, and Corpus Christi East and West Refineries formerly operated under flexible permits administered by the TCEQ.  In the fourth quarter of 2010, we completed the conversion of our flexible permits into federally enforceable conventional state NSR permits (“de-flexed permits”). We are now in the process of incorporating these de-flexed permits into our Title V permits. Continued discussions with the TCEQ and the EPA regarding this matter are likely.





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 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


 Meanwhile, the EPA has formally disapproved other TCEQ permitting programs that historically have streamlined the environmental permitting process in Texas. For example, the EPA has disapproved the TCEQ pollution control standard permit, thus requiring conventional permitting for future pollution control equipment. Litigation is pending from industry groups and others against the EPA for each of these actions. 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. 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. But 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.


 Tax Matters

 We are subject to extensive tax liabilities, including federal, state, and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise, withholding, 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.


 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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 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


   
 7.   EQUITY 


 The following is a reconciliation of the beginning and ending balances (in millions) of equity attributable to our stockholders, equity attributable to noncontrolling interests, and total equity for the  nine  months ended  September 30, 2011  and  2010 :

 
                                                 
     2011     2010 
     Valero Stockholders ’ Equity     Non- controlling Interests     Total Equity     Valero Stockholders ’ Equity     Non- controlling Interests     Total Equity 
 Balance at beginning of period     $   15,025 
 
   $   — 
 
   $   15,025 
 
   $   14,725 
 
   $   — 
 
   $   14,725 
 
 Net income (loss)     2,045 
 
   (1   )     2,044 
 
   762 
 
   — 
 
   762 
 
 Dividends     (85   )     — 
 
   (85   )     (85   )     — 
 
   (85   ) 
 Stock-based compensation expense     34 
 
   — 
 
   34 
 
   32 
 
   — 
 
   32 
 
 Tax deduction in excess of stock-based compensation expense     19 
 
   — 
 
   19 
 
   7 
 
   — 
 
   7 
 
 Transactions in connection with stock-based compensation plans:                         
 Stock issuances     42 
 
   — 
 
   42 
 
   12 
 
   — 
 
   12 
 
 Stock repurchases     (270   )     — 
 
   (270   )     (2   )     — 
 
   (2   ) 
 Contributions from noncontrolling interest     — 
 
   14 
 
   14 
 
   — 
 
   — 
 
   — 
 
 Recognition of noncontrolling interest in connection with Pembroke Acquisition     — 
 
   3 
 
   3 
 
   — 
 
   — 
 
   — 
 
 Other comprehensive income (loss)     (156   )     — 
 
   (156   )     (51   )     — 
 
   (51   ) 
 Balance at end of period     $   16,654 
 
   $   16 
 
   $   16,670 
 
   $   15,400 
 
   $   — 
 
   $   15,400 
 


 The noncontrolling interests relate to the ownership interests in MLP and DGD Holdings that are owned by parties unrelated to us, as discussed in  Note 1 .





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 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


 Treasury Stock

 During the nine months ended  September 30, 2011  and 2010, we purchased  13.6 million  shares and  1.6 million  shares, respectively, of our common stock in connection with the administration of our stock-based compensation plans. During the  nine months ended September 30, 2011 and 2010, we issued  3.9 million  and  1.6 million  shares from treasury, respectively, for our stock-based compensation plans.


 Common Stock Dividends

 On  October 27, 2011 , our board of directors declared a regular quarterly cash dividend of  $0.15  per common share payable on December 14, 2011  to holders of record at the close of business on  November 16, 2011 .


   
 8.   EMPLOYEE BENEFIT PLANS 


 The components of net periodic benefit cost related to our defined benefit plans were as follows for the three and  nine months ended September 30,  2011 and 2010 (in millions):


 
                               
   Pension Plans     Other Postretirement Benefit Plans 
   2011     2010     2011     2010 
 Three months ended September 30:               
 Service cost   $   28 
 
   $   22 
 
   $   4 
 
   $   3 
 
 Interest cost   21 
 
   21 
 
   5 
 
   6 
 
 Expected return on plan assets   (28   )     (28   )     — 
 
   — 
 
 Amortization of: 
 
           
 Prior service cost (credit)   1 
 
   1 
 
   (6   )     (5   ) 
 Net loss   3 
 
   — 
 
   — 
 
   1 
 
 Net periodic benefit cost   $   25 
 
   $   16 
 
   $   3 
 
   $   5 
 
               
 Nine months ended September 30:               
 Service cost   $   73 
 
   $   65 
 
   $   9 
 
   $   8 
 
 Interest cost   64 
 
   62 
 
   16 
 
   19 
 
 Expected return on plan assets   (84   )     (84   )     — 
 
   — 
 
 Amortization of:               
 Prior service cost (credit)   2 
 
   2 
 
   (17   )     (15   ) 
 Net loss   9 
 
   1 
 
   1 
 
   3 
 
 Net periodic benefit cost   $   64 
 
   $   46 
 
   $   9 
 
   $   15 
 


 During the  nine months ended September 30,   2011  and  2010 , we contributed  $207 million  and  $54 million , respectively, to our pension plans.





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 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 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 September 30, 
   2011     2010 
   Restricted  Stock     Common Stock       Restricted Stock         Common Stock 
 Earnings per common share from   continuing operations:               
 Net income attributable to Valero stockholders   from continuing operations       $   1,203 
 
       $   303 
 
 Less dividends paid:               
 Common stock       28 
 
       28 
 
 Nonvested restricted stock       — 
 
       — 
 
 Undistributed earnings       $   1,175 
 
       $   275 
 
               
 Weighted-average common shares outstanding   3 
 
   564 
 
   3 
 
   564 
 
               
 Earnings per common share from   continuing operations:               
 Distributed earnings   $   0.05 
 
   $   0.05 
 
   $   0.05 
 
   $   0.05 
 
 Undistributed earnings   2.07 
 
   2.07 
 
   0.49 
 
   0.49 
 
 Total earnings per common share from   continuing operations   $   2.12 
 
   $   2.12 
 
   $   0.54 
 
   $   0.54 
 
               
 Earnings per common share from   continuing operations – assuming dilution:               
 Net income attributable to Valero stockholders   from continuing operations       $   1,203 
 
       $   303 
 
 Weighted-average common shares outstanding       564 
 
       564 
 
 Common equivalent shares:     
 
       
 Stock options       3 
 
       3 
 
 Performance awards and unvested restricted   stock       2 
 
       1 
 
 Weighted-average common shares outstanding –   assuming dilution       569 
 
       568 
 
 Earnings per common share from   continuing operations – assuming dilution       $   2.11 
 
       $   0.53 
 




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 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


 
                               
   Nine Months Ended September 30, 
   2011     2010 
   Restricted  Stock     Common Stock       Restricted Stock         Common Stock 
 Earnings per common share from   continuing operations:               
 Net income attributable to Valero stockholders   from continuing operations       $   2,052 
 
       $   743 
 
 Less dividends paid:               
 Common stock       85 
 
       85 
 
 Nonvested restricted stock       — 
 
       — 
 
 Undistributed earnings       $   1,967 
 
       $   658 
 
               
 Weighted-average common shares outstanding   3 
 
   566 
 
   3 
 
   563 
 
               
 Earnings per common share from   continuing operations:               
 Distributed earnings   $   0.15 
 
   $   0.15 
 
   $   0.15 
 
   $   0.15 
 
 Undistributed earnings   3.46 
 
   3.46 
 
   1.16 
 
   1.16 
 
 Total earnings per common share from   continuing operations   $   3.61 
 
   $   3.61 
 
   $   1.31 
 
   $   1.31 
 
               
 Earnings per common share from   continuing operations – assuming dilution:               
 Net income attributable to Valero stockholders   from continuing operations       $   2,052 
 
       $   743 
 
 Weighted-average common shares outstanding       566 
 
       563 
 
 Common equivalent shares:               
 Stock options       4 
 
       3 
 
 Performance awards and unvested restricted   stock       2 
 
       1 
 
 Weighted-average common shares outstanding –   assuming dilution       572 
 
       567 
 
 Earnings per common share from   continuing operations – assuming dilution       $   3.59 
 
       $   1.31 
 




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 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


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


 
                       
   Three Months Ended September 30,     Nine Months Ended September 30, 
   2011     2010     2011     2010 
 Stock options   6 
 
   17 
 
   6 
 
   14 
 


   
 10.   SEGMENT INFORMATION 

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


 
                                         
     Refining     Retail     Ethanol     Corporate     Total 
 Three months ended September 30, 2011:                     
 Operating revenues from external   customers     $   29,177 
 
   $   3,053 
 
   $   1,483 
 
   $   — 
 
   $   33,713 
 
 Intersegment revenues     2,258 
 
   — 
 
   25 
 
   — 
 
   2,283 
 
 Operating income (loss)     1,947 
 
   97 
 
   107 
 
   (172   )     1,979 
 
                     
 Three months ended September 30, 2010:                     
 Operating revenues from external   customers     17,811 
 
   2,360 
 
   844 
 
   — 
 
   21,015 
 
 Intersegment revenues     1,576 
 
   — 
 
   73 
 
   — 
 
   1,649 
 
 Operating income (loss)     590 
 
   105 
 
   47 
 
   (152   )     590 
 
                     
 Nine months ended September 30, 2011:                     
 Operating revenues from external   customers     78,660 
 
   8,865 
 
   3,789 
 
   — 
 
   91,314 
 
 Intersegment revenues     6,566 
 
   — 
 
   125 
 
   — 
 
   6,691 
 
 Operating income (loss)     3,476 
 
   298 
 
   215 
 
   (476   )     3,513 
 
                     
 Nine months ended September 30, 2010:                     
 Operating revenues from external   customers     51,104 
 
   6,893 
 
   2,072 
 
   — 
 
   60,069 
 
 Intersegment revenues     4,675 
 
   — 
 
   184 
 
   — 
 
   4,859 
 
 Operating income (loss)     1,479 
 
   285 
 
   139 
 
   (405   )     1,498 
 





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 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


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


 
               
   September 30,  
 2011 
   December 31, 2010 
 Refining   $   35,541 
 
   $   30,363 
 
 Retail   1,933 
 
   1,925 
 
 Ethanol   879 
 
   953 
 
 Corporate   3,330 
 
   4,380 
 
 Total consolidated assets   $   41,683 
 
   $   37,621 
 


   
 11.   SUPPLEMENTAL CASH FLOW INFORMATION 

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


 
               
   Nine Months Ended
 September 30, 
   2011     2010 
 Decrease (increase) in current assets:       
 Receivables, net   $   (1,963   )     $   (516   ) 
 Inventories   891 
 
   79 
 
 Income taxes receivable   333 
 
   787 
 
 Prepaid expenses and other   12 
 
   111 
 
 Increase (decrease) in current liabilities:       
 Accounts payable   1,191 
 
   358 
 
 Accrued expenses   137 
 
   (51   ) 
 Taxes other than income taxes   99 
 
   (168   ) 
 Income taxes payable   140 
 
   (8   ) 
 Changes in current assets and current liabilities   $   840 
 
   $   592 
 


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

   
 •   the amounts shown above exclude changes in cash and temporary cash investments, deferred income taxes, and current portion of debt and capital lease obligations, as well as the effect of certain noncash investing and financing activities discussed below; 
   
 •   the amounts shown above exclude the current assets and current liabilities acquired in connection with the the Pembroke Acquisition in August 2011 and the acquisitions of  three  ethanol plants in the first quarter of 2010; 
   
 •   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 



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 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


   
 •   certain differences between consolidated 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. 

 During the  nine  months ended  September 30, 2011 , we received a noncash contribution of  $2 million  from the noncontrolling interest for property, plant and equipment related to DGD Holdings. There were no significant noncash investing or financing activities for the  nine months ended  September 30, 2010 .


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

 
               
   Nine Months Ended
 September 30, 
   2011     2010 
 Interest paid in excess of amount capitalized   $   276 
 
   $   302 
 
 Income taxes paid (received), net   289 
 
   (645   ) 

 Cash flows related to the discontinued operations of the Paulsboro and Delaware City Refineries have been combined with the cash flows from continuing operations within each category in the consolidated statement of cash flows for the  nine months ended September 30,  2010 and are summarized as follows (in millions):


 
       
 Cash provided by (used in) operating activities:   
 Paulsboro Refinery   $   42 
 
 Delaware City Refinery   (76   ) 
 Cash used in investing activities:   
 Paulsboro Refinery   (32   ) 
 Delaware City Refinery   — 
 


   
 12.   FAIR VALUE MEASUREMENTS 

 General

 GAAP requires that certain financial instruments, such as derivative instruments, be recognized at their fair values in our consolidated 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 consolidated 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 consolidated 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




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 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


 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 consolidated balance sheets categorized according to the fair value hierarchy of the inputs utilized by us to determine the fair values as of  September 30, 2011  and December 31, 2010 .


 
                                       
   Fair Value Measurements Using         
   Quoted Prices in Active Markets (Level 1)     Significant Other Observable Inputs (Level 2)     Significant Unobservable Inputs (Level 3)         Total as of September 30, 2011 
         Netting Adjustments   
 Assets:                   
 Commodity derivative contracts   $   6,764 
 
   $   238 
 
   $   — 
 
   $   (6,734   )     $   268 
 
 Physical purchase contracts   — 
 
   (81   )     — 
 
   — 
 
   (81   ) 
 Investments of nonqualified benefit plans   81 
 
   — 
 
   11 
 
   — 
 
   92 
 
 Other investments   — 
 
   — 
 
   — 
 
   — 
 
   — 
 
 Liabilities:                   
 Commodity derivative contracts   6,503 
 
   338 
 
   — 
 
   (6,734   )     107 
 
 Nonqualified benefit plan obligations   34 
 
   — 
 
   — 
 
   — 
 
   34 
 
 RINs obligation   137 
 
   — 
 
   — 
 
   — 
 
   137 
 


 
                                       
   Fair Value Measurements Using         
   Quoted Prices in Active Markets (Level 1)     Significant Other Observable Inputs (Level 2)     Significant Unobservable Inputs (Level 3)         Total as of December 31, 2010 
         Netting Adjustments   
 Assets:                   
 Commodity derivative contracts   $   3,240 
 
   $   489 
 
   $   — 
 
   $   (3,560   )     $   169 
 
 Physical purchase contracts   — 
 
   17 
 
   — 
 
   — 
 
   17 
 
 Investments of nonqualified benefit plans   104 
 
   — 
 
   10 
 
   — 
 
   114 
 
 Other investments   — 
 
   — 
 
   — 
 
   — 
 
   — 
 
 Liabilities:                   
 Commodity derivative contracts   3,097 
 
   502 
 
   — 
 
   (3,560   )     39 
 
 Nonqualified benefit plan obligations   36 
 
   — 
 
   — 
 
   — 
 
   36 
 
 RINs obligation   51 
 
   — 
 
   — 
 
   — 
 
   51 
 




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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. 
   
 •   Nonqualified benefit plan assets consist of investment securities held by our nonqualified defined benefit and nonqualified defined contribution plans. The nonqualified benefit plan obligations relate to our nonqualified defined contribution plans under which our obligations to eligible employees are equal to the fair value of the assets held by those plans. The nonqualified benefit plan assets categorized in Level 1 of the fair value hierarchy are measured at fair value using a market approach based on quotations from national securities exchanges. The nonqualified benefit plan assets categorized in Level 3 of the fair value hierarchy represent insurance contracts, the fair value of which is provided by the insurer. 
   
 •   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. 
   
 •   Our RINs obligation represents a liability for the purchase of Renewable Identification Numbers (RINs) to satisfy our obligation to blend biofuels into the products we produce. A RIN represents a serial number assigned to each gallon of biofuel produced or imported into the U.S. as required by the EPA’s Renewable Fuel Standard, which was implemented in accordance with the Energy Policy Act of 2005. The EPA sets annual quotas for the percentage of biofuels that must be blended into motor fuels consumed in the U.S., and 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 EPA’s quota. To the degree we are unable to blend at that rate, we must purchase RINs in the open market to satisfy our obligation. Our RINs obligation is based on our RINs deficiency and the price of those RINs as of the balance sheet date. Our RINs obligation is categorized in Level 1 of the fair value hierarchy and is measured at fair value using the market approach based on quoted prices from an independent pricing service. 



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 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


 Cash collateral deposits of  $228 million  and  $403 million  with brokers under master netting arrangements are included in the fair value of the commodity derivatives reflected in Level 1 as of  September 30, 2011  and  December 31, 2010 , 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; however, fair value amounts by hierarchy level are presented on a gross basis in the tables above.

 The following is a reconciliation of the beginning and ending balances (in millions) for fair value measurements developed using significant unobservable inputs (Level 3).


 
                               
   2011     2010 
   Investments of Nonqualified Benefit Plans     Other Investments     Investments of Nonqualified Benefit Plans     Other Investments 
 Three months ended September 30:               
 Balance at beginning of period   $   11 
 
   $   — 
 
   $   10 
 
   $   — 
 
 Purchases   — 
 
   5 
 
   — 
 
   — 
 
 Total losses included in earnings   — 
 
   (5   )     — 
 
   — 
 
 Transfers in and/or out of Level 3   — 
 
   — 
 
   — 
 
   — 
 
 Balance at end of period   $   11 
 
   $   — 
 
   $   10 
 
   $   — 
 
 The amount of total losses included   in earnings attributable to the change in   unrealized losses relating to assets still   held at end of period   $   — 
 
   $   (5   )     $   — 
 
   $   — 
 
               
 Nine months ended September 30:               
 Balance at beginning of period   $   10 
 
   $   — 
 
   $   10 
 
   $   — 
 
 Purchases   — 
 
   21 
 
   — 
 
   1 
 
 Total gains (losses) included in   earnings   1 
 
   (21   )     — 
 
   (1   ) 
 Transfers in and/or out of Level 3   — 
 
   — 
 
   — 
 
   — 
 
 Balance at end of period   $   11 
 
   $   — 
 
   $   10 
 
   $   — 
 
 The amount of total gains (losses)   included in earnings attributable to the   change in unrealized gains (losses)   relating to assets still held   at end of period   $   1 
 
   $   (21   )     $   — 
 
   $   (1   ) 

 Nonrecurring Fair Value Measurements

 As of  September 30, 2011  and  December 31, 2010 , there were no assets or liabilities that were measured at fair value on a nonrecurring basis.




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 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


 Other Financial Instruments

 Financial instruments that we recognize in our consolidated balance sheets at their carrying amounts include cash and temporary cash investments, receivables, payables, debt and capital lease obligations. The fair values of these financial instruments approximate their carrying amounts, except for debt as shown in the table below (in millions):


 
               
   September 30,  
 2011 
   December 31,  
 2010 
 Carrying amount (excluding capital leases)   $   7,595 
 
   $   8,300 
 
 Fair value   9,169 
 
   9,492 
 


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


   
 13.   PRICE RISK MANAGEMENT ACTIVITIES 

 We are exposed to market risks related to the volatility in the price of commodities, interest rates and foreign currency exchange rates, and we enter into derivative instruments to manage those 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, 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, are 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 the consolidated statements of cash flows for all periods presented.





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 Commodity Price Risk

 We are exposed to market risks related to 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. 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.

 As of  September 30, 2011 , 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     2011 
 Crude oil and refined products:     
 Futures – long     3,025 
 
 Futures – short     16,453 
 
 Physical purchase contracts – long     13,428 
 




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 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


 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  September 30, 2011 , 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     5,241 
 
 Swaps – short     5,241 
 





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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 in entering into economic hedges is consistent with the objectives discussed above for fair value hedges and cash flow hedges. However, the economic hedges are not designated as a fair value hedge or a cash flow hedge for accounting purposes, usually due to the difficulty of establishing the required documentation at the date that the derivative instrument is entered into that would allow us to achieve “hedge deferral accounting.”

 As of  September 30, 2011 , we had the following outstanding commodity derivative instruments that were entered into 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     2011     2012     2013 
 Crude oil and refined products:             
 Swaps – long     34,708 
 
   65,040 
 
   — 
 
 Swaps – short     33,890 
 
   65,040 
 
   — 
 
 Futures – long     200,076 
 
   40,388 
 
   — 
 
 Futures – short     192,292 
 
   41,219 
 
   — 
 
 Options – long     606 
 
   10 
 
   — 
 
 Options – short     600 
 
   — 
 
   — 
 
 Corn:             
 Futures – long     22,325 
 
   8,405 
 
   — 
 
 Futures – short     41,300 
 
   23,980 
 
   260 
 
 Physical purchase contracts – long     12,166 
 
   10,991 
 
   265 
 




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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  September 30, 2011 , 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     2011     2012 
 Crude oil and refined products:         
 Swaps – long     6,196 
 
   3,240 
 
 Swaps – short     6,196 
 
   3,240 
 
 Futures – long     66,365 
 
   15,868 
 
 Futures – short     66,389 
 
   15,831 
 
 Options – short     75 
 
   — 
 
 Natural gas:         
 Futures – long     5,050 
 
   — 
 
 Futures – short     5,050 
 
   — 
 
 Corn:         
 Swaps – long     — 
 
   1,050 
 
 Swaps – short     — 
 
   1,050 
 
 Futures – long     3,850 
 
   60 
 
 Futures – short     2,350 
 
   1,060 
 

 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.


 Foreign Currency Risk

 We are exposed to exchange rate fluctuations on transactions entered into by our Canadian and European operations that are denominated in currencies other than the local (functional) currencies of those operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and purchase contracts. These contracts are not designated as hedging instruments for accounting purposes, and therefore they are classified as economic hedges. As of  September 30, 2011 , we had commitments to purchase  $475 million of U.S. dollars. These commitments matured on or before  October 28, 2011 .





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 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


 Fair Values of Derivative Instruments

 The following tables provide information about the fair values of our derivative instruments as of  September 30, 2011  and  December 31, 2010  (in millions) and the line items in the consolidated balance sheet 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.


 
                   
   Consolidated Balance Sheet Location     September 30, 2011 
     Asset Derivatives        Liability Derivatives    
 Derivatives designated as hedging instruments           
 Commodity contracts:           
 Futures   Receivables, net     $   360 
 
   $   237 
 
 Swaps   Receivables, net     46 
 
   40 
 
 Swaps   Accrued expenses     4 
 
   3 
 
 Total       $   410 
 
   $   280 
 
           
 Derivatives not designated as hedging instruments           
 Commodity contracts:           
 Futures   Receivables, net     $   6,170 
 
   $   6,266 
 
 Swaps   Receivables, net     6 
 
   5 
 
 Swaps   Prepaid expenses and other     2 
 
   1 
 
 Swaps   Accrued expenses     181 
 
   268 
 
 Options   Receivables, net     5 
 
   — 
 
 Options   Accrued expenses     — 
 
   21 
 
 Physical purchase contracts   Inventories     — 
 
   81 
 
 Total       $   6,364 
 
   $   6,642 
 
 Total derivatives       $   6,774 
 
   $   6,922 
 





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 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


 
                   
   Consolidated Balance Sheet Location     December 31, 2010 
     Asset Derivatives        Liability Derivatives    
 Derivatives designated as hedging instruments           
 Commodity contracts:           
 Futures   Receivables, net     $   120 
 
   $   183 
 
 Swaps   Prepaid expenses and other     55 
 
   39 
 
 Swaps   Accrued expenses     31 
 
   32 
 
 Total       $   206 
 
   $   254 
 
           
 Derivatives not designated as hedging instruments           
 Commodity contracts:           
 Futures   Receivables, net     $   2,717 
 
   $   2,914 
 
 Swaps   Prepaid expenses and other     287 
 
   277 
 
 Swaps   Accrued expenses     116 
 
   148 
 
 Options   Accrued expenses     — 
 
   6 
 
 Physical purchase contracts   Inventories     17 
 
   — 
 
 Total       $   3,137 
 
   $   3,345 
 
 Total derivatives       $   3,343 
 
   $   3,599 
 

 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  September 30, 2011 , we had net receivables related to derivative instruments of  $1 million  from counterparties in the refining industry and  no  amount of net receivables from counterparties in the financial services industry. As of  December 31, 2010 , we had net receivables related to derivative instruments of  $4 million  from counterparties in the refining industry and  $21 million  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 Consolidated Statements of 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 consolidated financial statements in which such gains and losses are reflected (in millions).


 
                                                     
 Derivatives in Fair Value Hedging Relationships     Location     Gain or (Loss) Recognized in Income on Derivatives     Gain or (Loss) Recognized in Income on Hedged Item     Gain or (Loss) Recognized in Income for Ineffective Portion of Derivative 
     2011     2010     2011     2010     2011     2010 
 Three months ended September 30:                             
 Commodity   contracts     Cost of sales     $   170 
 
   $   54 
 
   $   (161   )     $   (56   )     $   9 
 
   $   (2   ) 
 Nine months ended September 30:                             
 Commodity   contracts     Cost of sales     219 
 
   253 
 
   (222   )     (247   )     (3   )     6 
 


 For fair value hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness for the three and  nine  months ended  September 30, 2011  and  2010 . No amounts were recognized in income for hedged firm commitments that no longer qualify as fair value hedges for the three and  nine  months ended  September 30, 2011  and  2010 .


 
                                                         
 Derivatives in Cash Flow Hedging Relationships     Gain or (Loss) Recognized in OCI on Derivatives (Effective Portion)     Gain or (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)     Gain or (Loss) Recognized in Income on Derivatives (Ineffective Portion) 
   2011     2010     Location     2011     2010     Location     2011     2010 
 Three months ended September 30:                                 
 Commodity   contracts     $   20 
 
   $   — 
 
   Cost of sales     $   — 
 
   $   37 
 
   Cost of sales     $   4 
 
   $   — 
 
 Nine months ended September 30:                                 
 Commodity   contracts     20 
 
   (2   )     Cost of sales     — 
 
   135 
 
   Cost of sales     4 
 
   — 
 





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 VALERO ENERGY CORPORATION AND SUBSIDIARIES

 CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued )


 For cash flow hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness for the three and  nine  months ended  September 30, 2011  and  2010 . For the three and  nine  months ended  September 30, 2011 , cash flow hedges primarily related to forward sales of gasoline and distillates, and associated forward purchases of crude oil, with  $13 million  of cumulative after-tax gains on cash flow hedges remaining in accumulated other comprehensive income as of  September 30, 2011 . We estimate that  $10 million  of the deferred gains as of  September 30, 2011  will be reclassified into cost of sales over the next 12 months as a result of hedged transactions that are forecasted to occur. For the three and  nine  months ended  September 30, 2011  and  2010 , 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 or (Loss) Recognized in Income on Derivatives     Gain or (Loss) Recognized in Income on Derivatives 
     2011     2010 
 Three months ended September 30:             
 Commodity contracts     Cost of sales     $   9 
 
   $   22 
 
 Foreign currency contracts     Cost of sales     41 
 
   (5   ) 
 Other contract     Cost of sales     29 
 
   — 
 
 Total         $   79 
 
   $   17 
 
 Nine months ended September 30:             
 Commodity contracts     Cost of sales     $   (362   )     $   (93   ) 
 Foreign currency contracts     Cost of sales     32 
 
   (2   ) 
 Other contract     Cost of sales     29 
 
   — 
 
 Total         $   (301   )     $   (95   ) 


 The gain of  $29 million  on the other contract for the three and  nine months ended September 30,   2011  is related to the difference between the fair value of inventories acquired in connection with the Pembroke Acquisition and the amount paid for such inventories based on the terms of the purchase agreement. The loss of  $362 million  on commodity contracts for the  nine months ended September 30,   2011  includes a $542 million  loss related to forward sales of refined products.


 
                     
 Trading Derivatives     Location of Gain or (Loss) Recognized in Income on Derivatives     Gain or (Loss) Recognized in Income on Derivatives 
     2011     2010 
 Three months ended September 30:             
 Commodity contracts     Cost of sales     $   3 
 
   $   2 
 
 Nine months ended September 30:             
 Commodity contracts     Cost of sales     17 
 
   7 
 





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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 in the U.S., Canada, the United Kingdom, Ireland, and elsewhere; 
   
 •   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, including the U.S., Canada, Europe, the Middle East, Africa, and South America; 
   
 •   domestic and foreign demand for, and supplies of, refined products such as gasoline, diesel fuel, jet fuel, home heating oil, petrochemicals, and ethanol; 
   
 •   domestic and foreign 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; 





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 •   the actions taken by competitors, including both pricing and adjustments to refining capacity in response to market conditions; 
   
 •   the level of foreign imports of refined products to the U.S., Canada, or the United Kingdom; 
   
 •   accidents or other unscheduled shutdowns affecting our refineries, machinery, pipelines, or equipment, 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; 
   
 •   lower than expected ethanol margins; 
   
 •   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 federal, state, municipal, or foreign legislation or rulemakings, 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 EPA’s 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


 For the  third  quarter of 2011, we reported net income attributable to Valero stockholders from continuing operations of  $1.2 billion , or $2.11  per share, compared to  $303 million , or  $0.53  per share, for the  third  quarter of 2010. For the first  nine  months of 2011, we reported net income attributable to Valero stockholders from continuing operations of  $2.1 billion , or  $3.59  per share, compared to  $743 million , or $1.31  per share for the first  nine  months of 2010. Included in the results for the first  nine  months of 2011 was a  $542 million  loss ($352 million after taxes, or $0.62 per share) on commodity derivative contracts related to forward sales of refined products. These contracts were closed and realized in the first quarter of 2011. The improvement in net income attributable to Valero stockholders from continuing operations in the  third  quarter and  first nine months  of 2011 versus the comparable periods of 2010 was primarily due to an increase in operating income attributable to the business segments outlined in the following tables (in millions):


 
                         
     Three Months Ended September 30, 
     2011     2010     Change 
 Operating income (loss) by business segment:             
 Refining     $   1,947 
 
   $   590 
 
   $   1,357 
 
 Retail     97 
 
   105 
 
   (8   ) 
 Ethanol     107 
 
   47 
 
   60 
 
 Corporate     (172   )     (152   )     (20   ) 
 Total     $   1,979 
 
   $   590 
 
   $   1,389 
 
             
     Nine Months Ended September 30, 
     2011     2010     Change 
 Operating income (loss) by business segment:             
 Refining     $   3,476 
 
   $   1,479 
 
   $   1,997 
 
 Retail     298 
 
   285 
 
   13 
 
 Ethanol     215 
 
   139 
 
   76 
 
 Corporate     (476   )     (405   )     (71   ) 
 Total     $   3,513 
 
   $   1,498 
 
   $   2,015 
 


 Excluding the impact of the  $542 million  loss on commodity derivative contracts described above, total company operating income and our refining segment operating income would have been $4.1 billion and $4.0 billion, respectively, for the  first nine months  of 2011, which reflects an improvement in operating income of $2.6 billion and $2.5 billion, respectively, over the comparable 2010 period.


 Refining segment operating income improved primarily due to increased margins for most of the products we produce. Our margin improvement included the benefits from wider sour crude oil differentials (which is the difference between the price of sweet crude oil and the price of sour crude oil) and the favorable difference between the price of waterborne sweet crude oils, such as Louisiana Light Sweet (LLS) and Brent, and inland sweet crude oils, such as West Texas Intermediate (WTI). Many of our refineries process sour crude oils or WTI-type crude oils and these crude oils were priced significantly below waterborne sweet crude oils during the  third  quarter of 2011 and the  first nine months  of 2011, versus the comparable 2010 periods.





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 Our retail segment generated operating income of  $97 million  for the  third  quarter of 2011 compared to  $105 million  for the  third  quarter of 2010. This decrease of $8 million was due primarily to an increase of $8 million in the fuel margin generated by our Canadian retail operations, offset by a decrease of $10 million in the fuel margin generated by our U.S. retail operations and an increase of $8 million in operating expenses. For the  first nine months  of 2011, our retail segment generated  $298 million  of operating income compared to $285 million  for the  first nine months  of 2010. The increase was primarily due to higher fuel margins and volumes in our Canadian operations, including a favorable impact from the strengthening of the Canadian dollar relative to the U.S. dollar.


 Our ethanol segment generated operating income of  $107 million  for the  third  quarter of 2011 compared to  $47 million  for the  third  quarter of 2010, and it generated  $215 million  of operating income for the  first nine months  of 2011 compared to  $139 million  for the  first nine months of 2010. The increase in operating income in both the  third  quarter and  first nine months  of 2011 was primarily due to improved operating margins combined with a full  nine  months of operations related to the three ethanol plants we acquired in the first quarter of 2010. The ethanol business is dependent on margins between ethanol and corn feedstocks and is impacted by U.S. government subsidies and biofuels (including ethanol) mandates.


 On  August 1, 2011 , we acquired  100 percent  of the outstanding shares of Chevron Limited from a subsidiary of  Chevron Corporation and we subsequently changed the name of Chevron Limited to Valero Energy Ltd. Valero Energy Ltd owns and operates the Pembroke Refinery, which has a total throughput capacity of approximately  270,000  barrels per day and is located in Wales, United Kingdom. Valero Energy Ltd also owns, directly and through various subsidiaries, an extensive network of marketing and logistics assets throughout the United Kingdom and Ireland. On the acquisition date, we initially paid  $1.8 billion  from available cash, of which  $1.1 billion  was for working capital. Subsequent to the acquisition date, the amounts paid have been favorably adjusted for working capital true-up adjustments (primarily inventory), to an adjusted purchase price of  $1.675 billion . We expect final settlement by year end. This acquisition is referred to as the Pembroke Acquisition.


 On  October 1, 2011 , we acquired the Meraux Refinery and related logistics assets for an initial payment of  $586 million , including inventories of  $261 million , from  Murphy Oil Corporation. The purchase price was funded from available cash. We expect to receive a favorable adjustment related to inventories in the fourth quarter of 2011 that will reduce the purchase price by approximately  $40 million .


 As of the date of the filing of this report, the financial markets continue to experience significant volatility. The overall impact on our business is uncertain at this time and we expect the energy markets and margins to be volatile in the near to mid-term.




 41

 Table of Contents


 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) (c)

 (millions of dollars, except per share amounts)

 
                       
   Three Months Ended September 30, 
   2011     2010     Change 
 Operating revenues   $   33,713 
 
   $   21,015 
 
   $   12,698 
 
 Costs and expenses:           
 Cost of sales (d)   30,033 
 
   18,915 
 
   11,118 
 
 Operating expenses:           
 Refining   870 
 
   753 
 
   117 
 
 Retail (d)   177 
 
   169 
 
   8 
 
 Ethanol   103 
 
   96 
 
   7 
 
 General and administrative expenses   161 
 
   139 
 
   22 
 
 Depreciation and amortization expense:           
 Refining   340 
 
   303 
 
   37 
 
 Retail   29 
 
   27 
 
   2 
 
 Ethanol   10 
 
   10 
 
   — 
 
 Corporate   11 
 
   13 
 
   (2   ) 
 Total costs and expenses   31,734 
 
   20,425 
 
   11,309 
 
 Operating income   1,979 
 
   590 
 
   1,389 
 
 Other income, net   1 
 
   17 
 
   (16   ) 
 Interest and debt expense, net of capitalized interest   (88   )     (119   )     31 
 
 Income from continuing operations   before income tax expense   1,892 
 
   488 
 
   1,404 
 
 Income tax expense   689 
 
   185 
 
   504 
 
 Income from continuing operations   1,203 
 
   303 
 
   900 
 
 Income (loss) from discontinued operations,   net of income taxes   — 
 
   (11   )     11 
 
 Net income   1,203 
 
   292 
 
   911 
 
 Less: Net loss attributable to noncontrolling interests   — 
 
   — 
 
   — 
 
 Net income attributable to Valero stockholders   $   1,203 
 
   $   292 
 
   $   911 
 
           
 Net income attributable to Valero stockholders:           
 Continuing operations   $   1,203 
 
   $   303 
 
   $   900 
 
 Discontinued operations   — 
 
   (11   )     11 
 
 Total   $   1,203 
 
   $   292 
 
   $   911 
 
           
 Earnings per common share – assuming dilution:   
 
       
 Continuing operations   $   2.11 
 
   $   0.53 
 
   $   1.58 
 
 Discontinued operations   — 
 
   (0.02   )     0.02 
 
 Total   $   2.11 
 
   $   0.51 
 
   $   1.60 
 

 ________________

 See note references on page  47 .




 42

 Table of Contents


 Operating Highlights

 (millions of dollars, except per barrel amounts)


 
                       
   Three Months Ended September 30, 
   2011     2010     Change 
 Refining (a) (b):           
 Operating income   $   1,947 
 
   $   590 
 
   $   1,357 
 
 Throughput margin per barrel (e)   $   13.24 
 
   $   8.13 
 
   $   5.11 
 
 Operating costs per barrel:           
 Operating expenses   3.65 
 
   3.71 
 
   (0.06   ) 
 Depreciation and amortization expense   1.43 
 
   1.50 
 
   (0.07   ) 
 Total operating costs per barrel   5.08 
 
   5.21 
 
   (0.13   ) 
 Operating income per barrel   $   8.16 
 
   $   2.92 
 
   $   5.24 
 
           
 Throughput volumes (thousand barrels per day):           
 Feedstocks:           
 Heavy sour crude   540 
 
   443 
 
   97 
 
 Medium/light sour crude   455 
 
   402 
 
   53 
 
 Acidic sweet crude   150 
 
   51 
 
   99 
 
 Sweet crude   739 
 
   708 
 
   31 
 
 Residuals   310 
 
   239 
 
   71 
 
 Other feedstocks   123 
 
   113 
 
   10 
 
 Total feedstocks   2,317 
 
   1,956 
 
   361 
 
 Blendstocks and other   275 
 
   247 
 
   28 
 
 Total throughput volumes   2,592 
 
   2,203 
 
   389 
 
           
 Yields (thousand barrels per day):           
 Gasolines and blendstocks   1,196 
 
   1,088 
 
   108 
 
 Distillates   894 
 
   766 
 
   128 
 
 Other products (f)   519 
 
   381 
 
   138 
 
 Total yields   2,609 
 
   2,235 
 
   374 
 

 _______________

 See note references on page  47 .





 43

 Table of Contents


 Refining Operating Highlights by Region (g)

 (millions of dollars, except per barrel amounts)


 
                       
   Three Months Ended September 30, 
   2011     2010     Change 
 Gulf Coast:           
 Operating income   $   1,167 
 
   $   388 
 
   $   779 
 
 Throughput volumes (thousand barrels per day)   1,522 
 
   1,336 
 
   186 
 
 Throughput margin per barrel (e)   $   13.08 
 
   $   8.34 
 
   $   4.74 
 
 Operating costs per barrel:           
 Operating expenses   3.31 
 
   3.65 
 
   (0.34   ) 
 Depreciation and amortization expense   1.43 
 
   1.54 
 
   (0.11   ) 
 Total operating costs per barrel   4.74 
 
   5.19 
 
   (0.45   ) 
 Operating income per barrel   $   8.34 
 
   $   3.15 
 
   $   5.19 
 
           
 Mid-Continent          
 Operating income   $   586 
 
   $   131 
 
   $   455 
 
 Throughput volumes (thousand barrels per day)   400 
 
   422 
 
   (22   ) 
 Throughput margin per barrel (e)   $   22.27 
 
   $   8.06 
 
   $   14.21 
 
 Operating costs per barrel:           
 Operating expenses   4.76 
 
   3.34 
 
   1.42 
 
 Depreciation and amortization expense   1.59 
 
   1.33 
 
   0.26 
 
 Total operating costs per barrel   6.35 
 
   4.67 
 
   1.68 
 
 Operating income per barrel   $   15.92 
 
   $   3.39 
 
   $   12.53 
 
           
 North Atlantic (a) (b):           
 Operating income   $   65 
 
   $   36 
 
   $   29 
 
 Throughput volumes (thousand barrels per day)   386 
 
   193 
 
   193 
 
 Throughput margin per barrel (e)   $   5.46 
 
   $   6.04 
 
   $   (0.58   ) 
 Operating costs per barrel:           
 Operating expenses   2.91 
 
   2.75 
 
   0.16 
 
 Depreciation and amortization expense   0.74 
 
   1.30 
 
   (0.56   ) 
 Total operating costs per barrel   3.65 
 
   4.05 
 
   (0.40   ) 
 Operating income per barrel   $   1.81 
 
   $   1.99 
 
   $   (0.18   ) 
           
 West Coast:           
 Operating income   $   129 
 
   $   35 
 
   $   94 
 
 Throughput volumes (thousand barrels per day)   284 
 
   252 
 
   32 
 
 Throughput margin per barrel (e)   $   11.96 
 
   $   8.66 
 
   $   3.30 
 
 Operating costs per barrel:           
 Operating expenses   4.94 
 
   5.42 
 
   (0.48   ) 
 Depreciation and amortization expense   2.08 
 
   1.74 
 
   0.34 
 
 Total operating costs per barrel   7.02 
 
   7.16 
 
   (0.14   ) 
 Operating income per barrel   $   4.94 
 
   $   1.50 
 
   $   3.44 
 
           
 Total refining operating income   $   1,947 
 
   $   590 
 
   $   1,357 
 

 _______________

 See note references on page  47 .




 44

 Table of Contents


 Average Market Reference Prices and Differentials (h)

 (dollars per barrel, except as noted)


 
                       
   Three Months Ended September 30, 
   2011     2010     Change 
 Feedstocks:           
 Louisiana Light Sweet (LLS) crude oil   $   112.21 
 
   $   78.66 
 
   $   33.55 
 
 LLS less West Texas Intermediate (WTI) crude oil   22.47 
 
   2.58 
 
   19.89 
 
 LLS less Alaska North Slope (ANS) crude oil   0.60 
 
   3.03 
 
   (2.43   ) 
 LLS less Brent crude oil   (1.43   )     1.73 
 
   (3.16   ) 
 LLS less Mars crude oil   2.53 
 
   3.96 
 
   (1.43   ) 
 LLS less Maya crude oil   13.48 
 
   11.04 
 
   2.44 
 
 WTI crude oil   89.74 
 
   76.08 
 
   13.66 
 
 WTI less Mars crude oil   (19.94   )     1.38 
 
   (21.32   ) 
 WTI less Maya crude oil   (8.99   )     8.46 
 
   (17.45   ) 
           
 Products:           
 Gulf Coast:           
 Conventional 87 gasoline less LLS   $   8.20 
 
   $   4.35 
 
   $   3.85 
 
 Ultra-low-sulfur diesel less LLS   14.19 
 
   9.12 
 
   5.07 
 
 Propylene less LLS   12.46 
 
   2.61 
 
   9.85 
 
 Conventional 87 gasoline less WTI   30.67 
 
   6.93 
 
   23.74 
 
 Ultra-low-sulfur diesel less WTI   36.66 
 
   11.70 
 
   24.96 
 
 Propylene less WTI   34.93 
 
   5.19 
 
   29.74 
 
 Mid-Continent          
 Conventional 87 gasoline less WTI   32.11 
 
   9.20 
 
   22.91 
 
 Ultra-low-sulfur diesel less WTI   38.34 
 
   13.20 
 
   25.14 
 
 North Atlantic:           
 Conventional 87 gasoline less Brent   7.48 
 
   5.85 
 
   1.63 
 
 Ultra-low-sulfur diesel less Brent   14.55 
 
   12.16 
 
   2.39 
 
 Conventional 87 gasoline less WTI   31.38 
 
   6.70 
 
   24.68 
 
 Ultra-low-sulfur diesel less WTI   38.45 
 
   13.01 
 
   25.44 
 
 West Coast:           
 CARBOB 87 gasoline less ANS   10.27 
 
   16.96 
 
   (6.69   ) 
 CARB diesel less ANS   15.77 
 
   15.10 
 
   0.67 
 
 CARBOB 87 gasoline less WTI   32.14 
 
   16.51 
 
   15.63 
 
 CARB diesel less WTI   37.64 
 
   14.65 
 
   22.99 
 
 New York Harbor corn crush (dollars per gallon)   0.36 
 
   0.43 
 
   (0.07   ) 

 _______________

 See note references on page  47 .




 45

 Table of Contents


 Operating Highlights (continued)

 (millions of dollars, except per gallon amounts)


 
                       
   Three Months Ended September 30, 
   2011     2010     Change 
 Retail–U.S.: (d)           
 Operating income   $   59 
 
   $   72 
 
   $   (13   ) 
 Company-operated fuel sites (average)   994 
 
   990 
 
   4 
 
 Fuel volumes (gallons per day per site)   5,168 
 
   5,204 
 
   (36   ) 
 Fuel margin per gallon   $   0.155 
 
   $   0.176 
 
   $   (0.021   ) 
 Merchandise sales   $   324 
 
   $   322 
 
   $   2 
 
 Merchandise margin (percentage of sales)   29.2   %     28.8   %     0.4    % 
 Margin on miscellaneous sales   $   22 
 
   $   21 
 
   $   1 
 
 Operating expenses   $   111 
 
   $   108 
 
   $   3 
 
 Depreciation and amortization expense   $   19 
 
   $   18 
 
   $   1 
 
           
 Retail–Canada: (d)           
 Operating income   $   38 
 
   $   33 
 
   $   5 
 
 Fuel volumes (thousand gallons per day)   3,214 
 
   3,214 
 
   — 
 
 Fuel margin per gallon   $   0.273 
 
   $   0.247 
 
   $   0.026 
 
 Merchandise sales   $   72 
 
   $   66 
 
   $   6 
 
 Merchandise margin (percentage of sales)   29.4   %     30.4   %     (1   )% 
 Margin on miscellaneous sales   $   11 
 
   $   10 
 
   $   1 
 
 Operating expenses   $   66 
 
   $   61 
 
   $   5 
 
 Depreciation and amortization expense   $   10 
 
   $   9 
 
   $   1 
 
     
 
   
 Ethanol (c):     
 
   
 Operating income   $   107 
 
   $   47 
 
   $   60 
 
 Production (thousand gallons per day)   3,272 
 
   3,100 
 
   172 
 
 Gross margin per gallon of production (e)   $   0.73 
 
   $   0.54 
 
   $   0.19 
 
 Operating costs per gallon of production:     
 
   
 Operating expenses   0.34 
 
   0.34 
 
   — 
 
 Depreciation and amortization expense   0.04 
 
   0.03 
 
   0.01 
 
 Total operating costs per gallon of production   0.38 
 
   0.37 
 
   0.01 
 
 Operating income per gallon of production   $   0.35 
 
   $   0.17 
 
   $   0.18 
 

 _______________

 See note references on page  47 .




 46

 Table of Contents


 The following notes relate to references on pages  42  through  46 .

   
 (a)   The information presented for the three months ended  September 30, 2011  includes the results of operations of our refinery in Wales, United Kingdom (Pembroke Refinery), including the related marketing and logistics business, from the date of its acquisition,  August 1, 2011 , through  September 30, 2011 . In addition, the refining segment and North Atlantic region operating highlights for the three months ended  September 30, 2011  include the Pembroke Refinery. 
   
 (b)   In December 2010, we sold our Paulsboro Refinery to PBF Holding Company LLC. The results of operations of the Paulsboro Refinery have been presented as discontinued operations for the  three months ended September 30,  2010. In addition, the refining segment and North Atlantic region operating highlights exclude the Paulsboro Refinery for the  three months ended September 30,  2010. 
   
 (c)   We acquired three ethanol plants in the first quarter of 2010. The information presented includes the results of operations of those plants commencing on their respective acquisition dates. Ethanol production volumes are based on total production during each period divided by actual calendar days per period. 
   
 (d)   Credit card transaction processing fees incurred by our retail segment of  $23 million  for the  three months ended September 30,  2010 have been reclassified from retail operating expenses to cost of sales. The Retail–U.S. and Retail–Canada operating highlights for the  three months ended September 30,  2010 have been restated to reflect this reclassification. 
   
 (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 Gulf Coast region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, St. Charles, Aruba, and Port Arthur Refineries; the  Mid-Continent region includes the McKee, Ardmore, and Memphis Refineries; the North Atlantic (formerly known as Northeast) region includes the Pembroke and Quebec City Refineries; and the West Coast region includes the Benicia and Wilmington Refineries. 
   
 (h)   Average market reference prices for LLS crude oil, along with price differentials between the price of LLS 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 the best indicator of product margins for each region.  Prior to the first quarter of 2011, feedstock and product differentials presented herein were 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 light-sweet crude oil began to price at a discount to waterborne light-sweet crude oils, such as LLS and Brent, because of increased WTI supplies resulting from greater domestic production and increased deliveries of crude oil from Canada into the  Mid-Continent region.  Therefore, the use of the price of WTI crude oil as a benchmark price for regions that do not process WTI crude oil is no longer reasonable. 


 General

 Operating revenues increased 60 percent (or  $12.7 billion ) for the  third  quarter of  2011  compared to the  third  quarter of  2010  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 178,000 barrels per day 1  ($3.0 billion of revenue) from the Pembroke Refinery, which was acquired on August 1, 2011, and throughput of 182,000 barrels per day ($1.8 billion of revenue) from the Aruba Refinery, which restarted operations in January 2011. Both operating income and income from continuing operations before taxes increased  $1.4 billion  for the  third  quarter of  2011  compared to amounts reported for the  third  quarter of  2010  primarily due to a  $1.4 billion increase in refining segment operating income discussed below.









 _______________

 1 Calculated based on throughput volumes of the Pembroke Refinery from the date of acquisition ( August 1, 2011 ), divided by the number of days during the third quarter of 2011.





 47

 Table of Contents


 Refining

 Refining segment operating income more than tripled (a  $1.4 billion  increase) from  $590 million  for the  third  quarter of  2010  to  $1.9 billion for the  third  quarter of  2011 . The  $1.4 billion  improvement in operating income was due to a  $1.5 billion  increase in refining margin, offset by a  $117 million  increase in operating expenses.


 The  $1.5 billion  increase in refining margin was primarily due to a 63 percent increase in throughput margin per barrel (a  $5.11  per barrel increase between the comparable periods), and this increase was largely driven by an improvement in gasoline and distillate margins in most of our refining regions, primarily the  Mid-Continent and Gulf Coast refining regions, as further explained below.

   
 •   The WTI-based benchmark reference margin for  Mid-Continent conventional 87 gasoline was  $32.11  per barrel for the  third  quarter of 2011 , compared to  $9.20  per barrel for the  third  quarter of  2010 , representing a favorable increase of  $22.91  per barrel. In addition, the WTI-based benchmark reference margin for  Mid-Continent ultra-low sulfur diesel (a type of distillate) was  $38.34  per barrel for the third  quarter of  2011 , compared to  $13.20  per barrel for the  third  quarter of  2010 , representing a favorable increase of  $25.14  per barrel. We estimate that these increases in gasoline and distillate margins per barrel had a positive impact to our refining margin of approximately $500 million and $300 million, respectively, quarter versus quarter. The increases in the gasoline and distillate benchmark reference margins in the  Mid-Continent region are primarily due to the substantial discount in the price of WTI crude oil, the primary type of crude oil processed by our  Mid-Continent refineries, versus LLS-type crude oils. Historically, the price of WTI crude oil has tracked LLS crude oil, but due to the significant development of crude oil reserves within the  Mid-Continent region and increased deliveries of crude oil from Canada into the  Mid-Continent region, the increased supply of WTI crude oil has resulted in WTI crude oil currently being priced at a significant discount to LLS crude oil. 
   
 •   The LLS-based benchmark reference margin for Gulf Coast conventional 87 gasoline was  $8.20  per barrel for the  third  quarter of  2011 , compared to  $4.35  per barrel for the  third  quarter of  2010 , representing a favorable increase of  $3.85  per barrel. In addition, the LLS-based benchmark reference margin for Gulf Coast ultra-low sulfur diesel was  $14.19  per barrel for the  third  quarter of  2011 , compared to  $9.12  per barrel for the  third  quarter of  2010 , representing a favorable increase of  $5.07  per barrel. We estimate that these increases in gasoline and distillate margins per barrel had a positive impact to our refining margin of approximately $200 million and $250 million, respectively, quarter versus quarter. The increases in the gasoline and distillate benchmark reference margins are supported by increased exports of gasoline and distillate as well as an increase in demand for distillates. 
   
 •   In addition, our system benefited from the increase in the discount of the price of heavy sour crude oils as compared to the price of sweet crude oils. For example, Maya crude oil, which is a type of heavy sour crude oil, sold at a discount of  $13.48  per barrel to LLS crude oil, which is a type of sweet crude oil, during the  third  quarter of  2011 . This compares to a discount of  $11.04  per barrel during the third  quarter of  2010 , representing a favorable increase of  $2.44  per barrel. We estimate that the increase in the discounts for all types of sour crude oil that we process had a positive impact to our refining margin of approximately $120 million, quarter versus quarter. 

 The increase of  $117 million  in operating expenses discussed above was primarily due to $50 million in operating expenses incurred by the Pembroke Refinery, which was acquired on August 1, 2011. The remaining increase in refining operating expenses of $67 million was primarily due to a $34 million increase in maintenance expenses and a $38 million increase in chemicals and catalyst costs.




 48

 Table of Contents


 Retail

 Retail segment operating income was  $97 million  for the  third  quarter of  2011  compared to  $105 million  for the  third  quarter of  2010 . This 8 percent (or $8 million) decrease was due primarily to an increase of $8 million in the fuel margin generated by our Canadian retail operations offset by a decrease of $10 million in the fuel margin generated by our U.S. retail operations and an increase of  $8 million  in operating expenses between the quarters.


 Ethanol

 Ethanol segment operating income was  $107 million  for the  third  quarter of  2011  compared to  $47 million  for the  third  quarter of  2010 . The $60 million  increase in operating income was primarily due to a $68 million increase in gross margin, partially offset by a $7 million increase in operating expenses.


 The increase in gross margin was due to an increase in ethanol production (a  172,000  gallon per day increase between the comparable periods), which resulted from higher utilization rates and increased yield from the corn feedstock that we processed during the third quarter of  2011 , and a 35 percent increase in the gross margin per gallon of ethanol production (a  $0.19  per gallon increase between the comparable periods).


 The increase in operating expenses was due primarily to a $5 million increase in energy costs and chemical expenses.


 Corporate Expenses and Other

 General and administrative expenses increased $22 million from the  third  quarter of  2010  to the  third  quarter of  2011  primarily due to $18 million in costs incurred in connection with the Pembroke Acquisition.

 “Other income, net” for the  third  quarter of  2011  decreased  $16 million  from the  third  quarter of  2010  primarily due to a $12 million decrease in investment income earned on the plan assets of certain of our non-qualified benefit plans and earnings of $4 million in the third quarter of 2010 related to our joint venture investment in Cameron Highway Oil Pipeline Company, which did not recur due to the sale of our ownership interest in that joint venture in the fourth quarter of 2010.

 “Interest and debt expense, net of capitalized interest” for the  third  quarter of  2011  decreased  $31 million  from the  third  quarter of  2010 . This decrease is primarily due to a $16 million increase in capitalized interest due to a corresponding increase in capital expenditures between the quarters and the resumption of construction activity on previously suspended projects combined with a $7 million favorable impact from a decrease in average borrowings and an $8 million favorable impact resulting from the successful resolution of a tax contingency.

 Income tax expense increased  $504 million  from the  third  quarter of  2010  to the  third  quarter of  2011  mainly as a result of higher operating income in 2011.




 49

 Table of Contents


 Financial Highlights (a) (b) (c)

 (millions of dollars, except per share amounts)


 
                       
   Nine Months Ended September 30, 
   2011     2010     Change 
 Operating revenues   $   91,314 
 
   $   60,069 
 
   $   31,245 
 
 Costs and expenses:           
 Cost of sales (d) (e)   82,981 
 
   54,198 
 
   28,783 
 
 Operating expenses:           
 Refining   2,427 
 
   2,210 
 
   217 
 
 Retail (d)   508 
 
   484 
 
   24 
 
 Ethanol   302 
 
   267 
 
   35 
 
 General and administrative expenses   442 
 
   367 
 
   75 
 
 Depreciation and amortization expense:           
 Refining   995 
 
   898 
 
   97 
 
 Retail   84 
 
   80 
 
   4 
 
 Ethanol   28 
 
   27 
 
   1 
 
 Corporate   34 
 
   38 
 
   (4   ) 
 Asset impairment loss   — 
 
   2 
 
   (2   ) 
 Total costs and expenses   87,801 
 
   58,571 
 
   29,230 
 
 Operating income   3,513 
 
   1,498 
 
   2,015 
 
 Other income, net   28 
 
   29 
 
   (1   ) 
 Interest and debt expense, net of capitalized interest   (312   )     (363   )     51 
 
 Income from continuing operations   before income tax expense   3,229 
 
   1,164 
 
   2,065 
 
 Income tax expense   1,178 
 
   421 
 
   757 
 
 Income from continuing operations   2,051 
 
   743 
 
   1,308 
 
 Income (loss) from discontinued operations,   net of income taxes   (7   )     19 
 
   (26   ) 
 Net income   2,044 
 
   762 
 
   1,282 
 
 Less: Net loss attributable to noncontrolling interests   (1   )     — 
 
   (1   ) 
 Net income attributable to Valero stockholders   $   2,045 
 
   $   762 
 
   $   1,283 
 
           
 Net income attributable to Valero stockholders:           
 Continuing operations   $   2,052 
 
   $   743 
 
   $   1,309 
 
 Discontinued operations   (7   )     19 
 
   (26   ) 
 Total   $   2,045 
 
   $   762 
 
   $   1,283 
 
           
 Earnings per common share – assuming dilution:           
 Continuing operations   $   3.59 
 
   $   1.31 
 
   $   2.28 
 
 Discontinued operations   (0.01   )     0.03 
 
   (0.04   ) 
 Total   $   3.58 
 
   $   1.34 
 
   $   2.24 
 

 _______________

 See note references on page  55 .




 50

 Table of Contents


 Operating Highlights

 (millions of dollars, except per barrel amounts)

 
                       
   Nine Months Ended September 30, 
   2011     2010     Change 
 Refining (a) (b):           
 Operating income (e)   $   3,476 
 
   $   1,479 
 
   $   1,997 
 
 Throughput margin per barrel (e) (f)   $   10.80 
 
   $   7.97 
 
   $   2.83 
 
 Operating costs per barrel:           
 Operating expenses   3.80 
 
   3.84 
 
   (0.04   ) 
 Depreciation and amortization expense   1.56 
 
   1.56 
 
   — 
 
 Total operating costs per barrel   5.36 
 
   5.40 
 
   (0.04   ) 
 Operating income per barrel   $   5.44 
 
   $   2.57 
 
   $   2.87 
 
           
 Throughput volumes (thousand barrels per day):           
 Feedstocks:           
 Heavy sour crude   455 
 
   452 
 
   3 
 
 Medium/light sour crude   415 
 
   399 
 
   16 
 
 Acidic sweet crude   117 
 
   51 
 
   66 
 
 Sweet crude   695 
 
   655 
 
   40 
 
 Residuals   284 
 
   195 
 
   89 
 
 Other feedstocks   122 
 
   115 
 
   7 
 
 Total feedstocks   2,088 
 
   1,867 
 
   221 
 
 Blendstocks and other   252 
 
   241 
 
   11 
 
 Total throughput volumes   2,340 
 
   2,108 
 
   232 
 
           
 Yields (thousand barrels per day):           
 Gasolines and blendstocks   1,069 
 
   1,046 
 
   23 
 
 Distillates   793 
 
   695 
 
   98 
 
 Other products (g)   491 
 
   392 
 
   99 
 
 Total yields   2,353 
 
   2,133 
 
   220 
 

 _______________

 See note references on page  55 .




 51

 Table of Contents


 Refining Operating Highlights by Region (h)

 (millions of dollars, except per barrel amounts)

 
                       
   Nine Months Ended September 30, 
   2011     2010     Change 
 Gulf Coast:           
 Operating income (e)   $   2,064 
 
   $   1,027 
 
   $   1,037 
 
 Throughput volumes (thousand barrels per day)   1,418 
 
   1,268 
 
   150 
 
 Throughput margin per barrel (e) (f)   $   10.48 
 
   $   8.35 
 
   $   2.13 
 
 Operating costs per barrel:       
 
   
 Operating expenses   3.62 
 
   3.78 
 
   (0.16   ) 
 Depreciation and amortization expense   1.53 
 
   1.60 
 
   (0.07   ) 
 Total operating costs per barrel   5.15 
 
   5.38 
 
   (0.23   ) 
 Operating income per barrel   $   5.33 
 
   $   2.97 
 
   $   2.36 
 
           
 Mid-Continent          
 Operating income (e)   $   1,146 
 
   $   271 
 
   $   875 
 
 Throughput volumes (thousand barrels per day)   401 
 
   392 
 
   9 
 
 Throughput margin per barrel (e) (f)   $   16.18 
 
   $   7.59 
 
   $   8.59 
 
 Operating costs per barrel:           
 Operating expenses   4.14 
 
   3.63 
 
   0.51 
 
 Depreciation and amortization expense   1.56 
 
   1.42 
 
   0.14 
 
 Total operating costs per barrel   5.70 
 
   5.05 
 
   0.65 
 
 Operating income per barrel   $   10.48 
 
   $   2.54 
 
   $   7.94 
 
           
 North Atlantic (a) (b):           
 Operating income   $   104 
 
   $   81 
 
   $   23 
 
 Throughput volumes (thousand barrels per day)   268 
 
   189 
 
   79 
 
 Throughput margin per barrel (f)   $   5.32 
 
   $   6.01 
 
   $   (0.69   ) 
 Operating costs per barrel:           
 Operating expenses   2.92 
 
   2.98 
 
   (0.06   ) 
 Depreciation and amortization expense   0.98 
 
   1.47 
 
   (0.49   ) 
 Total operating costs per barrel   3.90 
 
   4.45 
 
   (0.55   ) 
 Operating income per barrel   $   1.42 
 
   $   1.56 
 
   $   (0.14   ) 
           
 West Coast:           
 Operating income (e)   $   162 
 
   $   102 
 
   $   60 
 
 Throughput volumes (thousand barrels per day)   253 
 
   259 
 
   (6   ) 
 Throughput margin per barrel (e) (f)   $   9.87 
 
   $   8.14 
 
   $   1.73 
 
 Operating costs per barrel:           
 Operating expenses   5.21 
 
   5.08 
 
   0.13 
 
 Depreciation and amortization expense   2.31 
 
   1.62 
 
   0.69 
 
 Total operating costs per barrel   7.52 
 
   6.70 
 
   0.82 
 
 Operating income per barrel   $   2.35 
 
   $   1.44 
 
   $   0.91 
 
           
 Operating income for regions above   $   3,476 
 
   $   1,481 
 
   $   1,995 
 
 Asset impairment loss applicable to refining   — 
 
   (2   )     2 
 
 Total refining operating income   $   3,476 
 
   $   1,479 
 
   $   1,997 
 

 _______________

 See note references on page  55 .




 52

 Table of Contents


 Average Market Reference Prices and Differentials (i)

 (dollars per barrel, except as noted)


 
                       
   Nine Months Ended September 30, 
   2011     2010     Change 
 Feedstocks:           
 LLS crude oil   $   111.73 
 
   $   79.35 
 
   $   32.38 
 
 LLS less WTI   16.34 
 
   1.83 
 
   14.51 
 
 LLS less ANS crude oil   2.44 
 
   2.27 
 
   0.17 
 
 LLS less Brent crude oil   (0.82   )     2.14 
 
   (2.96   ) 
 LLS less Mars crude oil   4.05 
 
   3.39 
 
   0.66 
 
 LLS less Maya crude oil   14.58 
 
   10.88 
 
   3.70 
 
 WTI crude oil   95.39 
 
   77.52 
 
   17.87 
 
 WTI less Mars crude oil   (12.29   )     1.56 
 
   (13.85   ) 
 WTI less Maya crude oil   (1.76   )     9.05 
 
   (10.81   ) 
           
 Products:           
 Gulf Coast:           
 Conventional 87 gasoline less LLS   $   7.43 
 
   $   6.26 
 
   $   1.17 
 
 Ultra-low-sulfur diesel less LLS   13.09 
 
   8.61 
 
   4.48 
 
 Propylene less LLS   19.33 
 
   7.80 
 
   11.53 
 
 Conventional 87 gasoline less WTI   23.77 
 
   8.09 
 
   15.68 
 
 Ultra-low-sulfur diesel less WTI   29.43 
 
   10.44 
 
   18.99 
 
 Propylene less WTI   35.67 
 
   9.63 
 
   26.04 
 
 Mid-Continent          
 Conventional 87 gasoline less WTI   24.79 
 
   8.77 
 
   16.02 
 
 Ultra-low-sulfur diesel less WTI   30.75 
 
   11.06 
 
   19.69 
 
 North Atlantic:           
 Conventional 87 gasoline less Brent   6.29 
 
   8.33 
 
   (2.04   ) 
 Ultra-low-sulfur diesel less Brent   14.04 
 
   12.15 
 
   1.89 
 
 Conventional 87 gasoline less WTI   23.45 
 
   8.02 
 
   15.43 
 
 Ultra-low-sulfur diesel less WTI   31.20 
 
   11.84 
 
   19.36 
 
 West Coast:           
 CARBOB 87 gasoline less ANS   13.39 
 
   14.97 
 
   (1.58   ) 
 CARB diesel less ANS   18.56 
 
   12.95 
 
   5.61 
 
 CARBOB 87 gasoline less WTI   27.29 
 
   14.53 
 
   12.76 
 
 CARB diesel less WTI   32.46 
 
   12.51 
 
   19.95 
 
 New York Harbor corn crush (dollars per gallon)   0.17 
 
   0.41 
 
   (0.24   ) 

 _______________

 See note references on page  55 .




 53

 Table of Contents


 Operating Highlights (continued)

 (millions of dollars, except per gallon amounts)


 
                       
   Nine Months Ended September 30, 
   2011     2010     Change 
 Retail–U.S.: (d)           
 Operating income   $   165 
 
   $   181 
 
   $   (16   ) 
 Company-operated fuel sites (average)   994 
 
   990 
 
   4 
 
 Fuel volumes (gallons per day per site)   5,053 
 
   5,115 
 
   (62   ) 
 Fuel margin per gallon   $   0.146 
 
   $   0.158 
 
   $   (0.012   ) 
 Merchandise sales   $   930 
 
   $   910 
 
   $   20 
 
 Merchandise margin (percentage of sales)   28.6   %     28.4   %     0.2    % 
 Margin on miscellaneous sales   $   66 
 
   $   65 
 
   $   1 
 
 Operating expenses   $   312 
 
   $   306 
 
   $   6 
 
 Depreciation and amortization expense   $   56 
 
   $   54 
 
   $   2 
 
           
 Retail–Canada: (d)           
 Operating income   $   133 
 
   $   104 
 
   $   29 
 
 Fuel volumes (thousand gallons per day)   3,210 
 
   3,131 
 
   79 
 
 Fuel margin per gallon   $   0.303 
 
   $   0.263 
 
   $   0.040 
 
 Merchandise sales   $   197 
 
   $   179 
 
   $   18 
 
 Merchandise margin (percentage of sales)   29.6   %     30.3   %     (0.7   )% 
 Margin on miscellaneous sales   $   33 
 
   $   29 
 
   $   4 
 
 Operating expenses   $   196 
 
   $   178 
 
   $   18 
 
 Depreciation and amortization expense   $   28 
 
   $   26 
 
   $   2 
 
           
 Ethanol (c):           
 Operating income   $   215 
 
   $   139 
 
   $   76 
 
 Production (thousand gallons per day)   3,317 
 
   2,943 
 
   374 
 
 Gross margin per gallon of production (f)   $   0.60 
 
   $   0.54 
 
   $   0.06 
 
 Operating costs per gallon of production: 
 
 
 
   
 Operating expenses   0.33 
 
   0.33 
 
   — 
 
 Depreciation and amortization expense   0.03 
 
   0.04 
 
   (0.01   ) 
 Total operating costs per gallon of production   0.36 
 
   0.37 
 
   (0.01   ) 
 Operating income per gallon of production   $   0.24 
 
   $   0.17 
 
   $   0.07 
 

 _______________

 See note references on page  55 .




 54

 Table of Contents


 The following notes relate to references on pages  50  through  54 .

   
 (a)   The information presented for the nine months ended  September 30, 2011  includes the results of operations of our Pembroke Refinery, including the related marketing and logistics business, from the date of its acquisition,  August 1, 2011 , through  September 30, 2011 . In addition, the refining segment and North Atlantic region operating highlights for the nine months ended  September 30, 2011  include the Pembroke Refinery. 
   
 (b)   In December 2010, we sold our Paulsboro Refinery to PBF Holding Company LLC and in June 2010, we sold our shutdown Delaware City Refinery assets and associated terminal and pipeline assets to PBF Energy Partners LP. The results of operations of these refineries have been presented as discontinued operations for the  nine months ended September 30,  2010. In addition, the refining segment and North Atlantic region operating highlights exclude these refineries for  nine months ended September 30,  2010. 
   
 (c)   We acquired three ethanol plants in the first quarter of 2010. The information presented includes the results of operations of those plants commencing on their respective acquisition dates. Ethanol production volumes are based on total production during each period divided by actual calendar days per period. 
   
 (d)   Credit card transaction processing fees incurred by our retail segment of  $68 million  for the  nine months ended September 30,  2010 have been reclassified from retail operating expenses to cost of sales. The Retail–U.S. and Retail–Canada operating highlights for the  nine months ended September 30,  2010 have been restated to reflect this reclassification.