e10vq
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2009
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
(State or other jurisdiction of
incorporation or organization)
  74-1828067
(I.R.S. Employer
Identification No.)
One Valero Way
San Antonio, Texas
(Address of principal executive offices)
78249
(Zip Code)
(210) 345-2000
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The number of shares of the registrant’s only class of common stock, $0.01 par value, outstanding as of July 31, 2009 was 562,761,441.
 
 

 


 

VALERO ENERGY CORPORATION AND SUBSIDIARIES
INDEX
         
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 EX-12.01
 EX-31.01
 EX-31.02
 EX-32.01
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT

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PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Par Value)
                 
    June 30,   December 31,
    2009   2008
    (Unaudited)        
 
ASSETS
               
Current assets:
               
Cash and temporary cash investments
  1,623     940  
Restricted cash
    141       131  
Receivables, net
    4,217       2,897  
Inventories
    4,561       4,637  
Income taxes receivable
    27       197  
Deferred income taxes
    132       98  
Prepaid expenses and other
    472       550  
 
               
Total current assets
    11,173       9,450  
 
               
Property, plant and equipment, at cost
    29,688       28,103  
Accumulated depreciation
    (5,404 )     (4,890 )
 
               
Property, plant and equipment, net
    24,284       23,213  
 
               
Intangible assets, net
    221       224  
Deferred charges and other assets, net
    1,543       1,530  
 
               
Total assets
  37,221     34,417  
 
               
LIABILITIES AND STOCKHOLDERSEQUITY
               
Current liabilities:
               
Current portion of debt and capital lease obligations
  137     312  
Accounts payable
    5,840       4,446  
Accrued expenses
    350       374  
Taxes other than income taxes
    557       592  
Income taxes payable
    36        
Deferred income taxes
    404       485  
 
               
Total current liabilities
    7,324       6,209  
 
               
Debt and capital lease obligations, less current portion
    7,231       6,264  
 
               
Deferred income taxes
    4,105       4,163  
 
               
Other long-term liabilities
    2,154       2,161  
 
               
Commitments and contingencies
               
Stockholders’ equity:
               
Common stock, $0.01 par value; 1,200,000,000 shares authorized; 673,501,593 and 627,501,593 shares issued
    7       6  
Additional paid-in capital
    7,987       7,190  
Treasury stock, at cost; 110,853,320 and 111,290,436 common shares
    (6,856 )     (6,884 )
Retained earnings
    15,384       15,484  
Accumulated other comprehensive loss
    (115 )     (176 )
 
               
Total stockholders’ equity
    16,407       15,620  
 
               
Total liabilities and stockholders’ equity
  37,221     34,417  
 
               
See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars, Except per Share Amounts)
(Unaudited)
                                 
    Three Months Ended      Six Months Ended
    June 30,   June 30,
    2009   2008   2009   2008
 
Operating revenues (1)
  17,925     36,640     31,749     64,585  
 
                               
 
                               
Costs and expenses:
                               
Cost of sales
    16,543       33,673       28,171       59,342  
Operating expenses
    1,015       1,133       2,012       2,247  
Retail selling expenses
    171       190       340       378  
General and administrative expenses
    124       117       269       252  
Depreciation and amortization expense
    389       369       767       736  
 
                               
Total costs and expenses
    18,242       35,482       31,559       62,955  
 
                               
 
Operating income (loss)
    (317 )     1,158       190       1,630  
Other income (expense), net
    (24 )     15       (25 )     35  
Interest and debt expense:
                               
Incurred
    (118 )     (107 )     (237 )     (223 )
Capitalized
    36       24       76       43  
 
                               
 
Income (loss) before income tax expense (benefit)
    (423 )     1,090       4       1,485  
Income tax expense (benefit)
    (169 )     356       (51 )     490  
 
                               
 
Net income (loss)
  (254 )   734     55     995  
 
                               
 
Earnings (loss) per common share
  (0.48 )   1.39     0.11     1.88  
Weighted-average common shares outstanding (in millions)
    525       526       520       529  
 
Earnings (loss) per common share – assuming dilution
  (0.48 )   1.37     0.11     1.85  
Weighted-average common shares outstanding –
assuming dilution (in millions)
    525       534       525       537  
Dividends per common share
  0.15     0.15     0.30     0.27  
 
                   
Supplemental information:
                               
(1) Includes excise taxes on sales by our U.S. retail system
  229     204     433     398  
See Condensed Notes to Consolidated Financial Statements.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)
                 
    Six Months Ended June 30,
    2009   2008
 
Cash flows from operating activities:
               
Net income
  55     995  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization expense
    767       736  
Stock-based compensation expense
    23       24  
Deferred income tax benefit
    (125 )     (93 )
Changes in current assets and current liabilities
    557       189  
Changes in deferred charges and credits and other operating activities, net
    130       (49 )
 
               
Net cash provided by operating activities
    1,407       1,802  
 
               
 
               
Cash flows from investing activities:
               
Capital expenditures
    (1,351 )     (1,178 )
Deferred turnaround and catalyst costs
    (249 )     (203 )
Purchase of certain VeraSun Energy Corporation facilities
    (556 )      
Return of investment in Cameron Highway Oil Pipeline Company
    8       12  
Advance proceeds related to sale of assets
          17  
Contingent payment in connection with acquisition
          (25 )
Minor acquisitions
    (29 )     (57 )
Other investing activities, net
    3       14  
 
               
Net cash used in investing activities
    (2,174 )     (1,420 )
 
               
 
               
Cash flows from financing activities:
               
Proceeds from the sale of common stock, net of issuance costs
    799        
Non-bank debt:
               
Borrowings
    998        
Repayments
    (209 )     (374 )
Bank credit agreements:
               
Borrowings
          296  
Repayments
          (296 )
Accounts receivable sales program:
               
Proceeds from sale of receivables
    500        
Repayments
    (500 )      
Purchase of common stock for treasury
          (700 )
Issuance of common stock in connection with employee benefit plans
    4       11  
Benefit from tax deduction in excess of recognized stock-based compensation cost
    1       13  
Common stock dividends
    (155 )     (143 )
Debt issuance costs
    (8 )      
Other financing activities
    (2 )     (2 )
 
               
Net cash provided by (used in) financing activities
    1,428       (1,195 )
 
               
Effect of foreign exchange rate changes on cash
    22       (7 )
 
               
Net increase (decrease) in cash and temporary cash investments
    683       (820 )
Cash and temporary cash investments at beginning of period
    940       2,464  
 
               
Cash and temporary cash investments at end of period
  1,623     1,644  
 
               
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   Six Months Ended
    June 30,   June 30,
    2009   2008   2009   2008
 
Net income (loss)
  (254 )   734     55     995  
 
                               
 
                               
Other comprehensive income (loss):
                               
Foreign currency translation adjustment
    191       15       110       (62 )
 
                               
 
                               
Pension and other postretirement benefits net (gain) loss reclassified into income, net of income tax expense of $-, $1, $-, and $1
          (1 )           (1 )
 
                               
 
                               
Net gain (loss) on derivative instruments designated and qualifying as cash flow hedges:
                               
Net gain (loss) arising during the period, net of income tax (expense) benefit of $(2), $27, $(34), and $54
    3       (51 )     63       (100 )
Net (gain) loss reclassified into income, net of income tax expense (benefit) of $39, $(17), $60, and $(9)
    (72 )     32       (112 )     17  
 
                               
Net loss on cash flow hedges
    (69 )     (19 )     (49 )     (83 )
 
                               
 
                               
Other comprehensive income (loss)
    122       (5 )     61       (146 )
 
                               
 
                               
Comprehensive income (loss)
  (132 )   729     116     849  
 
                               
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, PRINCIPLES OF CONSOLIDATION, AND SIGNIFICANT ACCOUNTING POLICIES
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 include the accounts of Valero and subsidiaries in which Valero has a controlling interest. Intercompany balances and transactions have been eliminated in consolidation. Investments in significant non-controlled entities are accounted for using the equity method.
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 six months ended June 30, 2009 and 2008 included in these Condensed Notes to Consolidated Financial Statements is derived from our unaudited consolidated financial statements. Operating results for the three and six months ended June 30, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009.
The consolidated balance sheet as of December 31, 2008 has been derived from the audited financial statements as of that date. For further information, refer to the consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2008.
We have evaluated subsequent events that occurred after June 30, 2009 through the filing of this Form 10-Q on August 7, 2009. Any material subsequent events that occurred during this time have been properly recognized or disclosed in our financial statements.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires our management 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, management reviews its estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.
Reclassifications
Certain amounts previously reported for the three and six months ended June 30, 2008 have been reclassified to conform to the 2009 presentation.
2. ACCOUNTING PRONOUNCEMENTS
FSP No. FAS 157-2
In February 2008, the Financial Accounting Standards Board (FASB) issued Staff Position No. FAS 157-2 (FSP No. 157-2), which delayed the effective date of Statement No. 157, “Fair Value Measurements,” for nonfinancial assets and nonfinancial liabilities, except for items that are recognized

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. The exceptions apply to the following: nonfinancial assets and nonfinancial liabilities measured at fair value in a business combination; impaired property, plant and equipment; goodwill; and the initial recognition of the fair value of asset retirement obligations and restructuring costs. The implementation of Statement No. 157 for these assets and liabilities effective January 1, 2009 did not affect our financial position or results of operations but did result in additional disclosures, which are provided in Note 9.
FASB Statement No. 141 (revised 2007)
In December 2007, the FASB issued Statement No. 141 (revised 2007), “Business Combinations” (Statement No. 141(R)). This statement improves the financial reporting of business combinations and clarifies the accounting for these transactions. The provisions of Statement No. 141(R) are to be applied prospectively to business combinations with acquisition dates on or after the beginning of an entity’s fiscal year that begins on or after December 15, 2008, with early adoption prohibited. Due to the adoption of Statement No. 141(R) effective January 1, 2009, the provisions of this statement were applied to the acquisition of certain ethanol plants from VeraSun Energy Corporation (VeraSun) in the second quarter of 2009, which is discussed in Note 3.
FASB Statement No. 160
In December 2007, the FASB issued Statement No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51.” Statement No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. This statement provides guidance for the accounting and reporting of noncontrolling interests, changes in controlling interests, and the deconsolidation of subsidiaries. In addition, Statement No. 160 amends FASB Statement No. 128, “Earnings per Share,” to specify the computation, presentation, and disclosure requirements for earnings per share if an entity has one or more noncontrolling interests. The adoption of Statement No. 160 effective January 1, 2009 has not affected our financial position or results of operations.
FASB Statement No. 161
In March 2008, the FASB issued Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” Statement No. 161 establishes, among other things, the disclosure requirements for derivative instruments and for hedging activities. This statement requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about contingent features related to credit risk in derivative agreements. Statement No. 161 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after November 15, 2008. The adoption of Statement No. 161 effective January 1, 2009 did not affect our financial position or results of operations but did result in additional disclosures, which are provided in Note 10.
FSP No. EITF 03-6-1
In June 2008, the FASB issued Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (FSP No. EITF 03-6-1). FSP No. EITF 03-6-1 addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method described in Statement No. 128. FSP No. EITF 03-6-1 is effective for fiscal years, and interim periods within those fiscal years, beginning

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
after December 15, 2008; early adoption is not permitted. Shares of restricted stock granted under certain of our stock-based compensation plans represent participating securities covered by FSP No. EITF 03-6-1. The adoption of FSP No. EITF 03-6-1 effective January 1, 2009 did not have any effect on the calculation of basic earnings per common share for the three months ended June 30, 2009 and the six months ended June 30, 2009 and 2008, but did reduce basic earnings per common share from the $1.40 amount originally reported for the three months ended June 30, 2008 to $1.39. The calculation is provided in Note 7.
EITF Issue No. 08-6
In November 2008, the FASB ratified its consensus on EITF Issue No. 08-6, “Equity Method Investment Accounting Considerations” (EITF No. 08-6). EITF No. 08-6 applies to all investments accounted for under the equity method and provides guidance regarding (i) initial measurement of an equity investment, (ii) recognition of an other-than-temporary impairment of an equity method investment, including any impairment charge taken by the investee, and (iii) accounting for a change in ownership level or degree of influence on an investee. The consensus is effective for fiscal years beginning on or after December 15, 2008, and interim periods within those fiscal years. EITF No. 08-6 is to be applied prospectively and earlier application is not permitted. Due to its application to future equity method investments, the adoption of EITF No. 08-6 effective January 1, 2009 has not had any immediate effect on our financial position or results of operations.
FSP No. FAS 132(R)-1
In December 2008, the FASB issued Staff Position No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP No. FAS 132(R)-1). FSP No. FAS 132(R)-1 amends FASB Statement No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The additional requirements of FSP No. FAS 132(R)-1 are designed to enhance disclosures regarding (i) investment policies and strategies, (ii) categories of plan assets, (iii) fair value measurements of plan assets, and (iv) significant concentrations of risk. FSP No. FAS 132(R)-1 is effective for fiscal years ending after December 15, 2009, with earlier application permitted. Since FSP No. FAS 132(R)-1 only affects disclosure requirements, the adoption of FSP No. FAS 132(R)-1 will not affect our financial position or results of operations.
FSP No. FAS 141(R)-1
In April 2009, the FASB issued Staff Position No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (FSP No. FAS 141(R)-1). FSP No. FAS 141(R)-1 amends and clarifies FASB Statement No. 141(R) to address application issues raised related to (i) initial recognition and measurement, (ii) subsequent measurement and accounting, and (iii) disclosure of assets and liabilities arising from contingencies in a business combination. The provisions of FSP No. FAS 141(R)-1 are to be applied to contingent assets or contingent liabilities acquired in business combinations for which the acquisition date is on or after the beginning of an entity’s fiscal year that begins on or after December 15, 2008. The adoption of FSP No. FAS 141(R)-1 effective January 1, 2009 has not had a material effect on our financial position or results of operations.
FSP No. FAS 107-1 and APB 28-1, FSP No. FAS 157-4, and FSP No. FAS 115-2 and FAS 124-2
In April 2009, the FASB issued Staff Position No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP No. FAS 107-1 and APB 28-1). FSP No. FAS 107-1 and

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
APB 28-1 amends FASB Statement No. 107, “Disclosures about Fair Value of Financial Instruments,” to require a publicly traded company to include disclosures about the fair value of its financial instruments for interim reporting periods as well as in annual financial statements. FSP No. FAS 107-1 and APB 28-1 is effective for interim reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The early adoption provision of FSP No. FAS 107-1 and APB 28-1 is available only if an entity also elects to apply the early adoption provisions of FASB Staff Position No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP No. FAS 157-4), and FASB Staff Position No. FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP No. FAS 115-2 and FAS 124-2). We adopted these three FASB Staff Positions in the first quarter of 2009, none of which has affected our financial position or results of operations. However, the adoption of FSP No. FAS 107-1 and APB 28-1 resulted in additional interim disclosures discussed below.
Our financial instruments include cash and temporary cash investments, restricted cash, receivables, payables, debt, capital lease obligations, commodity derivative contracts, and foreign currency derivative contracts. The estimated fair values of these financial instruments approximate their carrying amounts as reflected in the consolidated balance sheets, except for certain debt as discussed in Note 5. The fair values of our debt, commodity derivative contracts, and foreign currency derivative contracts were estimated primarily based on quoted market prices and inputs other than quoted prices that are observable for the asset or liability.
FASB Statement No. 165
In May 2009, the FASB issued Statement No. 165, “Subsequent Events.” Statement No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. In particular, Statement No. 165 provides guidance regarding (i) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (ii) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and (iii) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. The provisions of Statement No. 165 are to be applied prospectively and are effective for interim or annual financial periods ending after June 15, 2009. The adoption of Statement No. 165 in the second quarter of 2009 did not affect our financial position or results of operations but did result in additional disclosures, which are provided in Note 1.
FASB Statement No. 166
In June 2009, the FASB issued Statement No. 166, “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140.” Statement No. 166 amends and clarifies the provisions of Statement No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” in order to address application and disclosure issues. In general, Statement No. 166 clarifies the requirements for derecognizing transferred financial assets, removes the concept of a qualifying special-purpose entity and related exceptions, and requires additional disclosures related to transfers of financial assets. Statement No. 166 is effective for fiscal years, and interim periods within those fiscal years, beginning after November 15, 2009, and earlier application is prohibited. The adoption of Statement No. 166 effective January 1, 2010 is not expected to materially affect our financial position or results of operations.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
FASB Statement No. 167
In June 2009, the FASB issued Statement No. 167, “Amendments to FASB Interpretation No. 46(R).” Statement No. 167 amends the provisions of FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities,” to include entities previously considered qualifying special-purpose entities, as the concept of these entities was eliminated by Statement No. 166. This statement also clarifies consolidation requirements and expands disclosure requirements related to variable interest entities. Statement No. 167 is effective for fiscal years, and interim periods within those fiscal years, beginning after November 15, 2009, and earlier application is prohibited. The adoption of Statement No. 167 effective January 1, 2010 is not expected to materially affect our financial position or results of operations.
FASB Statement No. 168
In June 2009, the FASB issued Statement No. 168, “The FASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162” (Codification). Statement No. 168 replaces Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” and establishes the Codification as the source of authoritative GAAP recognized by the FASB, to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. Rules and interpretive releases of the Securities and Exchange Commission (SEC) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of Statement No. 168, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become nonauthoritative. Statement No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of Statement No. 168 in the third quarter of 2009 is not expected to materially affect our financial position or results of operations. Commencing with the Form 10-Q for the third quarter of 2009, future filings with the SEC will reference the Codification rather than prior accounting and reporting standards.
3. ACQUISITION
In the second quarter of 2009, we acquired seven ethanol plants and a site under development from VeraSun. Because VeraSun was subject to bankruptcy proceedings and different lenders were involved with various plants, three separate closings were required to consummate the acquisition of these ethanol plants. On April 1, 2009, we closed on the acquisition of ethanol plants located in Charles City, Fort Dodge, and Hartley, Iowa; Aurora, South Dakota; and Welcome, Minnesota, and a site under development located in Reynolds, Indiana for consideration of $350 million. Through subsequent closings on April 9, 2009 and May 8, 2009, we acquired VeraSun’s ethanol plant in Albert City, Iowa, for consideration of $72 million and VeraSun’s ethanol plant in Albion, Nebraska, for consideration of $55 million, respectively. In conjunction with the acquisition of the seven ethanol plants, we also paid $79 million primarily for inventory and certain other working capital. We have elected to use the LIFO method of accounting for the commodity inventories related to the acquired ethanol business. The acquisition of these ethanol plants is referred to as the VeraSun Acquisition. We incurred approximately $10 million of acquisition-related costs that were recognized as expense in “general and administrative expenses” in the consolidated statements of income for the three and six months ended June 30, 2009.
The acquired ethanol business involves the production and marketing of ethanol and its co-products, including distillers grains. The ethanol operations are being reported as a new operating segment in Note 11, the operations of which will complement our existing clean motor fuels business. The

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
acquisition cost was funded with part of the proceeds from a $1 billion issuance of notes in March 2009, which is discussed in Note 5.
An independent appraisal of the assets acquired in the VeraSun Acquisition has been substantially completed, and the assets acquired and the liabilities assumed have been recognized at their acquisition-date fair values as determined by the appraisal and other evaluations as follows (in millions):
         
Current assets, primarily inventory
  77  
Property, plant and equipment
    491  
Identifiable intangible assets
    1  
Current liabilities
    (10 )
Other long-term liabilities
    (3 )
 
       
Total consideration
  556  
 
       
Neither goodwill nor a gain from a bargain purchase was recognized in conjunction with the VeraSun Acquisition, and no significant contingent assets or liabilities were acquired or assumed in the acquisition.
The consolidated statements of income include the results of operations of the various ethanol plants commencing on their respective closing dates. The operating revenues and net income associated with the acquired ethanol plants included in our consolidated statements of income for the three and six months ended June 30, 2009, and the consolidated pro forma operating revenues, net income (loss), and earnings (loss) per common share – assuming dilution of the combined entity had the VeraSun Acquisition occurred on January 1, 2009 and 2008, are shown in the table below (in millions, except per share amounts). The pro forma information assumes that the purchase price was funded with proceeds from the issuance of $556 million of debt on January 1 of each respective year. The pro forma amounts for the three months ended June 30, 2009 are the same as actual consolidated results for that period because the two acquired plants with closing dates subsequent to April 1, 2009 were not operating during the second quarter prior to our acquisition of those facilities. The pro forma financial information is not necessarily indicative of the results of future operations.
                                 
    Three Months Ended   Six Months Ended
    June 30,   June 30,
    2009   2008   2009   2008
 
Actual amounts from acquired business from
April 1 – June 30, 2009:
                               
Operating revenues
  263       N/A     263       N/A  
Net income
    13       N/A       13       N/A  
 
                               
Consolidated pro forma:
                               
Operating revenues
  17,925     37,059     31,972     65,327  
Net income (loss)
    (254 )     734       49       1,004  
Earnings (loss) per common share –
assuming dilution
  (0.48 )     1.37       0.09       1.87  

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. INVENTORIES
Inventories consisted of the following (in millions):
                    
       June 30,      December 31,
    2009   2008
 
Refinery feedstocks
  2,065     2,140  
Refined products and blendstocks
    2,105       2,224  
Ethanol feedstocks and products
    100        
Convenience store merchandise
    93       90  
Materials and supplies
    198       183  
 
               
Inventories
  4,561     4,637  
 
               
As of June 30, 2009 and December 31, 2008, the replacement cost (market value) of LIFO inventories exceeded their LIFO carrying amounts by approximately $3.0 billion and $686 million, respectively.
5. DEBT
Non-Bank Debt
On April 1, 2009, we made scheduled debt repayments of $200 million related to our 3.5% notes and $9 million related to our 5.125% Series 1997D industrial revenue bonds.
In March 2009, we issued $750 million of 9.375% notes due March 15, 2019 and $250 million of 10.5% notes due March 15, 2039. Proceeds from the issuance of these notes totaled approximately $998 million, before deducting underwriting discounts and other issuance costs of $8 million.
On February 1, 2008, we redeemed our 9.50% senior notes for $367 million, or 104.75% of stated value. These notes had a carrying amount of $381 million on the date of redemption, resulting in a gain of $14 million that was included in “other income (expense), net” in the consolidated statement of income. In addition, in March 2008, we made a scheduled debt repayment of $7 million related to certain of our other debt.
Under the indenture related to our $100 million of 6.75% senior notes with a maturity date of October 15, 2037, on July 31, 2009, we notified the holders of such notes of our obligation to purchase any of those notes for which a written notice of purchase (purchase notice) is received from the holders prior to September 15, 2009. Any notes for which a purchase notice is received will be purchased at 100% of their principal amount plus accrued and unpaid interest to October 15, 2009, the date of payment of the purchase price.
Bank Credit Facilities
During the six months ended June 30, 2009, we had no borrowings or repayments under our revolving bank credit facilities. As of June 30, 2009, we had no borrowings outstanding under our revolving bank credit facilities.
As of June 30, 2009, we had $247 million of letters of credit outstanding under our uncommitted short-term bank credit facilities and $249 million of letters of credit outstanding under our U.S. committed

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
revolving credit facilities. Under our Canadian committed revolving credit facility, we had Cdn. $19 million of letters of credit outstanding as of June 30, 2009.
In June 2008, we entered into a one-year committed revolving letter of credit facility under which we could obtain letters of credit of up to $300 million to support certain of our crude oil purchases. In June 2009, we amended this agreement to extend the maturity date to June 2010. We are being charged letter of credit issuance fees in connection with the letter of credit facility.
During the six months ended June 30, 2008, we borrowed and repaid $296 million under our revolving bank credit facility.
In July 2008, we entered into a one-year committed revolving letter of credit facility under which we could obtain letters of credit of up to $275 million. This credit facility expired in July 2009.
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 2009 to extend the maturity date to June 2010.
As of December 31, 2008, the amount of eligible receivables sold to the third-party entities and financial institutions was $100 million, which was repaid in February 2009. In March 2009, we sold $100 million of eligible receivables to the third-party entities and financial institutions. In April 2009, we sold an additional $400 million of eligible receivables under this program, which we repaid in June 2009. As of June 30, 2009, the amount of eligible receivables sold to the third-party entities and financial institutions was $100 million. Proceeds from the sale of receivables under this facility are reflected as debt in our consolidated balance sheets.
Other Disclosures
The estimated fair value of our debt, including current portion, was as follows (in millions):
                 
       June 30,      December 31,
    2009   2008
 
Carrying amount
  7,330     6,537  
Fair value
    7,305       6,462  
6. STOCKHOLDERS’ EQUITY
Common Stock Offering
On June 3, 2009, we sold in a public offering 46 million shares of our common stock, which included 6 million shares related to an overallotment option exercised by the underwriters, at a price of $18.00 per share and received proceeds, net of underwriting discounts and commissions and other issuance costs, of $799 million.
Treasury Stock
No significant purchases of our common stock were made during the six months ended June 30, 2009. During the six months ended June 30, 2008, we purchased 12.6 million shares of our common stock at a cost of $700 million in connection with the administration of our employee benefit plans and common

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
stock purchase programs authorized by our board of directors. During the six months ended June 30, 2009 and 2008, we issued 0.5 million shares and 0.9 million shares, respectively, from treasury for our employee benefit plans.
Common Stock Dividends
On July 30, 2009, our board of directors declared a regular quarterly cash dividend of $0.15 per common share payable on September 16, 2009 to holders of record at the close of business on August 12, 2009.
7. EARNINGS (LOSS) PER COMMON SHARE
Earnings (loss) per common share amounts were computed as follows (dollars and shares in millions, except per share amounts):
                                 
    Three Months Ended June 30,
    2009   2008
    Restricted   Common   Restricted   Common
    Stock   Stock   Stock   Stock
 
Earnings (loss) per common share:
                               
Net income (loss)
          (254 )           734  
Less dividends paid:
                               
Common stock
            77               79  
Nonvested restricted stock
            1                
 
                               
Undistributed earnings (loss)
          (332 )           655  
 
                               
 
                               
Weighted-average common shares outstanding
    2       525       1       526  
 
                               
 
                               
Earnings (loss) per common share:
                               
Distributed earnings
  0.15     0.15     0.15     0.15  
Undistributed earnings (loss)
          (0.63 )     1.24       1.24  
 
                               
Total earnings (loss) per common share (1)
  0.15     (0.48 )   1.39     1.39  
 
                               
 
                               
Earnings (loss) per common share – assuming dilution:
                               
Net income (loss)
          (254 )           734  
 
                               
 
                               
Weighted-average common shares outstanding
            525               526  
Common equivalent shares (2):
                               
Stock options
                          8  
Performance awards and other benefit plans
                           
 
                               
Weighted-average common shares outstanding –
assuming dilution
            525               534  
 
                               
 
                               
Earnings (loss) per common share – assuming dilution
          (0.48 )           1.37  
 
                               

(1)   The basic earnings per common share amount originally reported for the three months ended June 30, 2008 changed from $1.40 as a result of the adoption of FSP No. EITF 03-6-1 effective January 1, 2009, as discussed in Note 2.
 
(2)   Common equivalent shares were excluded from the computation of diluted earnings per share for the three months ended June 30, 2009 because the effect of including such shares would be anti-dilutive.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
                                 
    Six Months Ended June 30,
    2009   2008
    Restricted   Common   Restricted   Common
    Stock   Stock   Stock   Stock
 
Earnings per common share:
                               
Net income
          55             995  
Less dividends paid:
                               
Common stock
            154               143  
Nonvested restricted stock
            1                
 
                               
Undistributed earnings (loss)
          (100 )           852  
 
                               
 
                               
Weighted-average common shares outstanding
    2       520       1       529  
 
                               
 
                               
Earnings per common share:
                               
Distributed earnings
  0.30     0.30     0.26     0.27  
Undistributed earnings (loss)
          (0.19 )     1.61       1.61  
 
                               
Total earnings per common share
  0.30     0.11     1.87     1.88  
 
                               
 
                               
Earnings per common share – assuming dilution:
                               
Net income
          55             995  
 
                               
 
                               
Weighted-average common shares outstanding
            520               529  
Common equivalent shares:
                               
Stock options
            4               8  
Performance awards and other benefit plans
            1                
 
                               
Weighted-average common shares outstanding –
assuming dilution
            525               537  
 
                               
 
                               
Earnings per common share – assuming dilution
          0.11             1.85  
 
                               
The following table reflects potentially dilutive securities that were excluded from the calculation of “earnings (loss) per common share – assuming dilution” as the effect of including such securities would have been anti-dilutive (in millions). As indicated above, for the three months ended June 30, 2009, common equivalent shares, which represent primarily stock options, were excluded as a result of the net loss reported for the second quarter of 2009. In addition, for all periods, certain stock option amounts presented below were excluded, representing outstanding stock options for which the exercise prices were greater than the average market price of the common shares during each respective reporting period.
                                     
    Three Months Ended June 30,   Six Months Ended June 30,
    2009   2008   2009   2008
   
Common equivalent shares
    5                    
Stock options
    11       4       10       4  

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
8. STATEMENTS OF CASH FLOWS
In order to determine net cash provided by operating activities, net income is adjusted by, among other things, changes in current assets and current liabilities as follows (in millions):
                 
    Six Months Ended June 30,
    2009   2008
   
Decrease (increase) in current assets:
               
Restricted cash
  $ (10 )   $ (69 )
Receivables, net
    (1,286 )     (54 )
Inventories
    172       (865 )
Income taxes receivable
    181        
Prepaid expenses and other
    11       4  
Increase (decrease) in current liabilities:
               
Accounts payable
    1,592       1,466  
Accrued expenses
    (97 )     (144 )
Taxes other than income taxes
    (41 )     (61 )
Income taxes payable
    35       (88 )
 
               
Changes in current assets and current liabilities
  557     189  
 
               
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;
   
the amounts shown above exclude the current assets and current liabilities acquired in connection with the VeraSun Acquisition;
   
previously accrued capital expenditures, deferred turnaround and catalyst costs, and contingent earn-out payments, as well as advance proceeds related to the sale of assets, are reflected in investing activities in the consolidated statements of cash flows;
   
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 in the consolidated statements of cash flows when the purchases are settled and paid;
    changes in assets held for sale and liabilities related to assets held for sale pertaining to the operations of the Krotz Springs Refinery prior to its sale to Alon Refining Krotz Springs, Inc. (Alon), a subsidiary of Alon USA Energy, Inc., in July 2008 are reflected in the line items to which the changes relate in the table above; and
    certain differences between consolidated balance sheet changes and consolidated statement of cash flow changes reflected above result from translating foreign currency denominated amounts at different exchange rates.
There were no significant noncash investing or financing activities for the six months ended June 30, 2009 and 2008.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Cash flows related to interest and income taxes were as follows (in millions):
                 
    Six Months Ended June 30,
    2009   2008
   
Interest paid in excess of amount capitalized
  152     199  
Income taxes paid (net of tax refunds received)
    (144 )     659  
9. FAIR VALUE MEASUREMENTS
Statement No. 157 establishes a fair value hierarchy (Level 1, Level 2, or Level 3) based on the quality of inputs used to measure fair value. Pursuant to the provisions of Statement No. 157, fair values determined by Level 1 inputs utilize quoted prices in active markets for identical assets or liabilities. Fair values determined by Level 2 inputs are based on quoted prices for similar assets and liabilities in active markets, and inputs other than quoted prices that are observable for the asset or liability. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. We use appropriate valuation techniques based on the available inputs to measure the fair values of our applicable assets and liabilities. When available, we measure fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.
The table below presents information (dollars in millions) about our financial assets and liabilities measured and recorded at fair value on a recurring basis and indicates the fair value hierarchy of the inputs utilized by us to determine the fair values as of June 30, 2009 and December 31, 2008.
                                        
    Fair Value Measurements Using    
    Quoted   Significant        
    Prices   Other   Significant    
    in Active   Observable   Unobservable    
    Markets   Inputs   Inputs   Total as of
    (Level 1)   (Level 2)   (Level 3)   June 30, 2009
   
Assets:
                               
Commodity derivative contracts
  12     537         549  
Nonqualified benefit plans
    99                   99  
Alon earn-out agreement
                38       38  
Liabilities:
                               
Commodity derivative contracts
    19       7             26  
Certain nonqualified benefit plans
    29                   29  

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
                                        
    Fair Value Measurements Using    
    Quoted   Significant        
    Prices   Other   Significant    
    in Active   Observable   Unobservable   Total as of
    Markets   Inputs   Inputs   December 31,
    (Level 1)   (Level 2)   (Level 3)   2008
   
Assets:
                               
Commodity derivative contracts
  40     610         650  
Nonqualified benefit plans
    98                   98  
Alon earn-out agreement
                13       13  
Liabilities:
                               
Commodity derivative contracts
          7             7  
Certain nonqualified benefit plans
    26                   26  
The valuation methods used to measure our financial instruments at fair value are as follows:
   
Commodity derivative contracts, consisting primarily of exchange-traded futures and swaps, are measured at fair value using the market approach pursuant to the provisions of Statement No. 157. 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 since 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.
   
Nonqualified benefit plan assets and certain nonqualified benefit plan liabilities are measured at fair value using a market approach based on quotations from national securities exchanges and are categorized in Level 1 of the fair value hierarchy.
   
The Alon earn-out agreement, which we received as partial consideration for the sale of our Krotz Springs Refinery in July 2008, is measured at fair value using a discounted cash flow model and is categorized in Level 3 of the fair value hierarchy. Significant inputs to the model include expected payments and discount rates that consider the effects of both credit risk and the time value of money.
Deposits of $104 million in broker accounts covered by master netting arrangements are included in the fair value of the commodity derivatives reflected in Level 1. Certain of our commodity derivative contracts under master netting arrangements include both asset and liability positions. Under the guidance of FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39,” 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.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following is a reconciliation of the beginning and ending balances (in millions) for fair value measurements developed using significant unobservable inputs for the three and six months ended June 30, 2009. We did not have any fair value measurements using significant unobservable inputs for the six months ended June 30, 2008.
                 
    Three Months   Six Months
    Ended June 30,   Ended June 30,
    2009   2009
   
Balance at beginning of period
  24     13  
Net unrealized gains included in earnings
    14       25  
Transfers in and/or out of Level 3
           
 
               
Balance as of June 30, 2009
  38     38  
 
               
Unrealized gains for the three and six months ended June 30, 2009, which are reported in “other income (expense), net” in the consolidated statements of income, relate to the Alon earn-out agreement that was still held at the reporting date. These unrealized gains were offset by the recognition in “other income (expense), net” of losses on derivative instruments entered into to hedge the risk of changes in the fair value of the Alon earn-out agreement. The derivative instruments used to hedge the Alon earn-out agreement are included in the “commodity derivative contracts” amounts reflected in the fair value table above.
The table below presents information (dollars in millions) about our nonfinancial liabilities measured and recorded at fair value on a nonrecurring basis that arose on or after January 1, 2009 (the date of adoption of FSP No. FAS 157-2), and indicates the fair value hierarchy of the inputs utilized by us to determine the fair values as of June 30, 2009.
                                 
    Fair Value Measurements Using    
    Quoted   Significant        
    Prices   Other   Significant    
    in Active   Observable   Unobservable    
    Markets   Inputs   Inputs   Total as of
    (Level 1)   (Level 2)   (Level 3)   June 30, 2009
   
Liabilities:
                               
Asset retirement obligations
          $ 9     $ 9  
Asset retirement obligations in the table above are calculated based on the present value of estimated removal and other closure costs using our internal risk-free rate of return or appropriate equivalent.
10. PRICE RISK MANAGEMENT ACTIVITIES
We enter into derivative instruments to manage our exposure to commodity price risk, interest rate risk, and foreign currency risk, and to hedge price risk on other contractual derivatives that we have entered into. In addition, we use derivative instruments for trading purposes based on our fundamental and technical analysis of market conditions. All derivative instruments are recorded on our balance sheet as either assets or liabilities measured at their fair values. 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 activity. 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

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 hedging relationships (hedges 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.
Commodity Price Risk
We are exposed to market risks related to the volatility of crude oil and refined product prices, as well as volatility in the price of natural gas used in our refining operations. To reduce the impact of this price volatility on our results of operations and cash flows, we use derivative commodity instruments, including swaps, futures, and options, to manage our exposure to commodity price risks. For such 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 derivative commodity instruments for trading purposes. Our objectives for entering into each of these types of derivative instruments and the level of activity of each as of June 30, 2009 are described below.
Fair Value Hedges
Fair value hedges are used to hedge 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 normally represents the amount by which our inventories differ from our previous year-end LIFO inventory levels.
As of June 30, 2009, we had the following outstanding derivative commodity instruments that were entered into to hedge crude oil and refined product inventories. The information presents the volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).
         
Derivative Instrument / Maturity
 
Contract Volumes
 
Futures – short (2009)
    5,178  
Cash Flow Hedges
Cash flow hedges are used to hedge certain forecasted feedstock and product purchases, refined product sales, and natural gas purchases. The purpose of our cash flow hedges is to lock in the price of forecasted feedstock or natural gas purchases or refined product sales at existing market prices that are deemed favorable by management.
As of June 30, 2009, we had the following outstanding derivative commodity instruments that were entered into to hedge forecasted purchases or sales of crude oil and refined products. The information presents the volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels).

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
         
Derivative Instrument / Maturity
 
Contract Volumes
 
Swaps – long:
       
2009
    14,157  
2010
    15,900  
Swaps – short:
       
2009
    14,157  
2010
    15,900  
Futures – long (2009)
    1,211  
Economic Hedges
Economic hedges are hedges not designated as fair value or cash flow hedges that are used to (i) manage price volatility in certain refinery feedstock, refined product, and grain inventories, (ii) manage price volatility in certain forecasted refinery feedstock, product, and grain purchases, refined product sales, and natural gas purchases; and (iii) manage price volatility in the referenced product margins associated with the Alon earn-out agreement, which is a separate contractual derivative that we entered into with the sale of our Krotz Springs Refinery, as further discussed in Note 9. 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 June 30, 2009, we had the following outstanding derivative commodity instruments that were entered into as economic hedges. The information presents the volume of outstanding contracts by type of instrument and year of maturity (volumes in thousands of barrels, except those identified as grain contracts that are presented in thousands of bushels).
         
Derivative Instrument / Maturity
 
Contract Volumes
 
Swaps – long:
       
2009
    52,625  
2010
    51,514  
2011
    11,750  
Swaps – short:
       
2009
    36,233  
2010
    47,878  
2011
    8,850  
Futures – long:
       
2009
    238,825  
2010
    39,618  
2009 (grain)
    7,605  
2010 (grain)
    50  
Futures – short:
       
2009
    231,332  
2010
    39,174  
2009 (grain)
    20,355  
2010 (grain)
    3,405  

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Trading Activities
These represent derivative commodity instruments held or issued for trading purposes. Our objective in entering into derivative commodity instruments for trading purposes is to take advantage of existing market conditions related to crude oil and refined products that management perceives as opportunities to benefit our results of operations and cash flows, but for which there are no related physical transactions. As of June 30, 2009, we had the following outstanding derivative commodity instruments that were entered into for trading purposes. The information presents the 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).
         
Derivative Instrument / Maturity
 
Contract Volumes
 
Swaps – long:
       
2009
    10,413  
2010
    18,780  
2011
    3,000  
Swaps – short:
       
2009
    12,455  
2010
    22,008  
2011
    3,900  
Futures – long:
       
2009
    30,122  
2010
    2,321  
2009 (natural gas)
    5,350  
2010 (natural gas)
    100  
Futures – short:
       
2009
    30,214  
2010
    2,346  
2009 (natural gas)
    5,100  
2010 (natural gas)
    100  
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, we have at times used interest rate swap agreements to manage our fixed to floating interest rate position by converting certain fixed-rate debt to floating-rate debt. These interest rate swap agreements are generally accounted for as fair value hedges. However, we have not had any outstanding interest rate swap agreements since 2006.
Foreign Currency Risk
We are exposed to exchange rate fluctuations on transactions related to our Canadian operations. To manage our exposure to these exchange rate fluctuations, we use foreign currency exchange and purchase contracts. These contracts are not designated as hedging instruments for accounting purposes, and therefore they are classified as economic hedges. As of June 30, 2009, we had commitments to purchase $301 million of U.S. dollars. These commitments matured on or before July 20, 2009, resulting in a $7 million loss in the third quarter of 2009.

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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 June 30, 2009 (in millions) and the line items in the balance sheet in which the fair values are reflected. See Note 9 for additional information related to the fair values of our derivative instruments. As indicated in Note 9, we net fair value amounts recognized for multiple similar derivative instruments executed with the same counterparty under master netting arrangements. The table below, however, is presented on a gross asset and gross liability basis as required by Statement No. 161, which results in the reflection of certain assets in liability accounts and certain liabilities in asset accounts. In addition, in Note 9 we included cash collateral of $104 million in the fair value of the commodity derivatives; the cash collateral is not reflected in the table below.
                         
   
Asset Derivatives
 
Liability Derivatives
    Balance Sheet       Balance Sheet    
   
Location
 
Fair Value
 
Location
 
Fair Value
 
Derivatives designated as
hedging instruments
 
 
         
 
       
Commodity contracts:
 
 
         
 
       
Futures
 
Receivables, net
  3    
Receivables, net
  1  
Futures
 
Accrued expenses
    31    
Accrued expenses
    49  
Swaps
 
Receivables, net
    425    
Receivables, net
    385  
Swaps
 
Prepaid expenses and other current assets
    1,409    
Prepaid expenses and other current assets
    1,235  
Swaps
 
Accrued expenses
    293    
Accrued expenses
    293  
 
 
 
         
 
       
Total derivatives designated as
hedging instruments
 
 
  2,161    
 
  1,963  
 
 
 
         
 
       
 
 
 
         
 
       
Derivatives not designated as
hedging instruments
 
 
         
 
       
Commodity contracts:
 
 
         
 
       
Futures
 
Receivables, net
  28    
Receivables, net
  15  
Futures
 
Accrued expenses
    3,560    
Accrued expenses
    3,668  
Swaps
 
Receivables, net
    671    
Receivables, net
    550  
Swaps
 
Prepaid expenses and other current assets
    1,458    
Prepaid expenses and other current assets
    1,256  
Swaps
 
Accrued expenses
    93    
Accrued expenses
    100  
Alon earn-out agreement
 
Receivables, net
    38    
Accrued expenses
     
Foreign currency contracts
 
Receivables, net
       
Accounts payable
     
 
 
 
         
 
       
Total derivatives not designated as hedging instruments
 
 
  5,848    
 
  5,589  
 
 
 
         
 
       
 
 
 
         
 
       
Total derivatives
 
 
  8,009    
 
  7,552  
 
 
 
         
 
       

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 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, in that these customers may be similarly affected by changes in economic or other conditions. In addition, financial services companies are the counterparties in certain of our price risk management activities, and such financial services companies may be adversely affected by periods of uncertainty and illiquidity in the credit and capital markets.
As of June 30, 2009, we had net receivables related to derivative instruments of $32 million from counterparties in the refining industry and $343 million from counterparties in the financial services industry. These amounts represent the aggregate receivables from 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 that we enter into. We also do not have any derivative instruments that require us to maintain a minimum investment-grade credit rating.
Effect of Derivative Instruments on 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 for the three and six months ended June 30, 2009 (in millions), and the line items in the financial statements in which such gains and losses are reflected.
                                                                 
    Location                   Location                   Amount
    of Gain or                   of Gain or   Amount   of Gain or
    (Loss)   Amount of   (Loss)   of Gain or   (Loss)
Derivatives in   Recognized   Gain or (Loss)   Recognized   (Loss)   Recognized
Fair Value   in Income   Recognized in   in Income   Recognized   in Income for
Hedging   on   Income   on   in Income   Ineffective Portion
Relationships
 
Derivatives
 
on Derivatives
 
Hedged Item
 
on Hedged Item
 
of Derivative (1)
            Three   Six           Three   Six   Three   Six
            Months   Months           Months   Months   Months   Months
            Ended   Ended           Ended   Ended   Ended   Ended
            June 30,   June 30,           June 30,   June 30,   June 30,   June 30,
           
2009
 
2009
         
2009
 
2009
 
2009
 
2009
 
Commodity contracts
  Cost of sales   (74 )   (89 )   Cost of sales   75     90     1     1  
 
                                                               
Total
          (74 )   (89 )           75     90     1     1  
 
                                                               
(1)  
For fair value hedges, no component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness. No amounts were recognized in income for hedged firm commitments that no longer qualify as fair value hedges.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
                                                                 
    Amount of   Location of   Amount of   Location of   Amount of
    Gain or (Loss)   Gain or (Loss)   Gain or (Loss)   Gain or (Loss)   Gain or (Loss)
Derivatives in   Recognized in   Reclassified from   Reclassified from   Recognized in   Recognized in
Cash Flow   OCI on   Accumulated OCI   Accumulated OCI   Income on   Income on
Hedging   Derivatives   into Income   into Income   Derivatives   Derivatives
Relationships
 
(Effective Portion)
 
(Effective Portion)
 
(Effective Portion)
 
(Ineffective Portion)
 
(Ineffective Portion) (1)
    Three   Six           Three   Six           Three   Six
    Months   Months           Months   Months           Months   Months
    Ended   Ended           Ended   Ended           Ended   Ended
    June 30,   June 30,           June 30,   June 30,           June 30,   June 30,
   
2009
 
2009
         
2009
 
2009
         
2009
 
2009
 
Commodity contracts (2)
  5     97     Cost of sales   111     172     Cost of sales   (1 )   (1 )
 
                                                               
Total
  5     97             111     172             (1 )   (1 )
 
                                                               
 
(1)  
No component of the derivative instruments’ gains or losses was excluded from the assessment of hedge effectiveness.
 
(2)  
For the three and six months ended June 30, 2009, cash flow hedges primarily related to forward sales of distillates and associated forward purchases of crude oil, with $120 million of cumulative after-tax gains on cash flow hedges remaining in “accumulated other comprehensive loss” as of June 30, 2009. We expect that a significant amount of the deferred gains at June 30, 2009 will be reclassified into “cost of sales” over the next 12 months as a result of hedged transactions that are forecasted to occur. The amount ultimately realized in income, however, will differ as commodity prices change. For the three and six months ended June 30, 2009, there were no amounts reclassified from “accumulated other comprehensive loss” into income as a result of the discontinuance of cash flow hedge accounting.
                     
    Location of   Amount of
Derivatives Designated as   Gain or (Loss)   Gain or (Loss)
Economic Hedges   Recognized in   Recognized in
and Other   Income on   Income on
Derivative Instruments
 
Derivatives
 
Derivatives
        Three Months Ended   Six Months Ended
       
June 30, 2009
 
June 30, 2009
 
Commodity contracts
  Cost of sales   (58 )   38  
Foreign currency contracts
  Cost of sales     (22 )     (16 )
 
                   
 
        (80 )     22  
 
                   
Alon earn-out agreement
  Other income (expense)     14       25  
Alon earn-out hedge (commodity contracts)
  Other income (expense)     (48 )     (63 )
 
                   
 
        (34 )     (38 )
 
                   
Total
      (114 )   (16 )
 
                   
                     
    Location of   Amount of
    Gain or (Loss)   Gain or (Loss)
    Recognized in   Recognized in
Derivatives Designated as   Income on   Income on
Trading Activities
 
Derivatives
 
Derivatives
        Three Months Ended   Six Months Ended
       
June 30, 2009
 
June 30, 2009
 
Commodity contracts
  Cost of sales   25     116  
 
                   
Total
      25     116  
 
                   

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. SEGMENT INFORMATION
Prior to the second quarter of 2009, we had two reportable segments, which were refining and retail. As a result of our acquisition of seven ethanol plants from VeraSun during the second quarter of 2009 (as discussed in Note 3), ethanol is now being presented as a third reportable segment. Segment information for our three reportable segments was as follows (in millions):
                                         
    Refining   Retail   Ethanol   Corporate   Total
 
Three months ended June 30, 2009:
                                       
Operating revenues from external customers
  15,693     1,969     263         17,925  
Intersegment revenues
    1,281             29             1,310  
Operating income (loss)
    (268 )     65       22       (136 )     (317 )
 
                                       
Three months ended June 30, 2008:
                                       
Operating revenues from external customers
    33,625       3,015                   36,640  
Intersegment revenues
    2,367                         2,367  
Operating income (loss)
    1,235       49             (126 )     1,158  
 
                                       
Six months ended June 30, 2009:
                                       
Operating revenues from external customers
    27,885       3,601       263             31,749  
Intersegment revenues
    2,288             29             2,317  
Operating income (loss)
    339       121       22       (292 )     190  
 
                                       
Six months ended June 30, 2008:
                                       
Operating revenues from external customers
    59,055       5,530                   64,585  
Intersegment revenues
    4,267                         4,267  
Operating income (loss)
    1,803       99             (272 )     1,630  
Total assets by reportable segment were as follows (in millions):
                     
    June 30,   December 31,
    2009   2008
 
Refining
  32,464     30,801  
Retail
    1,843       1,818  
Ethanol
    597        
Corporate
    2,317       1,798  
 
               
Total consolidated assets
  37,221     34,417  
 
               

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. EMPLOYEE BENEFIT PLANS
The components of net periodic benefit cost related to our defined benefit plans were as follows for the three and six months ended June 30, 2009 and 2008 (in millions):
                                 
                    Other Postretirement
    Pension Plans   Benefit Plans
    2009   2008   2009   2008
 
Three months ended June 30:
                               
Components of net periodic benefit cost:
                               
Service cost
  $ 26     $ 24     $ 3     $ 4  
Interest cost
    20       19       7       7  
Expected return on plan assets
    (27 )     (26 )            
Amortization of:
                               
Prior service cost (credit)
    1             (5 )     (3 )
Net loss
    2       1       1       1  
 
                               
Net periodic benefit cost
  $ 22     $ 18     $ 6     $ 9  
 
                               
 
                               
Six months ended June 30:
                               
Components of net periodic benefit cost:
                               
Service cost
  $ 52     $ 47     $ 6     $ 7  
Interest cost
    40       38       13       14  
Expected return on plan assets
    (54 )     (52 )            
Amortization of:
                               
Prior service cost (credit)
    1       1       (9 )     (5 )
Net loss
    5       1       3       2  
 
                               
Net periodic benefit cost
  $ 44     $ 35     $ 13     $ 18  
 
                               
We expect to contribute a total of approximately $70 million to our qualified pension plans during 2009. In January 2009, we contributed $50 million of this amount to our main qualified pension plan. There were no significant additional contributions made during the six months ended June 30, 2009.
13. COMMITMENTS AND CONTINGENCIES
Contingent Earn-Out Agreements
In January 2008, we made a previously accrued earn-out payment of $25 million related to the acquisition of the St. Charles Refinery, which was the final payment under that agreement. As of June 30, 2009, we have no further commitments with respect to contingent earn-out agreements. However, see Note 9 for a discussion of a contingent receivable from Alon related to a three-year earn-out agreement received in July 2008 as partial consideration for the sale of our Krotz Springs Refinery. Based on our calculations under the provisions of the agreement, we determined that $28 million was earned for the first year of this three-year agreement. Alon has calculated a different amount, and we are in the process of reconciling the different amounts. The resolution of this matter is not expected to result in a material difference.
Insurance Recoveries
During the first quarter of 2007, our McKee Refinery was shut down due to a fire originating in its propane deasphalting unit, resulting in business interruption losses for which we submitted claims to our

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
insurance carriers under our insurance policies. We reached a settlement with the insurance carriers on our claims, resulting in pre-tax income of approximately $100 million in the first quarter of 2008 that was recorded as a reduction to “cost of sales.”
TRN Refinery Commitment
On May 20, 2009, we entered into a Business Sale Agreement (Agreement) with Dow Chemical Company and certain of its affiliates (Dow) under which we agreed to purchase Dow’s 45% equity interest in Total Raffinaderij Nederland N.V. (TRN), which owns a refinery in the Netherlands, along with related businesses of TRN owned by Dow. The Agreement extends through December 31, 2009 and provides for a purchase price of $600 million plus an amount for related inventories. The closing of the transaction was conditioned upon, among other things, the expiration of a right of first refusal held by Total S.A. (Total) to purchase Dow’s equity interest in TRN or a waiver by Total of such right of first refusal. In June 2009, Total exercised its right of first refusal. To our knowledge, Total’s acquisition of Dow’s equity interest in TRN has not closed, and we and Dow have not executed a formal termination of the Agreement.
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.
Effective January 1, 2007, the Government of Aruba (GOA) enacted a turnover tax on revenues from the sale of goods produced and services rendered in Aruba. The turnover tax, which is 3% for on-island sales and services and 1% on export sales, is being assessed by the GOA on sales by our Aruba Refinery. However, due to a previous tax holiday that was granted to our Aruba Refinery by the GOA through December 31, 2010 as well as other reasons, we believe that exports by our Aruba Refinery should not be subject to this turnover tax. We commenced arbitration proceedings with the Netherlands Arbitration Institute pursuant to which we are seeking to enforce our rights under the tax holiday and other agreements related to the refinery. The arbitration hearing was held on February 3-4, 2009. We anticipate a decision sometime later this year. We have also filed protests of these assessments through proceedings in Aruba. In April 2008, we entered into an escrow agreement with the GOA and Caribbean Mercantile Bank NV (CMB), pursuant to which we agreed to deposit an amount equal to the disputed turnover tax on exports into an escrow account with CMB, pending resolution of the tax protest proceedings in Aruba. Under this escrow agreement, we are required to continue to deposit an amount equal to the disputed tax on a monthly basis until the tax dispute is resolved through the Aruba proceedings. On April 20, 2009, we were notified that the Aruban tax court overruled our protests with respect to the turnover tax assessed in January and February 2007, totaling $8 million. Under the escrow agreement, we expensed and paid $8 million, plus $1 million of interest, to the GOA in the second quarter of 2009. The tax protests for the remaining periods remain outstanding, and no expense or liability has been recognized in our consolidated financial statements with respect to these remaining periods. Amounts deposited under the escrow agreement, which totaled $111 million and $102 million as of June 30, 2009 and December 31, 2008, respectively, are reflected as “restricted cash” in our consolidated balance sheets.

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In addition to the turnover tax described above, the GOA has also asserted other tax amounts aggregating approximately $25 million related to dividends and other tax items. The GOA, through the arbitration, is also now questioning the validity of the tax holiday generally, although the GOA has not issued any formal assessment for profit tax at any time during the tax holiday period. We believe that the provisions of our tax holiday agreement exempt us from all of these taxes and, accordingly, no expense or liability has been recognized in our consolidated financial statements. We are also challenging approximately $30 million in foreign exchange payments made to the Central Bank of Aruba as payments exempted under our tax holiday, as well as other reasons. These taxes and assessments are also being addressed in the arbitration proceedings discussed above.
American Clean Energy and Security Act of 2009
On June 26, 2009, the U.S. House of Representatives narrowly approved the American Clean Energy and Security Act of 2009 (ACESA), also known as the Waxman-Markey Bill. The ACESA, if passed by the U.S. Senate, would establish a national “cap-and-trade” program beginning in 2012 to address greenhouse gas emissions and climate change. The ACESA proposes to reduce carbon dioxide and other greenhouse gas emissions by 3% below 2005 levels by 2012, 20% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by 2050. The cap-and-trade program would require businesses that emit greenhouse gases to acquire emission credits from the government, other businesses, or through an auction process. In addition, refiners would be obligated to purchase emission credits associated with the transportation fuels (gasoline, diesel, and jet fuel) sold and consumed in the United States. As a result of such a program, we could be required to purchase emission credits for greenhouse gas emissions resulting from our operations and from the fuels we sell. Although it is not possible at this time to predict the final form of the ACESA (or whether it will be passed by the U.S. Senate), any new federal restrictions on greenhouse gas emissions – including a cap-and-trade program – could result in increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have an adverse effect on our financial position, results of operations, and liquidity.
Litigation
MTBE Litigation
As of August 1, 2009, we were named as a defendant in 33 active cases alleging liability related to MTBE contamination in groundwater. The plaintiffs are generally water providers, governmental authorities, and private water companies alleging that refiners and marketers of MTBE and gasoline containing MTBE are liable for manufacturing or distributing a defective product. We have been named in these lawsuits together with many other refining industry companies. We are being sued primarily as a refiner and marketer of MTBE and gasoline containing MTBE. We do not own or operate gasoline station facilities in most of the geographic locations in which damage is alleged to have occurred. The lawsuits generally seek individual, unquantified compensatory and punitive damages, injunctive relief, and attorneys’ fees. Many of the cases are pending in federal court and are consolidated for pre-trial proceedings in the U.S. District Court for the Southern District of New York (Multi-District Litigation Docket No. 1358, In re: Methyl-Tertiary Butyl Ether Products Liability Litigation). Thirteen cases are pending in state court. We recently settled the City of New York case, which had been set for trial in June 2009. We expect that the Village of Hempstead and West Hempstead Water District cases will be set for trial in February 2010. Discovery is open in all cases. We believe that we have strong defenses to all claims and are vigorously defending the lawsuits.

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
We have recorded a loss contingency liability with respect to our MTBE litigation portfolio in accordance with FASB Statement No. 5, “Accounting for Contingencies.” However, due to the inherent uncertainty of litigation, we believe that it is reasonably possible (as defined in Statement No. 5) that we may suffer a loss with respect to one or more of the lawsuits in excess of the amount accrued. We believe that such an outcome in any one of these lawsuits would not have a material adverse effect on our results of operations or financial position. However, we believe that an adverse result in all or a substantial number of these cases could have a material effect on our results of operations and financial position. An estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.
Retail Fuel Temperature Litigation
As of August 1, 2009, we were named in 21 consumer class action lawsuits relating to fuel temperature. We have been named in these lawsuits together with several other defendants in the retail petroleum marketing business. The complaints, filed in federal courts in several states, allege that because fuel volume increases with fuel temperature, the defendants have violated state consumer protection laws by failing to adjust the volume of fuel when the fuel temperature exceeded 60 degrees Fahrenheit. The complaints seek to certify classes of retail consumers who purchased fuel in various locations. The complaints seek an order compelling the installation of temperature correction devices as well as monetary relief. The federal lawsuits are consolidated into a multi-district litigation case in the U.S. District Court for the District of Kansas (Multi-District Litigation Docket No. 1840, In re: Motor Fuel Temperature Sales Practices Litigation). Discovery has commenced. The court is expected to rule on certain class certification issues in 2009. We believe that we have several strong defenses to these lawsuits and intend to contest them. We have not recorded a loss contingency liability with respect to this matter, but due to the inherent uncertainty of litigation, we believe that it is reasonably possible (as defined in Statement No. 5) that we may suffer a loss with respect to one or more of the lawsuits. An estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.
Rosolowski
Rosolowski v. Clark Refining & Marketing, Inc., et al
., Judicial Circuit Court, Cook County, Illinois (Case No. 95-L 014703). We assumed this lawsuit in our acquisition of Premcor Inc. The lawsuit relates in part to a 1994 release to the atmosphere of spent catalyst from the now-closed Blue Island, Illinois refinery. The case was certified as a class action in 2000 with three classes, two of which received nominal or no damages, and one of which received a sizeable jury verdict. That class consisted of local residents who claimed property damage or loss of use and enjoyment of their property over a period of several years. In 2005, the jury returned a verdict for the plaintiffs of $80 million in compensatory damages and $40 million in punitive damages. However, following our motions for new trial and judgment notwithstanding the verdict (citing, among other things, misconduct by plaintiffs’ counsel and improper class certification), the trial judge in 2006 vacated the jury’s award and decertified the class. Plaintiffs appealed, and in June 2008 the state appeals court reversed the trial judge’s decision to decertify the class and set aside the judgment. Thereafter, the Illinois Supreme Court refused to hear the case and returned it to the trial court. We have submitted renewed motions for judgment notwithstanding the verdict or, alternatively, a new trial. While we do not believe that the ultimate resolution of this matter will have a material effect on our financial position or results of operations, we have recorded a loss contingency liability with respect to this matter in accordance with Statement No. 5.

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Other Litigation
We are also a party to additional claims and legal proceedings arising in the ordinary course of business. We believe that there is only a remote likelihood that future costs related to known contingent liabilities related to these legal proceedings would have a material adverse impact on our consolidated results of operations or financial position.
Asset Impairments
Under FASB Statement No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” long-lived assets must be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the long-lived assets may not be recoverable. A long-lived asset is not recoverable if its carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If a long-lived asset is not recoverable, an impairment loss is recognized in an amount by which its carrying amount exceeds its fair value, with fair value determined under Statement No. 157, generally based on discounted estimated net cash flows.
In order to test long-lived assets for recoverability, management must make estimates of projected cash flows related to the asset being evaluated, which include, but are not limited to, assumptions about the use or disposition of the asset, its estimated remaining life, and future expenditures necessary to maintain its existing service potential. In order to determine fair value, management must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected cash flows, investment rates, interest/equity rates, and growth rates, that could significantly impact the fair value of the asset being tested for impairment.
During the fourth quarter of 2008, there were severe disruptions in the capital and commodities markets that contributed to a significant decline in our common stock price, thus causing our market capitalization to decline to a level substantially below our net book value. Due to these adverse changes in market conditions during the fourth quarter of 2008, we evaluated our significant operating assets for potential impairment as of December 31, 2008, and we determined that the carrying amount of each of these assets was recoverable. The economic slowdown that began in 2008 continued throughout the first six months of 2009, thereby further reducing demand for refined products and putting significant pressure on refined product margins. Due to these economic conditions, in June 2009, we announced our plan to temporarily shut down the Aruba Refinery, which had a net book value of approximately $1.0 billion as of June 30, 2009, for at least two months as narrow heavy sour crude oil differentials currently make the refinery uneconomical to operate. The Aruba Refinery was shut down in July 2009. We are continuing to pursue potential transactions for this refinery, which may include the sale of the refinery. In June 2009, the coker unit at the Corpus Christi East Refinery was also temporarily shut down, partly due to economic reasons. As a result of these factors, we readdressed the potential impairment of all of our significant operating assets as of June 30, 2009, incorporating updated 2009 price assumptions into our estimated cash flows. Based on this analysis, we determined that the carrying amount of each of our significant operating assets continued to be recoverable as of June 30, 2009.
Also in the second quarter of 2009, due to the impact of the continuing economic slowdown on refining industry fundamentals and in an effort to conserve cash, we evaluated all of our capital projects currently in progress. As a result of this assessment, certain capital projects were permanently cancelled, resulting in the write-off of $122 million of project costs in the second quarter of 2009. We have also suspended continued construction activity on various other projects. For example, our two hydrocracker projects on the Gulf Coast, one at the St. Charles Refinery and the other at the Port Arthur Refinery, have been

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CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
suspended pending a reassessment of the demand for the additional refined product supply that would result from these projects. As of June 30, 2009, approximately $915 million of costs had been incurred on these two projects. In addition, various other projects with a total cost of approximately $430 million as of June 30, 2009 have also been suspended.
Due to the effect of the current unfavorable economic conditions on the refining industry, and our expectations of a continuation of such conditions for the near term, we will continue to monitor both our operating assets and our capital projects for potential asset impairments or project write-offs until conditions improve. Our current evaluations are focused on our Delaware City Refinery, which had a net book value of approximately $2.0 billion as of June 30, 2009. Additional assessments will be performed in conjunction with our annual strategic plan process in the third quarter of 2009. Changes in market conditions, as well as changes in assumptions used to test for recoverability and to determine fair value, could result in significant impairment charges or project write-offs in the future, thus affecting our earnings.
14. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
In conjunction with the acquisition of Premcor Inc. on September 1, 2005, Valero Energy Corporation has fully and unconditionally guaranteed the following debt of The Premcor Refining Group Inc. (PRG), a wholly owned subsidiary of Valero Energy Corporation, that was outstanding as of June 30, 2009:
   
6.75% senior notes due February 2011,
   
6.125% senior notes due May 2011,
   
6.75% senior notes due May 2014, and
   
7.5% senior notes due June 2015.
In addition, PRG has fully and unconditionally guaranteed all of the outstanding debt issued by Valero Energy Corporation.
The following condensed consolidating financial information is provided for Valero and PRG as an alternative to providing separate financial statements for PRG. The accounts for all companies reflected herein are presented using the equity method of accounting for investments in subsidiaries.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Balance Sheet as of June 30, 2009
(unaudited, in millions)
                                         
    Valero           Other Non-        
    Energy           Guarantor        
    Corporation   PRG   Subsidiaries   Eliminations   Consolidated
 
                                       
ASSETS
                                       
Current assets:
                                       
Cash and temporary cash investments
  443         1,180         1,623  
Restricted cash
    22       2       117             141  
Receivables, net
          60       4,157             4,217  
Inventories
          447       4,114             4,561  
Income taxes receivable
    5             27       (5 )     27  
Deferred income taxes
                132             132  
Prepaid expenses and other
          6       466             472  
 
                                       
Total current assets
    470       515       10,193       (5 )     11,173  
 
                                       
 
Property, plant and equipment, at cost
          6,129       23,559             29,688  
Accumulated depreciation
          (575 )     (4,829 )           (5,404 )
 
                                       
Property, plant and equipment, net
          5,554       18,730             24,284  
 
                                       
 
Intangible assets, net
                221             221  
Investment in Valero Energy affiliates
    6,194       3,052       (296 )     (8,950 )      
Long-term notes receivable from affiliates
    16,659                   (16,659 )      
Deferred income tax receivable
    1,085                   (1,085 )      
Deferred charges and other assets, net
    127       123       1,293             1,543  
 
                                       
Total assets
  24,535     9,244     30,141     (26,699 )   37,221  
 
                                       
 
                                       
LIABILITIES AND STOCKHOLDERS’ EQUITY
                                       
Current liabilities:
                                       
Current portion of debt and capital lease obligations
  33         104         137  
Accounts payable
    31       190       5,619             5,840  
Accrued expenses
    110       33       207             350  
Taxes other than income taxes
          18       539             557  
Income taxes payable
                41       (5 )     36  
Deferred income taxes
    404                         404  
 
                                       
Total current liabilities
    578       241       6,510       (5 )     7,324  
 
                                       
 
Debt and capital lease obligations, less current portion
    6,299       897       35             7,231  
 
                                       
Long-term notes payable to affiliates
          7,004       9,655       (16,659 )      
 
                                       
Deferred income taxes
          1,207       3,983       (1,085 )     4,105  
 
                                       
Other long-term liabilities
    1,251       191       712             2,154  
 
                                       
 
Stockholders’ equity:
                                       
Common stock
    7             1       (1 )     7  
Additional paid-in capital
    7,987       1,598       4,367       (5,965 )     7,987  
Treasury stock
    (6,856 )                       (6,856 )
Retained earnings
    15,384       (1,884 )     4,767       (2,883 )     15,384  
Accumulated other comprehensive income (loss)
    (115 )     (10 )     111       (101 )     (115 )
 
                                       
Total stockholders’ equity
    16,407       (296 )     9,246       (8,950 )     16,407  
 
                                       
Total liabilities and stockholders’ equity
  24,535     9,244     30,141     (26,699 )   37,221  
 
                                       

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Balance Sheet as of December 31, 2008
(in millions)
                                         
    Valero           Other Non-        
    Energy           Guarantor        
    Corporation   PRG   Subsidiaries   Eliminations   Consolidated
 
                                       
ASSETS
                                       
Current assets:
                                       
Cash and temporary cash investments
  215         725         940  
Restricted cash
    23       2       106             131  
Receivables, net
          36       2,861             2,897  
Inventories
          360       4,277             4,637  
Income taxes receivable
    76             197       (76 )     197  
Deferred income taxes
                98             98  
Prepaid expenses and other
          8       542             550  
 
                                       
Total current assets
    314       406       8,806       (76 )     9,450  
 
                                       
 
Property, plant and equipment, at cost
          6,025       22,078             28,103  
Accumulated depreciation
          (483 )     (4,407 )           (4,890 )
 
                                       
Property, plant and equipment, net
          5,542       17,671             23,213  
 
                                       
 
Intangible assets, net
                224             224  
Investment in Valero Energy affiliates
    6,300       2,718       65       (9,083 )      
Long-term notes receivable from affiliates
    15,354                   (15,354 )      
Deferred income tax receivable
    883                   (883 )      
Deferred charges and other assets, net
    121       136       1,273             1,530  
 
                                       
Total assets
  22,972     8,802     28,039     (25,396 )   34,417  
 
                                       
 
                                       
LIABILITIES AND STOCKHOLDERS’ EQUITY
                                       
Current liabilities:
                                       
Current portion of debt and capital lease obligations
  209         103         312  
Accounts payable
    43       414       3,989             4,446  
Accrued expenses
    82       34       258             374  
Taxes other than income taxes
          23       569             592  
Income taxes payable
          6       70       (76 )      
Deferred income taxes
    485                         485  
 
                                       
Total current liabilities
    819       477       4,989       (76 )     6,209  
 
                                       
 
Debt and capital lease obligations, less current portion
    5,329       899       36             6,264  
 
                                       
Long-term notes payable to affiliates
          5,966       9,388       (15,354 )      
 
                                       
Deferred income taxes
          1,200       3,846       (883 )     4,163  
 
                                       
Other long-term liabilities
    1,204       195       762             2,161  
 
                                       
 
Stockholders’ equity:
                                       
Common stock
    6             1       (1 )     6  
Additional paid-in capital
    7,190       1,598       4,349       (5,947 )     7,190  
Treasury stock
    (6,884 )                       (6,884 )
Retained earnings
    15,484       (1,523 )     4,507       (2,984 )     15,484  
Accumulated other comprehensive income (loss)
    (176 )     (10 )     161       (151 )     (176 )
 
                                       
Total stockholders’ equity
    15,620       65       9,018       (9,083 )     15,620  
 
                                       
Total liabilities and stockholders’ equity
  22,972     8,802     28,039     (25,396 )   34,417  
 
                                       

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Income for the Three Months Ended June 30, 2009
(unaudited, in millions)
                                         
    Valero           Other Non-        
    Energy           Guarantor        
      Corporation     PRG   Subsidiaries   Eliminations   Consolidated
 
                                       
Operating revenues
      3,457     17,766     (3,298 )   17,925  
 
                                       
 
                                       
Costs and expenses:
                                       
Cost of sales
          3,726       16,115       (3,298 )     16,543  
Operating expenses
          246       769             1,015  
Retail selling expenses
                171             171  
General and administrative expenses
    3       1       120             124  
Depreciation and amortization expense
          59       330             389  
 
                                       
Total costs and expenses
    3       4,032       17,505       (3,298 )     18,242  
 
                                       
 
                                       
Operating income (loss)
    (3 )     (575 )     261             (317 )
Equity in earnings (losses) of subsidiaries
    (326 )     214       (255 )     367        
Other income (expense), net
    289       (28 )     152       (437 )     (24 )
Interest and debt expense:
                                       
Incurred
    (162 )     (127 )     (266 )     437       (118 )
Capitalized
          7       29             36  
 
                                       
 
Loss before income tax expense (benefit)
    (202 )     (509 )     (79 )     367       (423 )
 
                                       
Income tax expense (benefit) (1)
    52       (254 )     33             (169 )
 
                                       
 
                                       
Net loss
  (254 )   (255 )   (112 )   367     (254 )
 
                                       
(1)   The income tax expense (benefit) reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Income for the Three Months Ended June 30, 2008
(unaudited, in millions)
                                         
    Valero           Other Non-        
    Energy           Guarantor        
      Corporation     PRG   Subsidiaries   Eliminations   Consolidated
 
                                       
Operating revenues
      8,065     36,073     (7,498 )   36,640  
 
                                       
 
                                       
Costs and expenses:
                                       
Cost of sales
          7,849       33,322       (7,498 )     33,673  
Operating expenses
          207       926             1,133  
Retail selling expenses
                190             190  
General and administrative expenses
    (2 )     1       118             117  
Depreciation and amortization expense
          60       309             369  
 
                                       
Total costs and expenses
    (2 )     8,117       34,865       (7,498 )     35,482  
 
                                       
 
                                       
Operating income (loss)
    2       (52 )     1,208             1,158  
Equity in earnings of subsidiaries
    651       137       29       (817 )      
Other income (expense), net
    281       (18 )     190       (438 )     15  
Interest and debt expense:
                                       
Incurred
    (135 )     (132 )     (278 )     438       (107 )
Capitalized
          5       19             24  
 
                                       
 
Income (loss) before income tax expense (benefit)
    799       (60 )     1,168       (817 )     1,090  
Income tax expense (benefit) (1)
    65       (89 )     380             356  
 
                                       
 
                                       
Net income
  734     29     788     (817 )   734  
 
                                       
(1)   The income tax expense (benefit) reflected in each column does not include any tax effect of the equity in earnings of subsidiaries.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Income for the Six Months Ended June 30, 2009
(unaudited, in millions)
                                         
    Valero           Other Non-        
    Energy           Guarantor        
      Corporation     PRG   Subsidiaries   Eliminations   Consolidated
 
                                       
Operating revenues
      6,191     31,470     (5,912 )   31,749  
 
                                       
 
                                       
Costs and expenses:
                                       
Cost of sales
          6,432       27,651       (5,912 )     28,171  
Operating expenses
          485       1,527             2,012  
Retail selling expenses
                340             340  
General and administrative expenses
    1       2       266             269  
Depreciation and amortization expense
          123       644             767  
 
                                       
Total costs and expenses
    1       7,042       30,428       (5,912 )     31,559  
 
                                       
 
                                       
Operating income (loss)
    (1 )     (851 )     1,042             190  
Equity in earnings (losses) of subsidiaries
    (78 )     334       (360 )     104        
Other income (expense), net
    544       (42 )     313       (840 )     (25 )
Interest and debt expense:
                                       
Incurred
    (305 )     (242 )     (530 )     840       (237 )
Capitalized
          14       62             76  
 
                                       
 
Income (loss) before income tax expense (benefit)
    160       (787 )     527       104       4  
Income tax expense (benefit) (1)
    105       (427 )     271             (51 )
 
                                       
 
                                       
Net income (loss)
  55     (360 )   256     104     55  
 
                                       
(1)   The income tax expense (benefit) reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Income for the Six Months Ended June 30, 2008
(unaudited, in millions)
                                         
    Valero           Other Non-        
    Energy           Guarantor        
      Corporation     PRG   Subsidiaries   Eliminations   Consolidated
 
                                       
Operating revenues
      15,739     63,678     (14,832 )   64,585  
 
                                       
 
                                       
Costs and expenses:
                                       
Cost of sales
          15,268       58,906       (14,832 )     59,342  
Operating expenses
          441       1,806             2,247  
Retail selling expenses
                378             378  
General and administrative expenses
    (3 )     14       241             252  
Depreciation and amortization expense
          138       598             736  
 
                                       
Total costs and expenses
    (3 )     15,861       61,929       (14,832 )     62,955  
 
                                       
 
                                       
Operating income (loss)
    3       (122 )     1,749             1,630  
Equity in earnings (losses) of subsidiaries
    787       176       (92 )     (871 )      
Other income (expense), net
    573       (26 )     382       (894 )     35  
Interest and debt expense:
                                       
Incurred
    (272 )     (280 )     (565 )     894       (223 )
Capitalized
          9       34             43  
 
                                       
 
Income (loss) before income tax expense (benefit)
    1,091       (243 )     1,508       (871 )     1,485  
Income tax expense (benefit) (1)
    96       (151 )     545             490  
 
                                       
 
                                       
Net income (loss)
  995     (92 )   963     (871 )   995  
 
                                       
(1)   The income tax expense (benefit) reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2009
(unaudited, in millions)
                                         
    Valero           Other Non-        
    Energy           Guarantor        
    Corporation   PRG   Subsidiaries   Eliminations   Consolidated
 
                                       
Net cash provided by (used in) operating activities
  (8 )   (819 )   2,234         1,407  
 
                                       
 
                                       
Cash flows from investing activities:
                                       
Capital expenditures
          (197 )     (1,154 )           (1,351 )
Deferred turnaround and catalyst costs
          (20 )     (229 )           (249 )
Acquisition of certain VeraSun Energy Corporation facilities
                (556 )           (556 )
Return of investment in Cameron Highway Oil Pipeline Company
                8             8  
Minor acquisitions
                (29 )           (29 )
Net intercompany loans
    (1,194 )                 1,194        
Other investing activities, net
                3             3  
 
                                       
Net cash used in investing activities
    (1,194 )     (217 )     (1,957 )     1,194       (2,174 )
 
                                       
 
                                       
Cash flows from financing activities:
                                       
Proceeds from the sale of common stock, net of issuance costs
    799                         799  
Non-bank debt:
                                       
Borrowings
    998                         998  
Repayments
    (209 )                       (209 )
Accounts receivable sales program:
                                       
Proceeds from sale of receivables
                500             500  
Repayments
                (500 )           (500 )
Common stock dividends
    (155 )                       (155 )
Net intercompany borrowings
          1,036       158       (1,194 )      
Other financing activities, net
    (3 )           (2 )           (5 )
 
                                       
Net cash provided by financing activities
    1,430       1,036       156       (1,194 )     1,428  
 
                                       
Effect of foreign exchange rate changes on cash
                22             22  
 
                                       
Net increase in cash and temporary cash investments
    228             455             683  
Cash and temporary cash investments at beginning of period
    215             725             940  
 
                                       
Cash and temporary cash investments at end of period
  443         1,180         1,623  
 
                                       

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VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Cash Flows for the Six Months Ended June 30, 2008
(unaudited, in millions)
                                         
    Valero           Other Non-        
    Energy           Guarantor        
    Corporation   PRG (1)   Subsidiaries (1)   Eliminations   Consolidated
 
                                       
Net cash provided by operating activities
  274     65     1,463         1,802  
 
                                       
 
                                       
Cash flows from investing activities:
                                       
Capital expenditures
          (247 )     (931 )           (1,178 )
Deferred turnaround and catalyst costs
          (50 )     (153 )           (203 )
Return of investment in Cameron Highway Oil Pipeline Company
                12             12  
Advance proceeds related to sale of assets
                17             17  
Contingent payment in connection with acquisition
                (25 )           (25 )
Investments in subsidiaries
    (215 )                 215        
Net intercompany loans
    210                   (210 )      
Minor acquisition
                (57 )           (57 )
Other investing activities, net
                14             14  
 
                                       
Net cash used in investing activities
    (5 )     (297 )     (1,123 )     5       (1,420 )
 
                                       
 
Cash flows from financing activities:
                                       
Non-bank debt repayments
    (6 )     (368 )                 (374 )
Bank credit agreements:
                                       
Borrowings
    296                         296  
Repayments
    (296 )                       (296 )
Purchase of common stock for treasury
    (700 )                       (700 )
Common stock dividends
    (143 )                       (143 )
Net intercompany borrowings (repayments)
          600       (810 )     210        
Capital contributions from parent
                215       (215 )      
Other financing activities
    24             (2 )           22  
 
                                       
Net cash provided by (used in) financing activities
    (825 )     232       (597 )     (5 )     (1,195 )
 
                                       
Effect of foreign exchange rate changes on cash
                (7 )           (7 )
 
                                       
Net decrease in cash and temporary cash investments
    (556 )           (264 )           (820 )
Cash and temporary cash investments at beginning of period
    1,414             1,050             2,464  
 
                                       
Cash and temporary cash investments at end of period
  858         786         1,644  
 
                                       
(1)   The information presented herein excludes a $918 million noncash capital contribution of property and other assets, net of certain liabilities, from PRG to Valero Refining Company–Tennessee, L.L.C. (included in “Other Non-Guarantor Subsidiaries”) on April 1, 2008.

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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 “Results of Operations – 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 and the effect of the acquisition from VeraSun Energy Corporation (VeraSun) of certain ethanol plants (the VeraSun Acquisition) on our results of operations;
 
   
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 United States, Canada, and elsewhere;
 
   
expectations regarding environmental, tax, and other regulatory initiatives; and
 
   
the effect of general economic and other conditions on refining and retail 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 consume refined products, including the United States, and in crude oil producing regions, including the Middle East and South America;
 
   
the domestic and foreign supplies of refined products such as gasoline, diesel fuel, jet fuel, home heating oil, and petrochemicals;
 
   
the domestic and foreign 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;
 
   
the actions taken by competitors, including both pricing and adjustments to refining capacity in response to market conditions;

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environmental, tax, and other regulations at the municipal, state, and federal levels and in foreign countries;
 
   
the level of foreign imports of refined products;
 
   
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;
 
   
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;
 
   
ethanol margins following the VeraSun Acquisition may be lower than expected;
 
   
earthquakes, hurricanes, tornadoes, and irregular weather, which can unforeseeably affect the price or availability of natural gas, crude oil and other feedstocks, and refined products;
 
   
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, 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 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 the results of 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
In this overview, we describe some of the primary factors that we believe affected our results of operations in the second quarter and first six months of 2009. We reported a net loss of $254 million, or $0.48 per share, for the second quarter of 2009, compared to net income of $734 million, or $1.37 per share, for the second quarter of 2008. Net income was $55 million, or $0.11 per share, for the first six months of 2009, compared to $995 million, or $1.85 per share, for the first six months of 2008. The results of operations for the first six months of 2008 included a pre-tax benefit of approximately $100 million for a business interruption insurance settlement related to a 2007 fire at our McKee Refinery.
Our profitability is substantially determined by the spread between the price of refined products and the price of crude oil, referred to as the “refined product margin.” The current economic recession has caused a decline in demand for refined products, which put pressure on refined product margins during the second quarter and first six months of 2009. This reduced demand, combined with increased inventory levels attributable in large part to new worldwide refining capacity coming online, caused a significant decline in diesel and jet fuel margins in the second quarter and first six months of 2009 compared to the corresponding periods of 2008. However, margins on other refined products were favorable in 2009 compared to 2008. Gasoline margins were strong and improved significantly in the second quarter and first six months of 2009 compared to the same periods of 2008 due to a better balance of supply and demand. In addition, lower costs of crude oil and other feedstocks significantly improved margins on certain secondary products, such as asphalt, fuel oils, and petroleum coke, during the second quarter and first six months of 2009.
Because more than 65% of our total crude oil throughput generally consists of sour crude oil and acidic sweet crude oil feedstocks that historically have been purchased at prices less than sweet crude oil, our profitability is also significantly affected by the spread between sweet crude oil and sour crude oil prices, referred to as the “sour crude oil differential.” Sour crude oil differentials for the second quarter and first six months of 2009 decreased significantly and were substantially lower than the 2008 differentials for the corresponding periods. We believe that this decline in sour crude oil differentials was partially caused by a reduction in sour crude oil production by OPEC and other producers, which reduced the supply of sour crude oil and increased the price of sour crude oils relative to sweet crude oils.
In March 2009, we issued $750 million of 10-year notes and $250 million of 30-year notes. Proceeds from these notes have been used to make $209 million of scheduled debt payments in April 2009, fund our acquisition of certain ethanol plants from VeraSun, and maintain our capital investment program.
In April and May of 2009, we acquired seven ethanol plants and a site under development from VeraSun for $477 million, plus $79 million primarily for inventory and certain other working capital. The new ethanol business reported $22 million of operating income in the second quarter of 2009, which represented only a partial quarter of operations for several of these plants.
In June 2009, we sold in a public offering 46 million shares of our common stock at a price of $18.00 per share and received proceeds, net of underwriting discounts and commissions and other issuance costs, of $799 million.

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RESULTS OF OPERATIONS
Second Quarter 2009 Compared to Second Quarter 2008
Financial Highlights
(millions of dollars, except per share amounts)
                         
    Three Months Ended June 30,
    2009 (a)   2008 (b)   Change
 
Operating revenues
  17,925     36,640     (18,715 )
 
                       
 
                       
Costs and expenses:
                       
Cost of sales
    16,543       33,673       (17,130 )
Operating expenses
    1,015       1,133       (118 )
Retail selling expenses
    171       190       (19 )
General and administrative expenses
    124       117       7  
Depreciation and amortization expense:
                       
Refining
    346       336       10  
Retail
    26       24       2  
Ethanol
    5             5  
Corporate
    12       9       3  
 
                       
Total costs and expenses
    18,242       35,482       (17,240 )
 
                       
 
                       
Operating income (loss)
    (317 )     1,158       (1,475 )
Other income (expense), net
    (24 )     15       (39 )
Interest and debt expense:
                       
Incurred
    (118 )     (107 )     (11 )
Capitalized
    36       24       12  
 
                       
 
                       
Income (loss) before income tax expense (benefit)
    (423 )     1,090       (1,513 )
Income tax expense (benefit)
    (169 )     356       (525 )
 
                       
 
                       
Net income (loss)
  $ (254 )   $ 734     $ (988 )
 
                       
 
                       
Earnings (loss) per common share – assuming dilution
  $ (0.48 )   $ 1.37     $ (1.85 )
 
                       
 
See the footnote references on page 49.

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Operating Highlights
(millions of dollars, except per barrel and per gallon amounts)
                         
    Three Months Ended June 30,
    2009   2008   Change
 
                       
Refining (b):
                       
Operating income (loss)
  (268 )   1,235     (1,503 )
Throughput margin per barrel (c)
  4.64     10.82     (6.18 )
Operating costs per barrel:
                       
Refining operating expenses
  4.30     4.53     (0.23 )
Depreciation and amortization
    1.53       1.35       0.18  
 
                       
Total operating costs per barrel
  5.83     5.88     (0.05 )
 
                       
 
                       
Throughput volumes (thousand barrels per day):
                       
Feedstocks:
                       
Heavy sour crude
    451       593       (142 )
Medium/light sour crude
    582       715       (133 )
Acidic sweet crude
    104       80       24  
Sweet crude
    616       658       (42 )
Residuals
    248       253       (5 )
Other feedstocks
    186       128       58  
 
                       
Total feedstocks
    2,187       2,427       (240 )
Blendstocks and other
    302       319       (17 )
 
                       
Total throughput volumes
    2,489       2,746       (257 )
 
                       
 
                       
Yields (thousand barrels per day):
                       
Gasolines and blendstocks
    1,196       1,232       (36 )
Distillates
    793       982       (189 )
Petrochemicals
    70       77       (7 )
Other products (d)
    426       446       (20 )
 
                       
Total yields
    2,485       2,737       (252 )
 
                       
 
                       
Retail – U.S.:
                       
Operating income
  36     25     11  
Company-operated fuel sites (average)
    1,001       949       52  
Fuel volumes (gallons per day per site)
    5,119       5,104       15  
Fuel margin per gallon
  0.125     0.129     (0.004 )
Merchandise sales
  307     282     25  
Merchandise margin (percentage of sales)
    28.6 %     29.8 %     (1.2 )%
Margin on miscellaneous sales
  21     22     (1 )
Retail selling expenses
  115     121     (6 )
Depreciation and amortization expense
  18     16     2  
 
                       
Retail – Canada:
                       
Operating income
  29     24     5  
Fuel volumes (thousand gallons per day)
    3,093       3,103       (10 )
Fuel margin per gallon
  0.253     0.270     (0.017 )
Merchandise sales
  49     54     (5 )
Merchandise margin (percentage of sales)
    29.2 %     28.6 %     0.6 %
Margin on miscellaneous sales
  7     10     (3 )
Retail selling expenses
  56     69     (13 )
Depreciation and amortization expense
  8     8      
 
See the footnote references on page 49.

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Operating Highlights (continued)
(millions of dollars, except per gallon amounts)
                         
    Three Months Ended June 30,
    2009   2008   Change
 
                       
Ethanol (a):
                       
Operating income
  22       N/A     22  
Ethanol production (thousand gallons per day)
    1,547       N/A       1,547  
Gross margin per gallon of ethanol production
  0.49       N/A     0.49  
Operating costs per gallon of ethanol production:
                       
Ethanol operating expenses
  0.30       N/A     0.30  
Depreciation and amortization
    0.03       N/A       0.03  
 
                       
Total operating costs per gallon of ethanol production
  0.33       N/A     0.33  
 
                       
 
See the footnote references on page 49.

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Refining Operating Highlights by Region (e)
(millions of dollars, except per barrel amounts)
                         
    Three Months Ended June 30,
    2009   2008   Change
 
Gulf Coast (b):
                       
Operating income (loss)
  (176 )   1,043     (1,219 )
Throughput volumes (thousand barrels per day)
    1,395       1,495       (100 )
Throughput margin per barrel (c)
  3.94     13.25     (9.31 )
Operating costs per barrel:
                       
Refining operating expenses
  3.92     4.34     (0.42 )
Depreciation and amortization
    1.41       1.24       0.17  
 
                       
Total operating costs per barrel
  5.33     5.58     (0.25 )
 
                       
 
                       
Mid-Continent:
                       
Operating income
  18     103     (85 )
Throughput volumes (thousand barrels per day)
    370       439       (69 )
Throughput margin per barrel (c)
  6.03     7.85     (1.82 )
Operating costs per barrel:
                       
Refining operating expenses
  3.76     3.99     (0.23 )
Depreciation and amortization
    1.72       1.27       0.45  
 
                       
Total operating costs per barrel
  5.48     5.26     0.22  
 
                       
 
                       
Northeast:
                       
Operating loss
  (169 )   (35 )   (134 )
Throughput volumes (thousand barrels per day)
    440       527       (87 )
Throughput margin per barrel (c)
  2.88     5.81     (2.93 )
Operating costs per barrel:
                       
Refining operating expenses
  5.39     5.06     0.33  
Depreciation and amortization
    1.71       1.49       0.22  
 
                       
Total operating costs per barrel
  7.10     6.55     0.55  
 
                       
 
                       
West Coast:
                       
Operating income
  59     124     (65 )
Throughput volumes (thousand barrels per day)
    284       285       (1 )
Throughput margin per barrel (c)
  9.03     11.92     (2.89 )
Operating costs per barrel:
                       
Refining operating expenses
  5.15     5.41     (0.26 )
Depreciation and amortization
    1.61       1.73       (0.12 )
 
                       
Total operating costs per barrel
  6.76     7.14     (0.38 )
 
                       
 
See the footnote references on page 49.

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Average Market Reference Prices and Differentials (f)
(dollars per barrel)
                         
    Three Months Ended June 30,
    2009   2008   Change
 
Feedstocks:
                       
West Texas Intermediate (WTI) crude oil
  59.54     123.98     (64.44 )
WTI less sour crude oil at U.S. Gulf Coast (g)
    0.33       5.70       (5.37 )
WTI less Mars crude oil
    2.19       6.96       (4.77 )
WTI less Maya crude oil
    4.57       20.99       (16.42 )
 
                       
Products:
                       
U.S. Gulf Coast:
                       
Conventional 87 gasoline less WTI
    10.57       6.60       3.97  
No. 2 fuel oil less WTI
    3.84       23.03       (19.19 )
Ultra-low-sulfur diesel less WTI
    6.16       28.85       (22.69 )
Propylene less WTI
    (10.89 )     (6.77 )     (4.12 )
U.S. Mid-Continent:
                       
Conventional 87 gasoline less WTI
    10.58       5.89       4.69  
Low-sulfur diesel less WTI
    6.24       28.84       (22.60 )
U.S. Northeast:
                       
Conventional 87 gasoline less WTI
    9.85       4.34       5.51  
No. 2 fuel oil less WTI
    4.69       24.94       (20.25 )
Lube oils less WTI
    25.64       33.65       (8.01 )
U.S. West Coast:
                       
CARBOB 87 gasoline less WTI
    18.07       16.08       1.99  
CARB diesel less WTI
    7.92       30.83       (22.91 )
 
The following notes relate to references on pages 45 through 49.
  (a)  
The information presented for the three months ended June 30, 2009 includes the operations related to the acquisition of certain ethanol plants from VeraSun. Ethanol plants located in Charles City, Fort Dodge, and Hartley, Iowa; Aurora, South Dakota; and Welcome, Minnesota were purchased on April 1, 2009, and ethanol plants in Albert City, Iowa and Albion, Nebraska were purchased on April 9, 2009 and May 8, 2009, respectively. The ethanol production volumes reflected for the three months ended June 30, 2009 are based on 91 calendar days rather than the actual daily production, which varied by facility.
  (b)  
Effective July 1, 2008, we sold our Krotz Springs Refinery to Alon Refining Krotz Springs, Inc. (Alon), a subsidiary of Alon USA Energy, Inc. The nature and significance of our post-closing participation in an offtake agreement with Alon represents a continuation of activities with the Krotz Springs Refinery for accounting purposes, and as such the results of operations related to the Krotz Springs Refinery have not been presented as discontinued operations, and all refining operating highlights, both consolidated and for the Gulf Coast region, include the Krotz Springs Refinery for the three months ended June 30, 2008.
  (c)  
Throughput margin per barrel represents operating revenues less cost of sales divided by throughput volumes.
  (d)  
Other products primarily include gas oils, No. 6 fuel oil, petroleum coke, and asphalt.
  (e)  
The regions reflected herein contain the following refineries: the Gulf Coast refining region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, Krotz Springs (for the three months ended June 30, 2008), St. Charles, Aruba, and Port Arthur Refineries; the Mid-Continent refining region includes the McKee, Ardmore, and Memphis Refineries; the Northeast refining region includes the Quebec City, Paulsboro, and Delaware City Refineries; and the West Coast refining region includes the Benicia and Wilmington Refineries.
  (f)  
The average market reference prices and differentials, with the exception of the propylene and lube oil differentials, are based on posted prices from Platts Oilgram. The propylene differential is based on posted propylene prices in Chemical Market Associates, Inc. and the lube oil differential is based on Exxon Mobil Corporation postings provided by Independent Commodity Information Services – London Oil Reports. The average market reference prices and differentials are presented to provide users of the consolidated financial statements with economic indicators that significantly affect our operations and profitability.
  (g)  
The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab Light posted prices.

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General
Operating revenues decreased 51% for the second quarter of 2009 compared to the second quarter of 2008 primarily as a result of lower refined product prices between the two periods. Operating income declined $1.5 billion and net income decreased $1.0 billion for the three months ended June 30, 2009 compared to amounts reported for the three months ended June 30, 2008 primarily due to a $1.5 billion decrease in refining segment operating income discussed below.
Refining
Results of operations of our refining segment decreased from operating income of $1.2 billion for the second quarter of 2008 to an operating loss of $268 million for the second quarter of 2009, resulting from a 57% decrease in throughput margin per barrel and a 9% decline in throughput volumes, partially offset by a 10% decrease in refining operating expenses (including depreciation and amortization expense).
Total refining throughput margins for the second quarter of 2009 compared to the second quarter of 2008 were impacted by the following factors:
   
Distillate margins in the second quarter of 2009 decreased significantly in all of our refining regions from the high margins in the second quarter of 2008. The decrease in distillate margins was primarily due to reduced demand attributable to the global slowdown in economic activity, combined with an increase in inventory levels resulting largely from new worldwide refining capacity.
   
Sour crude oil feedstock differentials to WTI crude oil during the second quarter of 2009 declined significantly compared to the differentials in the second quarter of 2008. These unfavorable sour crude oil differentials were attributable mainly to reduced production of sour crude oil by OPEC and other producers. The sour crude oil differentials were also affected by high relative prices for residual fuel oil as reduced worldwide demand for residual fuel oil was more than offset by lower production resulting from reduced refinery throughput due to lower refined product demand.
   
Gasoline margins were strong in all of our refining regions in the second quarter of 2009, and improved significantly from the second quarter of 2008. The improvement in gasoline margins for the second quarter of 2009 was primarily due to a better balance of supply and demand. Although demand for gasoline decreased slightly during the period, lower production and lower imports resulted in inventories similar to historical levels.
   
Margins on various secondary refined products such as asphalt, fuel oils, and petroleum coke improved significantly from the second quarter of 2008 to the second quarter of 2009 as prices for these products did not decrease in proportion to the large decrease in the costs of the feedstocks used to produce them.
   
Throughput volumes decreased 257,000 barrels per day during the second quarter of 2009 compared to the second quarter of 2008 primarily due to (i) unplanned downtime at our Delaware City and St. Charles Refineries, (ii) the sale of our Krotz Springs Refinery in July 2008, and (iii) economic decisions to reduce throughput in certain of our refineries as a result of unfavorable market fundamentals.
Refining operating expenses, excluding depreciation and amortization expense, were 14% lower for the quarter ended June 30, 2009 compared to the quarter ended June 30, 2008 primarily due to a significant decrease in energy costs, a reduction in sales and use taxes, and $20 million of operating expenses in the second quarter of 2008 related to the Krotz Springs Refinery, which was sold effective July 1, 2008, partially offset by expenses related to the cancellation of certain capital projects. Refining depreciation and amortization expense increased 3% from the second quarter of 2008 to the second quarter of 2009 primarily due to the completion of new capital projects.

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Retail
Retail operating income was $65 million for the quarter ended June 30, 2009 compared to $49 million for the quarter ended June 30, 2008. This 33% increase was primarily due to increased in-store sales and lower selling expenses in our U.S. retail operations.
Ethanol
Ethanol operating income was $22 million for the quarter ended June 30, 2009, which represents the operations of the seven ethanol plants acquired in the VeraSun Acquisition, as described in Note 3 of Condensed Notes to Consolidated Financial Statements.
Corporate Expenses and Other
General and administrative expenses, including depreciation and amortization expense, increased $10 million from the second quarter of 2008 to the second quarter of 2009 primarily due to costs associated with the VeraSun Acquisition.
“Other income (expense), net” for the second quarter of 2009 decreased from the second quarter of 2008 due mainly to a $34 million net loss resulting from fair value adjustments related to the Alon earn-out agreement and associated derivative instruments in 2009, as discussed in Notes 9 and 10 of Condensed Notes to Consolidated Financial Statements.
Income tax expense decreased $525 million from $356 million of expense in the second quarter of 2008 to a $169 million benefit in the second quarter of 2009 mainly as a result of lower operating income.

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Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008
Financial Highlights
(millions of dollars, except per share amounts)
                         
    Six Months Ended June 30,
    2009 (a)   2008 (b)   Change
 
Operating revenues
  $ 31,749     $ 64,585     $ (32,836 )
 
                       
 
                       
Costs and expenses:
                       
Cost of sales
    28,171       59,342       (31,171 )
Operating expenses
    2,012       2,247       (235 )
Retail selling expenses
    340       378       (38 )
General and administrative expenses
    269       252       17  
Depreciation and amortization expense:
                       
Refining
    690       667       23  
Retail
    49       49        
Ethanol
    5             5  
Corporate
    23       20       3  
 
                       
Total costs and expenses
    31,559       62,955       (31,396 )
 
                       
 
                       
Operating income
    190       1,630       (1,440 )
Other income (expense), net
    (25 )     35       (60 )
Interest and debt expense:
                       
Incurred
    (237 )     (223 )     (14 )
Capitalized
    76       43       33  
 
                       
 
                       
Income before income tax expense (benefit)
    4       1,485       (1,481 )
Income tax expense (benefit)
    (51 )     490       (541 )
 
                       
 
                       
Net income
  $ 55     $ 995     $ (940 )
 
                       
 
                       
Earnings per common share – assuming dilution
  $ 0.11     $ 1.85     $ (1.74 )
 
                       
 
See the footnote references on page 56.

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Table of Contents

Operating Highlights
(millions of dollars, except per barrel and per gallon amounts)
                                         
    Six Months Ended June 30,
    2009   2008   Change
 
                       
Refining (b):
                       
Operating income
  339     1,803     (1,464 )
Throughput margin per barrel (c)
  6.69     9.68     (2.99 )
Operating costs per barrel:
                       
Refining operating expenses
  4.39     4.61     (0.22 )
Depreciation and amortization
    1.54       1.37       0.17  
 
                       
Total operating costs per barrel
  5.93     5.98     (0.05 )
 
                       
 
                       
Throughput volumes (thousand barrels per day):
                       
Feedstocks:
                       
Heavy sour crude
    511       587       (76 )
Medium/light sour crude
    601       685       (84 )
Acidic sweet crude
    108       77       31  
Sweet crude
    589       643       (54 )
Residuals
    184       223       (39 )
Other feedstocks
    178       144       34  
 
                       
Total feedstocks
    2,171       2,359       (188 )
Blendstocks and other
    307       318       (11 )
 
                       
Total throughput volumes
    2,478       2,677       (199 )
 
                       
 
                       
Yields (thousand barrels per day):
                       
Gasolines and blendstocks
    1,160       1,228       (68 )
Distillates
    812       927       (115 )
Petrochemicals
    65       77       (12 )
Other products (d)
    434       442       (8 )
 
                       
Total yields
    2,471       2,674       (203 )
 
                       
 
                       
Retail – U.S.:
                       
Operating income
  61     39     22  
Company-operated fuel sites (average)
    1,003       949       54  
Fuel volumes (gallons per day per site)
    5,052       5,023       29  
Fuel margin per gallon
  0.121     0.121      
Merchandise sales
  573     527     46  
Merchandise margin (percentage of sales)
    29.5 %     30.1 %     (0.6 )%
Margin on miscellaneous sales
  44     50     (6 )
Retail selling expenses
  229     241     (12 )
Depreciation and amortization expense
  35     33     2  
 
                       
Retail – Canada:
                       
Operating income
  60     60      
Fuel volumes (thousand gallons per day)
    3,176       3,191       (15 )
Fuel margin per gallon
  0.252     0.286     (0.034 )
Merchandise sales
  88     100     (12 )
Merchandise margin (percentage of sales)
    29.5 %     28.5 %     1.0 %
Margin on miscellaneous sales
  15     19     (4 )
Retail selling expenses
  111     137     (26 )
Depreciation and amortization expense
  14     16     (2 )
 
See the footnote references on page 56.

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Table of Contents

Operating Highlights (continued)
(millions of dollars, except per gallon amounts)
                         
    Six Months Ended June 30,
    2009   2008   Change
 
                       
Ethanol (a):
                       
Operating income
  22       N/A     22  
Ethanol production (thousand gallons per day)
    778       N/A       778  
Gross margin per gallon of ethanol production
  0.49       N/A     0.49  
Operating costs per gallon of ethanol production:
                       
Ethanol operating expenses
  0.30       N/A     0.30  
Depreciation and amortization
    0.03       N/A       0.03  
 
                       
Total operating costs per gallon of ethanol production
  0.33       N/A     0.33  
 
                       
 
See the footnote references on page 56.

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Table of Contents

Refining Operating Highlights by Region (e)
(millions of dollars, except per barrel amounts)
                         
    Six Months Ended June 30,
    2009   2008   Change
 
                       
Gulf Coast (b):
                       
Operating income (loss)
  $ (7 )   1,480     $ (1,487 )
Throughput volumes (thousand barrels per day)
    1,355       1,437       (82 )
Throughput margin per barrel (c)
  5.48     11.46     $ (5.98 )
Operating costs per barrel:
                       
Refining operating expenses
  4.05     4.52     $ (0.47 )
Depreciation and amortization
    1.46       1.28       0.18  
 
                       
Total operating costs per barrel
  5.51     5.80     $ (0.29 )
 
                       
 
                       
Mid-Continent:
                       
Operating income
  190     218     $ (28 )
Throughput volumes (thousand barrels per day)
    385       426       (41 )
Throughput margin per barrel (c)
  8.07     8.28     $ (0.21 )
Operating costs per barrel:
                       
Refining operating expenses
  3.75     4.16     $ (0.41 )
Depreciation and amortization
    1.59       1.30       0.29  
 
                       
Total operating costs per barrel
  5.34     5.46     $ (0.12 )
 
                       
 
                       
Northeast:
                       
Operating loss
  $ (88 )   $ (30 )   $ (58 )
Throughput volumes (thousand barrels per day)
    458       541       (83 )
Throughput margin per barrel (c)
  6.06     5.91     0.15  
Operating costs per barrel:
                       
Refining operating expenses
  5.48     4.77     0.71  
Depreciation and amortization
    1.64       1.45       0.19  
 
                       
Total operating costs per barrel
  7.12     6.22     0.90  
 
                       
 
                       
West Coast:
                       
Operating income
  244     135     109  
Throughput volumes (thousand barrels per day)
    280       273       7  
Throughput margin per barrel (c)
  11.66     9.99     1.67  
Operating costs per barrel:
                       
Refining operating expenses
  5.12     5.48     $ (0.36 )
Depreciation and amortization
    1.73       1.80       (0.07 )
 
                       
Total operating costs per barrel
  6.85     7.28     $ (0.43 )
 
                       
 
See the footnote references on page 56.

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Average Market Reference Prices and Differentials (f)
(dollars per barrel)
                         
    Six Months Ended June 30,
    2009   2008   Change
 
                       
Feedstocks:
                       
WTI crude oil
  $ 51.26     $ 110.96     $ (59.70 )
WTI less sour crude oil at U.S. Gulf Coast (g)
    1.02       5.77       (4.75 )
WTI less Mars crude oil
    0.70       6.97       (6.27 )
WTI less Maya crude oil
    4.51       18.90       (14.39 )
 
                       
Products:
                       
U.S. Gulf Coast:
                       
Conventional 87 gasoline less WTI
    9.36       5.42       3.94  
No. 2 fuel oil less WTI
    7.34       19.11       (11.77 )
Ultra-low-sulfur diesel less WTI
    9.38       24.61       (15.23 )
Propylene less WTI
    (8.69 )     (3.77 )     (4.92 )
U.S. Mid-Continent:
                       
Conventional 87 gasoline less WTI
    9.58       5.43       4.15  
Low-sulfur diesel less WTI
    8.94       24.88       (15.94 )
U.S. Northeast:
                       
Conventional 87 gasoline less WTI
    8.99       3.70       5.29  
No. 2 fuel oil less WTI
    9.06       21.35       (12.29 )
Lube oils less WTI
    46.37       32.97       13.40  
U.S. West Coast:
                       
CARBOB 87 gasoline less WTI
    18.60       12.56       6.04  
CARB diesel less WTI
    10.81       25.39       (14.58 )
 
   The following notes relate to references on pages 52 through 56.
   (a)
 
The information presented for the six months ended June 30, 2009 includes the operations related to the acquisition of certain ethanol plants from VeraSun. Ethanol plants located in Charles City, Fort Dodge, and Hartley, Iowa; Aurora, South Dakota; and Welcome, Minnesota were purchased on April 1, 2009, and ethanol plants in Albert City, Iowa and Albion, Nebraska were purchased on April 9, 2009 and May 8, 2009, respectively. The ethanol production volumes reflected for the six months ended June 30, 2009 are based on 181 calendar days rather than the actual daily production, which varied by facility.
   (b)
 
Effective July 1, 2008, we sold our Krotz Springs Refinery to Alon. The nature and significance of our post-closing participation in an offtake agreement with Alon represents a continuation of activities with the Krotz Springs Refinery for accounting purposes, and as such the results of operations related to the Krotz Springs Refinery have not been presented as discontinued operations, and all refining operating highlights, both consolidated and for the Gulf Coast region, include the Krotz Springs Refinery for the six months ended June 30, 2008.
   (c)
 
Throughput margin per barrel represents operating revenues less cost of sales divided by throughput volumes.
   (d)
 
Other products primarily include gas oils, No. 6 fuel oil, petroleum coke, and asphalt.
   (e)
 
The regions reflected herein contain the following refineries: the Gulf Coast refining region includes the Corpus Christi East, Corpus Christi West, Texas City, Houston, Three Rivers, Krotz Springs (for the six months ended June 30, 2008), St. Charles, Aruba, and Port Arthur Refineries; the Mid-Continent refining region includes the McKee, Ardmore, and Memphis Refineries; the Northeast refining region includes the Quebec City, Paulsboro, and Delaware City Refineries; and the West Coast refining region includes the Benicia and Wilmington Refineries.
   (f)
 
The average market reference prices and differentials, with the exception of the propylene and lube oil differentials, are based on posted prices from Platts Oilgram. The propylene differential is based on posted propylene prices in Chemical Market Associates, Inc. and the lube oil differential is based on Exxon Mobil Corporation postings provided by Independent Commodity Information Services – London Oil Reports. The average market reference prices and differentials are presented to provide users of the consolidated financial statements with economic indicators that significantly affect our operations and profitability.
   (g)
 
The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab Light posted prices.

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General
Operating revenues decreased 51% for the first six months of 2009 compared to the first six months of 2008 primarily as a result of lower refined product prices between the two periods. Operating income of $190 million and net income of $55 million for the six months ended June 30, 2009 decreased 88% and 94%, respectively, from the corresponding amounts in the first six months of 2008 primarily due to a $1.5 billion decrease in refining segment operating income discussed below.
Refining
Operating income for our refining segment decreased from $1.8 billion for the first six months of 2008 to $339 million for the first six months of 2009, resulting from a 31% decrease in throughput margin per barrel and a 7% decline in throughput volumes, partially offset by a 9% decrease in refining operating expenses (including depreciation and amortization expense).
Total refining throughput margins for the first six months of 2009 compared to the first six months of 2008 were impacted by the following factors:
   
Distillate margins in the first six months of 2009 decreased significantly in all of our refining regions from the high margins in the first six months of 2008. The decrease in distillate margins was primarily due to increased inventory levels and reduced demand attributable to the global slowdown in economic activity.
 
   
Sour crude oil feedstock differentials to WTI crude oil during the first six months of 2009 declined significantly compared to the differentials in the first six months of 2008. These unfavorable sour crude oil differentials were attributable mainly to reduced production of sour crude oil by OPEC and other producers. The sour crude oil differentials were also affected by high relative prices for residual fuel oil as reduced worldwide demand for residual fuel oil was more than offset by lower production resulting from reduced refinery throughput due to lower refined product demand.
 
   
Gasoline margins increased in all of our refining regions in the first six months of 2009 compared to the first six months of 2008. The improvement in gasoline margins for the first six months of 2009 was primarily due to a better balance of supply and demand. Although demand for gasoline decreased slightly during the period, lower production and lower imports resulted in inventories similar to historical levels.
 
   
Margins on various secondary refined products such as asphalt, fuel oils, and petroleum coke improved significantly from the first six months of 2008 to the first six months of 2009 as prices for these products did not decrease in proportion to the large decrease in the costs of the feedstocks used to produce them.
 
   
Throughput margin for the first six months of 2008 included approximately $100 million related to the McKee Refinery business interruption insurance settlement discussed in Note 13 of Condensed Notes to Consolidated Financial Statements.
 
   
Throughput volumes decreased 199,000 barrels per day during the first six months of 2009 compared to the first six months of 2008 primarily due to (i) unplanned downtime at our Delaware City and St. Charles Refineries, (ii) planned downtime for maintenance at our Texas City, St. Charles, and Corpus Christi Refineries, (iii) the sale of our Krotz Springs Refinery in July 2008, and (iv) economic decisions to reduce throughput in certain of our refineries as a result of unfavorable market fundamentals.
Refining operating expenses, excluding depreciation and amortization expense, were 12% lower for the six months ended June 30, 2009 compared to the six months ended June 30, 2008 primarily due to a decrease in energy costs, a reduction in sales and use taxes, and $43 million of operating expenses in the

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first six months of 2008 related to the Krotz Springs Refinery, which was sold effective July 1, 2008, partially offset by expenses related to the cancellation of certain capital projects. Refining depreciation and amortization expense increased 3% from the first six months of 2008 to the first six months of 2009 primarily due to the completion of new capital projects and increased turnaround and catalyst amortization.
Retail
Retail operating income was $121 million for the six months ended June 30, 2009 compared to $99 million for the six months ended June 30, 2008. This 22% increase was primarily due to increased in-store sales and lower selling expenses in our U.S. retail operations.
Ethanol
Ethanol operating income was $22 million for the six months ended June 30, 2009, which represents the operations of the seven ethanol plants acquired in the VeraSun Acquisition subsequent to their acquisition in the second quarter of 2009, as described in Note 3 of Condensed Notes to Consolidated Financial Statements.
Corporate Expenses and Other
General and administrative expenses, including depreciation and amortization expense, increased $20 million from the first six months of 2008 to the first six months of 2009 due mainly to an increase in severance expenses and costs associated with the VeraSun Acquisition.
“Other income (expense), net” for the first six months of 2009 decreased from the first six months of 2008 primarily due to a $38 million net loss resulting from fair value adjustments related to the Alon earn-out agreement and associated derivative instruments in 2009 (as discussed in Notes 9 and 10 of Condensed Notes to Consolidated Financial Statements), reduced interest income resulting from lower cash balances and interest rates, and the nonrecurrence of a $14 million gain recognized in the first six months of 2008 on the redemption of our 9.5% senior notes as discussed in Note 5 of Condensed Notes to Consolidated Financial Statements.
Interest and debt expense decreased from the first six months of 2008 to the first six months of 2009 due mainly to an increase in capitalized interest resulting from a higher balance of capital projects under construction, partially offset by interest incurred on $1 billion of debt issued in March 2009.
Income tax expense decreased $541 million from $490 million of expense for the first six months of 2008 to a $51 million benefit for the first six months of 2009 mainly as a result of lower operating income.
OUTLOOK
The current global economic slowdown and rising unemployment are expected to continue to unfavorably impact demand for refined products in the near term. This reduced demand, combined with an increase in global refined product inventories resulting from new refineries coming online, is expected to continue to put significant pressure on refined product margins. In addition, low demand for refined products is expected to result in a continuing reduction in overall crude oil production by OPEC, which will reduce the supply of sour crude oil and continue to put pressure on the differentials between sour and sweet crude oil prices. Pressure on refined product margins and sour crude oil differentials is expected to continue until the economy begins to recover, at which time demand for refined products and sour crude oil production are expected to increase.

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Until the economy recovers, we expect that the current low refined product margins and sour crude oil differentials will result in production constraints or refinery shutdowns in the refining industry. In July, we temporarily shut down our Aruba Refinery, and in June, we temporarily shut down one of our units at our Corpus Christi East Refinery, both due to poor economics resulting from the current unfavorable industry fundamentals. We are currently monitoring, and will continue to monitor, all of our other refineries to assess whether complete or partial shutdown of certain of those facilities is appropriate until conditions improve. We expect refined product margins and sour crude oil differentials for the third quarter of 2009 to be similar to those in the second quarter, which could result in a loss in the third quarter. In addition, we believe that the fourth quarter of 2009 could continue to be challenging for the refining industry and our company in light of the current economic environment.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows for the Six Months Ended June 30, 2009 and 2008
Net cash provided by operating activities for the six months ended June 30, 2009 was $1.4 billion compared to $1.8 billion for the six months ended June 30, 2008. The decrease in cash generated from operating activities was primarily due to the decrease in operating income discussed above under “Results of Operations,” partially offset by an approximate $800 million favorable change in the amount of income tax payments and refunds between the two periods. Changes in cash provided by or used for working capital during the first six months of 2009 and 2008 are shown in Note 8 of Condensed Notes to Consolidated Financial Statements. Both receivables and accounts payable increased for the first six months of 2009 due mainly to a significant increase in gasoline, distillate, and crude oil prices at June 30, 2009 compared to such prices at the end of 2008.
The net cash generated from operating activities during the first six months of 2009, combined with $998 million of proceeds from the issuance of $1 billion of notes in March 2009 as discussed in Note 5 of Condensed Notes to Consolidated Financial Statements and $799 million of net proceeds from the issuance of 46 million shares of common stock in June 2009 as discussed in Note 6 of Condensed Notes to Consolidated Financial Statements, were used mainly to:
    fund $1.6 billion of capital expenditures and deferred turnaround and catalyst costs;
 
    fund the VeraSun Acquisition for $556 million;
 
    make scheduled long-term note repayments of $209 million;
 
    pay common stock dividends of $155 million;
 
    fund a $29 million acquisition of two pipelines; and
 
    increase available cash on hand by $683 million.
The net cash generated from operating activities during the first six months of 2008, combined with $820 million of available cash on hand, were used mainly to:
    fund $1.4 billion of capital expenditures and deferred turnaround and catalyst costs;
 
    make an early redemption of our 9.5% senior notes for $367 million and scheduled long-term note repayments of $7 million;
 
    purchase 12.6 million shares of our common stock at a cost of $700 million;
 
    fund a $25 million contingent earn-out payment in connection with the acquisition of the St. Charles Refinery and a $57 million acquisition primarily of an interest in a refined product pipeline; and
 
    pay common stock dividends of $143 million.

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Capital Investments
During the six months ended June 30, 2009, we expended $1.4 billion for capital expenditures and $249 million for deferred turnaround and catalyst costs. Capital expenditures for the six months ended June 30, 2009 included $189 million of costs related to environmental projects.
For 2009, we expect to incur approximately $2.5 billion for capital investments, including approximately $2.1 billion for capital expenditures (approximately $500 million of which is for environmental projects) and approximately $440 million for deferred turnaround and catalyst costs. The capital expenditure estimate excludes expenditures related to strategic acquisitions. We continuously evaluate our capital budget and make changes as economic conditions warrant.
In the second quarter of 2009, we acquired seven ethanol plants and a site under development from VeraSun for $477 million, plus $79 million primarily for inventory and certain other working capital.
Contractual Obligations
As of June 30, 2009, our contractual obligations included debt, capital lease obligations, operating leases, purchase obligations, and other long-term liabilities.
On April 1, 2009, we made scheduled debt repayments of $200 million related to our 3.5% notes and $9 million related to our 5.125% Series 1997D industrial revenue bonds.
In March 2009, we issued $750 million of 9.375% notes due March 15, 2019 and $250 million of 10.5% notes due March 15, 2039. Proceeds from the issuance of these notes totaled approximately $998 million, before deducting underwriting discounts and other issuance costs of $8 million.
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 2009 to extend the maturity date to June 2010. As of December 31, 2008, the amount of eligible receivables sold to the third-party entities and financial institutions was $100 million, which was repaid in February 2009. In March 2009, we sold $100 million of eligible receivables to the third-party entities and financial institutions. In April 2009, we sold an additional $400 million of eligible receivables under this program, which we repaid in June 2009. As of June 30, 2009, the amount of eligible receivables sold to the third-party entities and financial institutions was $100 million. Proceeds from the sale of receivables under this facility are reflected as debt in our consolidated balance sheets.
Under the indenture related to our $100 million of 6.75% senior notes with a maturity date of October 15, 2037, on July 31, 2009, we notified the holders of such notes of our obligation to purchase any of those notes for which a written notice of purchase (purchase notice) is received from the holders prior to September 15, 2009. Any notes for which a purchase notice is received will be purchased at 100% of their principal amount plus accrued and unpaid interest to October 15, 2009, the date of payment of the purchase price.
On May 20, 2009, we entered into a Business Sale Agreement (Agreement) with Dow Chemical Company and certain of its affiliates (Dow) under which we agreed to purchase Dow’s 45% equity interest in Total Raffinaderij Nederland N.V. (TRN), which owns a refinery in the Netherlands, along with related businesses of TRN owned by Dow. The Agreement extends through December 31, 2009 and provides for a purchase price of $600 million plus an amount for related inventories. The closing of the transaction was conditioned upon, among other things, the expiration of a right of first refusal held by Total S.A. (Total) to purchase Dow’s equity interest in TRN or a waiver by Total of such right of first refusal. In June 2009, Total exercised its right of first refusal. To our knowledge, Total’s acquisition of

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Dow’s equity interest in TRN has not closed, and we and Dow have not executed a formal termination of the Agreement.
Other than the TRN Refinery commitment discussed above, during the six months ended June 30, 2009, we had no material changes outside the ordinary course of our business in capital lease obligations, operating leases, purchase obligations, or other long-term liabilities.
Our agreements do not have rating agency triggers that would automatically require us to post additional collateral. However, in the event of certain downgrades of our senior unsecured debt to below investment grade ratings by Moody’s Investors Service and Standard & Poor’s Ratings Services, the cost of borrowings under some of our bank credit facilities and other arrangements would increase. As of June 30, 2009, all of our ratings on our senior unsecured debt are at or above investment grade level as follows:
         
   
Rating Agency
 
Rating
                       
 
 
 
Standard & Poor’s Ratings Services
  BBB (stable outlook)  
 
 
Moody’s Investors Service
  Baa2 (stable outlook)  
 
 
Fitch Ratings
  BBB (stable outlook)  
We cannot provide assurance that these ratings will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell, or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing and the cost of such financings.
Other Commercial Commitments
As of June 30, 2009, our committed lines of credit were as follows:
                 
    Borrowing    
   
Capacity
 
Expiration
 
Letter of credit facility
  $300 million   June 2010
Letter of credit facility
  $275 million   July 2009 *
Revolving credit facility
  $2.5 billion   November 2012
Canadian revolving credit facility
  Cdn. $115 million   December 2012
 
*   The $275 million letter of credit facility expired in July 2009.
As of June 30, 2009, we had $247 million of letters of credit outstanding under our uncommitted short-term bank credit facilities and $249 million of letters of credit outstanding under our U.S. committed revolving credit facilities. Under our Canadian committed revolving credit facility, we had Cdn. $19 million of letters of credit outstanding as of June 30, 2009. Our letters of credit expire during 2009 and 2010.
Common Stock Offering
On June 3, 2009, we sold in a public offering 46 million shares of our common stock, which included 6 million shares related to an overallotment option exercised by the underwriters, at a price of $18.00 per share and received proceeds, net of underwriting discounts and commissions and other issuance costs, of $799 million.

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Stock Purchase Programs
As of June 30, 2009, we have approvals under common stock purchase programs previously approved by our board of directors to purchase approximately $3.5 billion of our common stock.
Tax Matters
As discussed in Note 13 of Condensed Notes to Consolidated Financial Statements, we are subject to extensive tax liabilities. 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.
Effective January 1, 2007, the Government of Aruba (GOA) enacted a turnover tax on revenues from the sale of goods produced and services rendered in Aruba. The turnover tax, which is 3% for on-island sales and services and 1% on export sales, is being assessed by the GOA on sales by our Aruba Refinery. However, due to a previous tax holiday that was granted to our Aruba Refinery by the GOA through December 31, 2010 as well as other reasons, we believe that exports by our Aruba Refinery should not be subject to this turnover tax. We commenced arbitration proceedings with the Netherlands Arbitration Institute pursuant to which we are seeking to enforce our rights under the tax holiday and other agreements related to the refinery. The arbitration hearing was held on February 3-4, 2009. We anticipate a decision sometime later this year. We have also filed protests of these assessments through proceedings in Aruba. In April 2008, we entered into an escrow agreement with the GOA and Caribbean Mercantile Bank NV (CMB), pursuant to which we agreed to deposit an amount equal to the disputed turnover tax on exports into an escrow account with CMB, pending resolution of the tax protest proceedings in Aruba. Under this escrow agreement, we are required to continue to deposit an amount equal to the disputed tax on a monthly basis until the tax dispute is resolved through the Aruba proceedings. On April 20, 2009, we were notified that the Aruban tax court overruled our protests with respect to the turnover tax assessed in January and February 2007, totaling $8 million. Under the escrow agreement, we expensed and paid $8 million, plus $1 million of interest, to the GOA in the second quarter of 2009. The tax protests for the remaining periods remain outstanding, and no expense or liability has been recognized in our consolidated financial statements with respect to these remaining periods. Amounts deposited under this escrow agreement, which totaled $111 million and $102 million as of June 30, 2009 and December 31, 2008, respectively, are reflected as “restricted cash” in our consolidated balance sheets.
In addition to the turnover tax described above, the GOA has also asserted other tax amounts aggregating approximately $25 million related to dividends and other tax items. The GOA, through the arbitration, is also now questioning the validity of the tax holiday generally, although the GOA has not issued any formal assessment for profit tax at any time during the tax holiday period. We believe that the provisions of our tax holiday agreement exempt us from all of these taxes and, accordingly, no expense or liability has been recognized in our consolidated financial statements. We are also challenging approximately $30 million in foreign exchange payments made to the Central Bank of Aruba as payments exempted under our tax holiday, as well as other reasons. These taxes and assessments are also being addressed in the arbitration proceedings discussed above.
Asset Impairments
Under FASB Statement No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” long-lived assets must be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the long-lived assets may not be recoverable. A long-lived asset is not recoverable if its carrying amount exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If a long-lived asset is not recoverable, an impairment loss is recognized

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in an amount by which its carrying amount exceeds its fair value, with fair value determined under Statement No. 157, generally based on discounted estimated net cash flows.
In order to test long-lived assets for recoverability, management must make estimates of projected cash flows related to the asset being evaluated, which include, but are not limited to, assumptions about the use or disposition of the asset, its estimated remaining life, and future expenditures necessary to maintain its existing service potential. In order to determine fair value, management must make certain estimates and assumptions including, among other things, an assessment of market conditions, projected cash flows, investment rates, interest/equity rates, and growth rates, that could significantly impact the fair value of the asset being tested for impairment.
During the fourth quarter of 2008, there were severe disruptions in the capital and commodities markets that contributed to a significant decline in our common stock price, thus causing our market capitalization to decline to a level substantially below our net book value. Due to these adverse changes in market conditions during the fourth quarter of 2008, we evaluated our significant operating assets for potential impairment as of December 31, 2008, and we determined that the carrying amount of each of these assets was recoverable. The economic slowdown that began in 2008 continued throughout the first six months of 2009, thereby further reducing demand for refined products and putting significant pressure on refined product margins. Due to these economic conditions, in June 2009, we announced our plan to temporarily shut down the Aruba Refinery, which had a net book value of approximately $1.0 billion as of June 30, 2009, for at least two months as narrow heavy sour crude oil differentials currently make the refinery uneconomical to operate. The Aruba Refinery was shut down in July 2009. We are continuing to pursue potential transactions for this refinery, which may include the sale of the refinery. In June 2009, the coker unit at the Corpus Christi East Refinery was also temporarily shut down, partly due to economic reasons. As a result of these factors, we readdressed the potential impairment of all of our significant operating assets as of June 30, 2009, incorporating updated 2009 price assumptions into our estimated cash flows. Based on this analysis, we determined that the carrying amount of each of our significant operating assets continued to be recoverable as of June 30, 2009.
Also in the second quarter of 2009, due to the impact of the continuing economic slowdown on refining industry fundamentals and in an effort to conserve cash, we evaluated all of our capital projects currently in progress. As a result of this assessment, certain capital projects were permanently cancelled, resulting in the write-off of $122 million of project costs in the second quarter of 2009. We have also suspended continued construction activity on various other projects. For example, our two hydrocracker projects on the Gulf Coast, one at the St. Charles Refinery and the other at the Port Arthur Refinery, have been suspended pending a reassessment of the demand for the additional refined product supply that would result from these projects. As of June 30, 2009, approximately $915 million of costs had been incurred on these two projects. In addition, various other projects with a total cost of approximately $430 million as of June 30, 2009 have also been suspended.
Due to the effect of the current unfavorable economic conditions on the refining industry, and our expectations of a continuation of such conditions for the near term, we will continue to monitor both our operating assets and our capital projects for potential asset impairments or project write-offs until conditions improve. Our current evaluations are focused on our Delaware City Refinery, which had a net book value of approximately $2.0 billion as of June 30, 2009. Additional assessments will be performed in conjunction with our annual strategic plan process in the third quarter of 2009. Changes in market conditions, as well as changes in assumptions used to test for recoverability and to determine fair value, could result in significant impairment charges or project write-offs in the future, thus affecting our earnings.

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American Clean Energy and Security Act of 2009
On June 26, 2009, the U.S. House of Representatives narrowly approved the American Clean Energy and Security Act of 2009 (ACESA), also known as the Waxman-Markey Bill. The ACESA, if passed by the U.S. Senate, would establish a national “cap-and-trade” program beginning in 2012 to address greenhouse gas emissions and climate change. The ACESA proposes to reduce carbon dioxide and other greenhouse gas emissions by 3% below 2005 levels by 2012, 20% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by 2050. The cap-and-trade program would require businesses that emit greenhouse gases to acquire emission credits from the government, other businesses, or through an auction process. In addition, refiners would be obligated to purchase emission credits associated with the transportation fuels (gasoline, diesel, and jet fuel) sold and consumed in the United States. As a result of such a program, we could be required to purchase emission credits for greenhouse gas emissions resulting from our operations and from the fuels we sell. Although it is not possible at this time to predict the final form of the ACESA (or whether it will be passed by the U.S. Senate), any new federal restrictions on greenhouse gas emissions – including a cap-and-trade program – could result in increased compliance costs, additional operating restrictions for our business, and an increase in the cost of the products we produce, which could have an adverse effect on our financial position, results of operations, and liquidity.
Other
We expect to contribute a total of approximately $70 million to our qualified pension plans during 2009. In January 2009, we contributed $50 million of this amount to our main qualified pension plan.
We are subject to extensive federal, state, and local environmental laws and regulations, including those relating to the discharge of materials into the environment, waste management, pollution prevention measures, greenhouse gas emissions, and characteristics and composition of gasolines and distillates. Because environmental laws and regulations are becoming more complex and stringent and new environmental laws and regulations are continuously being enacted or proposed, the level of future expenditures required for environmental matters could increase in the future. In addition, any major upgrades in any of our refineries could require material additional expenditures to comply with environmental laws and regulations.
We believe that we have sufficient funds from operations and, to the extent necessary, from borrowings under our credit facilities, to fund our ongoing operating requirements. We expect that, to the extent necessary, we can raise additional funds from time to time through equity or debt financings in the public and private capital markets or the arrangement of additional credit facilities. However, there can be no assurances regarding the availability of any future financings or additional credit facilities or whether such financings or additional credit facilities can be made available on terms that are acceptable to us.
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in accordance with United States generally accepted accounting principles requires management 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. Our critical accounting policies are disclosed in our annual report on Form 10-K for the year ended December 31, 2008.
As discussed in Note 2 of Condensed Notes to Consolidated Financial Statements, certain new financial accounting pronouncements have been issued that either have already been reflected in the accompanying consolidated financial statements, or will become effective for our financial statements at various dates in the future.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk
COMMODITY PRICE RISK
For information regarding gains and losses on our derivative instruments, see Note 10 of Condensed Notes to Consolidated Financial Statements. The following tables provide information about our derivative commodity instruments as of June 30, 2009 and December 31, 2008 (dollars in millions, except for the weighted-average pay and receive prices as described below), including:
 
Fair Value Hedges – Fair value hedges are used to hedge certain refining inventories (which had a carrying amount of $4.2 billion and $4.4 billion as of June 30, 2009 and December 31, 2008, respectively, and a fair value of $7.2 billion and $5.1 billion as of June 30, 2009 and December 31, 2008, respectively) and our firm commitments (i.e., binding agreements to purchase inventories in the future). The gain or loss on a derivative instrument designated and qualifying as a fair value hedge and the offsetting loss or gain on the hedged item are recognized currently in income in the same period.
Cash Flow Hedges – Cash flow hedges are used to hedge certain forecasted feedstock and product purchases, refined product sales, and natural gas purchases. 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.
Economic Hedges – Economic hedges are hedges not designated as fair value or cash flow hedges that are used to:
    manage price volatility in refinery feedstock, refined product, and grain inventories;
    manage price volatility in forecasted refinery feedstock, product, and grain purchases, refined product sales, and natural gas purchases; and
    manage price volatility in the referenced product margins associated with the three-year earn-out agreement with Alon in connection with the sale of our Krotz Springs Refinery.
The derivative instruments related to economic hedges are recorded at fair value and changes in the fair value of the derivative instruments are recognized currently in income.
Trading Activities – These represent derivative commodity instruments held or issued for trading purposes. The derivative instruments entered into by us for trading activities are recorded at fair value and changes in the fair value of the derivative instruments are recognized currently in income.
The following tables include only open positions at the end of the reporting period. Contract volumes are presented in thousands of barrels (for crude oil and refined products), in billions of British thermal units (for natural gas), or in thousands of bushels (for grain). The weighted-average pay and receive prices represent amounts per barrel (for crude oil and refined products), amounts per million British thermal units (for natural gas), or amounts per bushel (for grain). Volumes shown for swaps represent notional volumes, which are used to calculate amounts due under the agreements. For futures, the contract value represents the contract price of either the long or short position multiplied by the derivative contract volume, while the market value amount represents the period-end market price of the commodity being hedged multiplied by the derivative contract volume. The pre-tax fair value for futures, swaps, and options represents the fair value of the derivative contract. The pre-tax fair value for swaps represents the excess of the receive price over the pay price multiplied by the notional contract volumes. For futures and options, the pre-tax fair value represents (i) the excess of the market value amount over the contract amount for long positions, or (ii) the excess of the contract amount over the market value amount for short positions. Additionally, for futures and options, the weighted-average pay price represents the contract price for long positions and the weighted-average receive price represents the contract price for

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short positions. The weighted-average pay price and weighted-average receive price for options represent their strike price.
                                                 
    June 30, 2009
            Wtd Avg   Wtd Avg                   Pre-tax
    Contract   Pay   Receive   Contract   Market   Fair
    Volumes   Price   Price   Value   Value   Value
                                     
Fair Value Hedges:
                                               
Futures – short:
                                               
2009 (crude oil and refined products)
    5,178       N/A     71.12     368     365     3  
                                     
Cash Flow Hedges:
                                               
Swaps – long:
                                               
2009 (crude oil and refined products)
    14,157     114.84       72.98       N/A       (593 )     (593 )
2010 (crude oil and refined products)
    15,900       60.46       75.34       N/A       237       237  
Swaps – short:
                                               
2009 (crude oil and refined products)
    14,157       78.06       132.06       N/A       764       764  
2010 (crude oil and refined products)
    15,900       86.57       72.68       N/A       (221 )     (221 )
Futures – long:
                                               
2009 (crude oil and refined products)
    1,211       72.12       N/A       87       85       (2 )
                                     
Economic Hedges:
                                               
Swaps – long:
                                               
2009 (crude oil and refined products)
    52,625       34.89       30.43       N/A       (235 )     (235 )
2010 (crude oil and refined products)
    51,514       51.27       41.88       N/A       (484 )     (484 )
2011 (crude oil and refined products)
    11,750       45.56       30.16       N/A       (181 )     (181 )
Swaps – short:
                                               
2009 (crude oil and refined products)
    36,233       44.99       54.49       N/A       344       344  
2010 (crude oil and refined products)
    47,878       50.77       63.34       N/A       602       602  
2011 (crude oil and refined products)
    8,850       44.07       65.39       N/A       189       189  
Futures – long:
                                               
2009 (crude oil and refined products)
    238,825       66.24       N/A       15,820       17,679       1,859  
2010 (crude oil and refined products)
    39,618       67.40       N/A       2,670       3,168       498  
2009 (grain)
    7,605       4.11       N/A       31       26       (5 )
2010 (grain)
    50       4.29       N/A                    
Futures – short:
                                               
2009 (crude oil and refined products)
    231,332       N/A       66.96       15,491       17,298       (1,807 )
2010 (crude oil and refined products)
    39,174       N/A       69.53       2,724       3,228       (504 )
2009 (grain)
    20,355       N/A       4.16       85       72       13  
2010 (grain)
    3,405       N/A       4.48       15       13       2  
                                     
Trading Activities:
                                               
Swaps – long:
                                               
2009 (crude oil and refined products)
    10,413       63.80       51.56       N/A       (127 )     (127 )
2010 (crude oil and refined products)
    18,780       24.92       28.96       N/A       76       76  
2011 (crude oil and refined products)
    3,000       53.70       57.55       N/A       12       12  
Swaps – short:
                                               
2009 (crude oil and refined products)
    12,455       43.38       54.41       N/A       137       137  
2010 (crude oil and refined products)
    22,008       24.98       23.91       N/A       (24 )     (24 )
2011 (crude oil and refined products)
    3,900       44.27       43.29       N/A       (4 )     (4 )

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    June 30, 2009
            Wtd Avg   Wtd Avg                   Pre-tax
    Contract   Pay   Receive   Contract   Market   Fair
    Volumes   Price   Price   Value   Value   Value
 
Futures – long:
                                               
2009 (crude oil and refined products)
    30,122     75.04       N/A     2,260     2,222     (38 )
2010 (crude oil and refined products)
    2,321       77.04       N/A       179       190       11  
2009 (natural gas)
    5,350       4.95       N/A       26       25       (1 )
2010 (natural gas)
    100       6.10       N/A       1       1        
Futures – short:
                                               
2009 (crude oil and refined products)
    30,214       N/A     75.01       2,266       2,223       43  
2010 (crude oil and refined products)
    2,346       N/A       75.68       178       191       (13 )
2009 (natural gas)
    5,100       N/A       5.02       25       24       1  
2010 (natural gas)
    100       N/A       5.46       1       1        
 
                                               
                                     
Total pre-tax fair value of open positions
                                          552  
 
                                               

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    December 31, 2008
            Wtd Avg   Wtd Avg                   Pre-tax
    Contract   Pay   Receive   Contract   Market   Fair
    Volumes   Price   Price   Value   Value   Value
 
Fair Value Hedges:
                                               
Futures – short:
                                               
2009 (crude oil and refined products)
    6,904       N/A     48.28     333     320     13  
 
                                               
Cash Flow Hedges:
                                               
Swaps – long:
                                               
2009 (crude oil and refined products)
    60,162     121.69       58.44       N/A       (3,805 )     (3,805 )
2010 (crude oil and refined products)
    4,680       63.72       64.03       N/A       1       1  
Swaps – short:
                                               
2009 (crude oil and refined products)
    60,162       62.38       129.80       N/A       4,056       4,056  
2010 (crude oil and refined products)
    4,680       76.32       78.69       N/A       11       11  
Futures – long:
                                               
2009 (crude oil and refined products)
    780       38.62       N/A       30       27       (3 )
 
                                               
Economic Hedges:
                                               
Swaps – long:
                                               
2009 (crude oil and refined products)
    25,987       96.88       55.25       N/A       (1,082 )     (1,082 )
2010 (crude oil and refined products)
    19,734       105.96       63.94       N/A       (829 )     (829 )
2011 (crude oil and refined products)
    3,900       124.78       67.99       N/A       (221 )     (221 )
Swaps – short:
                                               
2009 (crude oil and refined products)
    25,931       59.65       106.81       N/A       1,223       1,223  
2010 (crude oil and refined products)
    19,734       72.18       121.96       N/A       982       982  
2011 (crude oil and refined products)
    3,900       74.08       136.66       N/A       244       244  
Futures – long:
                                               
2009 (crude oil and refined products)
    135,882       59.17       N/A       8,040       7,319       (721 )
2010 (crude oil and refined products)
    3,466       78.33       N/A       271       240       (31 )
2009 (natural gas)
    4,310       8.46       N/A       36       24       (12 )
Futures – short:
                                               
2009 (crude oil and refined products)
    135,091       N/A       62.74       8,475       7,510       965  
2010 (crude oil and refined products)
    3,692       N/A       84.66       313       276       37  
2009 (natural gas)
    4,310       N/A       5.68       24       24        
Options – long:
                                               
2009 (crude oil and refined products)
    57       60.64       N/A       1             (1 )
 
                                               
Trading Activities:
                                               
Swaps – long:
                                               
2009 (crude oil and refined products)
    19,887       77.56       45.09       N/A       (646 )     (646 )
2010 (crude oil and refined products)
    10,050       40.66       35.35       N/A       (53 )     (53 )
2011 (crude oil and refined products)
    1,950       78.36       65.80       N/A       (24 )     (24 )
Swaps – short:
                                               
2009 (crude oil and refined products)
    16,084       56.44       97.17       N/A       655       655  
2010 (crude oil and refined products)
    5,850       64.19       73.12       N/A       52       52  
2011 (crude oil and refined products)
    1,950       68.06       80.59       N/A       24       24  

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    December 31, 2008
            Wtd Avg   Wtd Avg                   Pre-tax
    Contract   Pay   Receive   Contract   Market   Fair
    Volumes   Price   Price   Value   Value   Value
   
Futures – long:
                                               
2009 (crude oil and refined products)
    24,039     71.70       N/A     1,724     1,300     (424 )
2010 (crude oil and refined products)
    956       84.12       N/A       80       70       (10 )
2009 (natural gas)
    200       5.79       N/A       1       1        
Futures – short:
                                               
2009 (crude oil and refined products)
    21,999       N/A     73.38       1,614       1,209       405  
2010 (crude oil and refined products)
    956       N/A       83.63       80       70       10  
2009 (natural gas)
    200       N/A       5.82       1       1        
Options – long:
                                               
2009 (crude oil and refined products)
    100       30.00       N/A                    
 
                                               
 
                                               
Total pre-tax fair value of open positions
                                          816  
 
                                               

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INTEREST RATE RISK
The following table provides information about our debt instruments (dollars in millions), the fair value of which is sensitive to changes in interest rates. Principal cash flows and related weighted-average interest rates by expected maturity dates are presented. We had no interest rate derivative instruments outstanding as of June 30, 2009 and December 31, 2008.
                                                                 
    June 30, 2009
    Expected Maturity Dates            
                                            There-           Fair
    2009   2010   2011   2012   2013   after   Total   Value
   
Debt:
                                                               
Fixed rate
      33     418     759     489     5,597     7,296     7,205  
Average interest rate
    %     6.8 %     6.4 %     6.9 %     5.5 %     7.3 %     7.1 %        
Floating rate
      100                     100     100  
Average interest rate
    %     1.8 %     %     %     %     %     1.8 %        
                                                                 
    December 31, 2008
    Expected Maturity Dates            
                                            There-           Fair
    2009   2010   2011   2012   2013   after   Total   Value
Debt:
                                                               
Fixed rate
  209     33     418     759     489     4,597     6,505     6,362  
Average interest rate
    3.6 %     6.8 %     6.4 %     6.9 %     5.5 %     6.8 %     6.6 %        
Floating rate
  100                         100     100  
Average interest rate
    3.9 %     %     %     %     %     %     3.9 %        
FOREIGN CURRENCY RISK
As of June 30, 2009, we had commitments to purchase $301 million of U.S. dollars. These commitments matured on or before July 20, 2009, resulting in a $7 million loss in the third quarter of 2009.
Item 4.
 
Controls and Procedures
(a) Evaluation of disclosure controls and procedures.
Our management has evaluated, with the participation of our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report, and has concluded that our disclosure controls and procedures were effective as of June 30, 2009.
(b) Changes in internal control over financial reporting.
There has been no change in our internal control over financial reporting that occurred during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION
Item 1. Legal Proceedings
The information below describes new proceedings or material developments in proceedings that we previously reported in our annual report on Form 10-K for the year ended December 31, 2008, or our quarterly report on Form 10-Q for the quarter ended March 31, 2009.
Litigation
For the legal proceedings listed below, we hereby incorporate by reference into this Item our disclosures made in Part I, Item 1 of this Report included in Note 13 of Condensed Notes to Consolidated Financial Statements under the caption “Litigation.”
   
MTBE Litigation
   
Retail Fuel Temperature Litigation
   
Rosolowski
   
Other Litigation
Environmental Enforcement Matters
While it is not possible to predict the outcome of the following environmental proceedings, if any one or more of them were decided against us, we believe that there would be no material effect on our consolidated financial position or results of operations. We are reporting these proceedings to comply with SEC regulations, which require us to disclose certain information about proceedings arising under federal, state, or local provisions regulating the discharge of materials into the environment or protecting the environment if we reasonably believe that such proceedings will result in monetary sanctions of $100,000 or more.
United States Environmental Protection Agency (EPA) (Paulsboro Refinery). On July 9, 2009, the EPA issued a demand for a $1,017,500 stipulated penalty under a Section 114 Consent Decree for an acid gas flaring incident in September 2008.
Los Angeles Regional Water Quality Control Board (LARWQCB) (Wilmington Marine Terminal) (this matter was last reported in our Form 10-K for the year ended December 31, 2008). In December 2007, as part of the National Pollutant Discharge Elimination System Permit renewal process for our Wilmington marine terminal, the LARWQCB issued a notice of violation (NOV) and Request for Information. The NOV alleged violations of acute toxicity effluent limits between 2000 and 2006 and reporting violations between 2001 and 2005. We settled this matter in the second quarter of 2009.
South Coast Air Quality Management District (SCAQMD) (Wilmington Refinery). On June 26, 2009, the SCAQMD issued a Request for Flare Minimization Plan and Mitigation Fees pursuant to its amended Rule 1118 (Control of Emissions from Refinery Flares). The Request related to two flaring events at our Wilmington Refinery in the fall of 2008. We submitted the mitigation plan and paid the mitigation fee of $1,319,505 on July 28, 2009.
Texas Commission on Environmental Quality (TCEQ) (Corpus Christi West Refinery). In the second quarter of 2009, the TCEQ issued a notice of enforcement (NOE) to our Corpus Christi West Refinery. The NOE alleges excess air emissions relating to two cooling tower leaks that occurred in 2008. The penalty demanded in the TCEQ’s Preliminary Report and Petition was $1,100,424. On July 27, 2009, we filed a response and request for hearing on this matter. Settlement discussions continue on this matter.

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Item 1A.
 
Risk Factors
There have been no material changes from the risk factors disclosed in the “Risk Factors” section of our annual report on Form 10-K for the year ended December 31, 2008.
Item 2.
 
Unregistered Sales of Equity Securities and Use of Proceeds
          (a) Unregistered Sales of Equity Securities. Not applicable.
          (b) Use of Proceeds. Not applicable.
          (c) Issuer Purchases of Equity Securities. The following table discloses purchases of shares of our common stock made by us or on our behalf for the periods shown below.
                                                       
 
  Period     Total     Average     Total Number of     Total Number of     Maximum Number (or  
        Number of     Price     Shares Not     Shares Purchased     Approximate Dollar  
        Shares     Paid per     Purchased as Part     as Part of     Value) of Shares that  
        Purchased     Share     of Publicly     Publicly     May Yet Be Purchased  
                            Announced Plans     Announced Plans     Under the Plans or  
                            or Programs (1)     or Programs     Programs  
                                                (at month end) (2)  
 
April 2009
      2,571         $ 19.99         2,571               $ 3.46 billion  
 
May 2009
      6,385         $ 20.80         6,385               $ 3.46 billion  
 
June 2009
         397         $ 22.03         397               $ 3.46 billion  
 
Total
      9,353         $ 20.63         9,353               $ 3.46 billion  
 
  (1)  
The shares reported in this column represent purchases settled in the second quarter of 2009 relating to (a) our purchases of shares in open-market transactions to meet our obligations under employee benefit plans, and (b) our purchases of shares from our employees and non-employee directors in connection with the exercise of stock options, the vesting of restricted stock, and other stock compensation transactions in accordance with the terms of our incentive compensation plans.
 
  (2)  
On April 26, 2007, we publicly announced an increase in our common stock purchase program from $2 billion to $6 billion, as authorized by our board of directors on April 25, 2007. The $6 billion common stock purchase program has no expiration date. On February 28, 2008, we announced that our board of directors approved a new $3 billion common stock purchase program. This program is in addition to the $6 billion program. This $3 billion program has no expiration date.

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Item 4. Submission of Matters to a Vote of Security Holders.
Valero’s annual meeting of stockholders (the Annual Meeting) was held April 30, 2009. Matters voted on at the Annual Meeting and the results thereof were as follows:
  (a)   Proposal 1: a proposal to elect four Class III directors to serve until the 2012 annual meeting. Valero’s bylaws require each director to be elected by the vote of the majority of the votes cast at the Annual Meeting. For purposes of this election, a “majority of the votes cast” means that the number of shares voted “for” a director’s election exceeds 50% of the number of votes cast with respect to that director’s election. The election of each Class III director was approved as follows.
                         
Directors
 
For
 
Against
 
Abstain
 
Jerry D. Choate
    274,635,688       160,197,114       1,889,959  
William R. Klesse
    276,485,338       158,311,375       1,926,048  
Donald L. Nickles
    273,997,328       160,869,421       1,856,011  
Susan Kaufman Purcell
    277,154,116       157,768,781       1,799,864  
      Directors whose terms of office continued after the annual meeting were: W.E. “Bill” Bradford, Ronald K. Calgaard, Irl F. Engelhardt, Ruben M. Escobedo, Bob Marbut, Robert A. Profusek, and Stephen M. Waters.
 
  (b)   Proposal 2: a proposal to ratify the appointment of KPMG LLP to serve as Valero’s independent registered public accounting firm for the fiscal year ending December 31, 2009. Proposal 2 required approval by the affirmative vote of a majority of the voting power of the shares present in person or by proxy at the Annual Meeting and entitled to vote. Proposal 2 was approved as follows:
             
For
 
Against
 
Abstain
(1)  
 
430,981,925
  4,563,821             1,177,014  
             
Total Affirmative Votes   Total Negative Votes
   
430,981,925
  5,740,835    
Percentage of Shares Present and
Entitled to Vote
  Percentage of Shares Present and
Entitled to Vote
   
98.69%
  1.31%    
      Stockholder Proposals:
 
  (c)   Proposal 3: a stockholder proposal entitled, “Say-On-Pay” was approved as follows:
                 
For
 
Against
 
Abstain
(1)  
Non-Votes
(2)
 
195,481,456
  117,571,382   28,978,894     94,691,029  
 
               
Total Affirmative Votes   Total Negative Votes
       
195,481,456
  146,550,276        
Percentage of Shares Present
and Entitled to Vote
  Percentage of Shares Present and
Entitled to Vote
       
57.15%
  42.85%        
 
(1) (2)   See notes on following page.

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  (d)   Proposal 4: a stockholder proposal entitled, “Stock Retention by Executives” was not approved as follows:
                 
For
 
Against
 
Abstain
(1)  
Non-Votes
(2)
 
144,998,858
  193,369,259   3,663,615   94,691,029  
                 
Total Affirmative Votes   Total Negative Votes        
144,998,858
  197,032,874        
Percentage of Shares Present
and Entitled to Vote
  Percentage of Shares Present and
Entitled to Vote
       
42.39%
  57.61%        
  (e)   Proposal 5: a stockholder proposal entitled, “Compensation Consultant Disclosures” was approved as follows:
                 
For
 
Against
 
Abstain
(1)  
Non-Votes
(2)
 
190,261,333
  146,832,853   4,937,545   94,691,030  
 
               
Total Affirmative Votes   Total Negative Votes        
190,261,333
  151,770,398        
Percentage of Shares Present
and Entitled to Vote
  Percentage of Shares Present and
Entitled to Vote
       
55.63%
  44.37%        
  (f)   Proposal 6: a stockholder proposal entitled, “Disclosure of Political Contributions/Trade Associations” was not approved as follows:
                 
For
 
Against
 
Abstain
(1)  
Non-Votes
(2)
 
133,683,745
  148,235,929   60,112,059   94,691,028  
 
               
Total Affirmative Votes   Total Negative Votes        
133,683,745
  208,347,988        
Percentage of Shares Present
and Entitled to Vote
  Percentage of Shares Present and
Entitled to Vote
       
39.09%
  60.91%        
Required votes. For Proposal 1, directors were to be elected by a majority of votes cast by the holders of shares of Valero’s common stock present in person or by proxy at the Annual Meeting and entitled to vote. Proposals 2, 3, 4, 5, and 6 required approval by the affirmative vote of a majority of the voting power of the shares present in person or by proxy at the Annual Meeting and entitled to vote. Only Proposals 1, 2, 3, and 5 received the required votes for approval.
Notes :
(1) Effect of abstentions. Shares voted to “abstain” are treated as “present” for purposes of determining a quorum, and have the effect of a negative vote when approval for a proposal requires a majority of the voting power of the issued and outstanding shares of the company or a majority of the voting power of the shares present in person or by proxy and entitled to vote.
(2) Effect of “broker non-votes.” Brokers holding shares for the beneficial owners of such shares must vote according to specific instructions received from the beneficial owners. If specific instructions are not received, a broker may vote the shares in the broker’s discretion in certain instances. However, the New York Stock Exchange (NYSE) precludes brokers from exercising voting discretion on certain proposals, including stockholder proposals, without specific instructions from the beneficial owner. This results in a

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“broker non-vote” on the proposal. A broker non-vote is treated as “present” for purposes of determining a quorum, has the effect of a negative vote when approval for a particular proposal requires a majority of the voting power of the issued and outstanding shares of the company, and has no effect when approval for a proposal requires a majority of the voting power of the shares present in person or by proxy and entitled to vote. Per the NYSE’s rules, brokers had discretion to vote on Proposals 1 and 2 at the Annual Meeting, but did not have discretion to vote on the shareholder proposals presented as Proposals 3, 4, 5, and 6.
Item 6. Exhibits
     
Exhibit No.   Description
 
 
 
*12.01
 
Statements of Computations of Ratios of Earnings to Fixed Charges and Ratios of Earnings to Fixed Charges and Preferred Stock Dividends.
 
 
 
*31.01
 
Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal executive officer.
 
 
 
*31.02
 
Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of principal financial officer.
 
 
 
*32.01
 
Section 1350 Certifications (as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002).
 
 
 
**101
 
The following materials from Valero Energy Corporation’s Form 10-Q for the quarter ended June 30, 2009, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Statements of Other Comprehensive Income, and (v) Condensed Notes to Consolidated Financial Statements, tagged as blocks of text.
 
*
 
Filed herewith.
 
**
 
Submitted electronically herewith.
In accordance with Rule 402 of Regulation S-T, the XBRL information in Exhibit 101 to this Quarterly Report on Form 10-Q shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
         
  VALERO ENERGY CORPORATION
                   (Registrant)
 
 
  By:   /s/ Michael S. Ciskowski    
    Michael S. Ciskowski   
    Executive Vice President and
      Chief Financial Officer
(Duly Authorized Officer and Principal
Financial and Accounting Officer) 
 
 
Date: August 7, 2009

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