e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ |
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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
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o |
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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)
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Delaware
(State or other jurisdiction of
incorporation or organization)
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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
(Registrants 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.
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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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 registrants 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
2
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
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June 30, |
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December 31, |
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2009 |
|
2008 |
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(Unaudited) |
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ASSETS |
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Current assets: |
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Cash and temporary cash investments |
|
$ |
1,623 |
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$ |
940 |
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Restricted cash |
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141 |
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131 |
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Receivables, net |
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4,217 |
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2,897 |
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Inventories |
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4,561 |
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4,637 |
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Income taxes receivable |
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27 |
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|
197 |
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Deferred income taxes |
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132 |
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98 |
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Prepaid expenses and other |
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472 |
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550 |
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Total current assets |
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11,173 |
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9,450 |
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Property, plant and equipment, at cost |
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29,688 |
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28,103 |
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Accumulated depreciation |
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(5,404 |
) |
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(4,890 |
) |
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Property, plant and equipment, net |
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24,284 |
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23,213 |
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Intangible assets, net |
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221 |
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224 |
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Deferred charges and other assets, net |
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1,543 |
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1,530 |
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Total assets |
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$ |
37,221 |
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$ |
34,417 |
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LIABILITIES AND STOCKHOLDERS EQUITY |
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Current liabilities: |
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Current portion of debt and capital lease obligations |
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$ |
137 |
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$ |
312 |
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Accounts payable |
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5,840 |
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4,446 |
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Accrued expenses |
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350 |
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374 |
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Taxes other than income taxes |
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557 |
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592 |
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Income taxes payable |
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36 |
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Deferred income taxes |
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404 |
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485 |
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Total current liabilities |
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7,324 |
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6,209 |
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Debt and capital lease obligations, less current portion |
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7,231 |
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6,264 |
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Deferred income taxes |
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4,105 |
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4,163 |
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Other long-term liabilities |
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2,154 |
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2,161 |
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Commitments and contingencies |
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Stockholders equity: |
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Common stock, $0.01 par value; 1,200,000,000 shares authorized;
673,501,593 and 627,501,593 shares issued |
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7 |
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6 |
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Additional paid-in capital |
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7,987 |
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7,190 |
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Treasury stock, at cost; 110,853,320 and 111,290,436 common shares |
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(6,856 |
) |
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(6,884 |
) |
Retained earnings |
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15,384 |
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15,484 |
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Accumulated other comprehensive loss |
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(115 |
) |
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(176 |
) |
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Total stockholders equity |
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16,407 |
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15,620 |
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Total liabilities and stockholders equity |
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$ |
37,221 |
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$ |
34,417 |
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See Condensed Notes to Consolidated Financial Statements.
3
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Three Months Ended |
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Six Months Ended |
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June 30, |
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June 30, |
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2009 |
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2008 |
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2009 |
|
2008 |
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Operating revenues (1) |
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$ |
17,925 |
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$ |
36,640 |
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$ |
31,749 |
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$ |
64,585 |
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Costs and expenses: |
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Cost of sales |
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16,543 |
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33,673 |
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28,171 |
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59,342 |
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Operating expenses |
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1,015 |
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1,133 |
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2,012 |
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2,247 |
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Retail selling expenses |
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171 |
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190 |
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340 |
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378 |
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General and administrative expenses |
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124 |
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117 |
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269 |
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|
252 |
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Depreciation and amortization expense |
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389 |
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369 |
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767 |
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736 |
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Total costs and expenses |
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18,242 |
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35,482 |
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31,559 |
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62,955 |
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Operating income (loss) |
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|
(317 |
) |
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|
1,158 |
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|
190 |
|
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|
1,630 |
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Other income (expense), net |
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(24 |
) |
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15 |
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(25 |
) |
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35 |
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Interest and debt expense: |
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Incurred |
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(118 |
) |
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(107 |
) |
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(237 |
) |
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(223 |
) |
Capitalized |
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36 |
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24 |
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|
76 |
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43 |
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Income (loss) before income tax expense (benefit) |
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(423 |
) |
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|
1,090 |
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|
4 |
|
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|
1,485 |
|
Income tax expense (benefit) |
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|
(169 |
) |
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|
356 |
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|
(51 |
) |
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|
490 |
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Net income (loss) |
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$ |
(254 |
) |
|
$ |
734 |
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$ |
55 |
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$ |
995 |
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Earnings (loss) per common share |
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$ |
(0.48 |
) |
|
$ |
1.39 |
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|
$ |
0.11 |
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$ |
1.88 |
|
Weighted-average common shares outstanding (in millions) |
|
|
525 |
|
|
|
526 |
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|
520 |
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|
529 |
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Earnings (loss) per common share assuming dilution |
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$ |
(0.48 |
) |
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$ |
1.37 |
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$ |
0.11 |
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$ |
1.85 |
|
Weighted-average common shares outstanding
assuming dilution (in millions) |
|
|
525 |
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|
|
534 |
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|
525 |
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|
537 |
|
Dividends per common share |
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$ |
0.15 |
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$ |
0.15 |
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$ |
0.30 |
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$ |
0.27 |
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Supplemental information: |
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(1) Includes excise taxes on sales by our U.S. retail system |
|
$ |
229 |
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$ |
204 |
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$ |
433 |
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$ |
398 |
|
See Condensed Notes to Consolidated Financial Statements.
4
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Six Months Ended June 30, |
|
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2009 |
|
2008 |
|
Cash flows from operating activities: |
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|
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Net income |
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$ |
55 |
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$ |
995 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
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Depreciation and amortization expense |
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767 |
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|
736 |
|
Stock-based compensation expense |
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23 |
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|
24 |
|
Deferred income tax benefit |
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|
(125 |
) |
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|
(93 |
) |
Changes in current assets and current liabilities |
|
|
557 |
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|
189 |
|
Changes in deferred charges and credits and other operating activities, net |
|
|
130 |
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(49 |
) |
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|
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Net cash provided by operating activities |
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|
1,407 |
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|
|
1,802 |
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Cash flows from investing activities: |
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Capital expenditures |
|
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(1,351 |
) |
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|
(1,178 |
) |
Deferred turnaround and catalyst costs |
|
|
(249 |
) |
|
|
(203 |
) |
Purchase of certain VeraSun Energy Corporation facilities |
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|
(556 |
) |
|
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|
Return of investment in Cameron Highway Oil Pipeline Company |
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|
8 |
|
|
|
12 |
|
Advance proceeds related to sale of assets |
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|
17 |
|
Contingent payment in connection with acquisition |
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(25 |
) |
Minor acquisitions |
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|
(29 |
) |
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|
(57 |
) |
Other investing activities, net |
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|
3 |
|
|
|
14 |
|
|
|
|
|
|
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Net cash used in investing activities |
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|
(2,174 |
) |
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|
(1,420 |
) |
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|
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Cash flows from financing activities: |
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Proceeds from the sale of common stock, net of issuance costs |
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|
799 |
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Non-bank debt: |
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Borrowings |
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|
998 |
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Repayments |
|
|
(209 |
) |
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|
(374 |
) |
Bank credit agreements: |
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Borrowings |
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|
296 |
|
Repayments |
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(296 |
) |
Accounts receivable sales program: |
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Proceeds from sale of receivables |
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|
500 |
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Repayments |
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(500 |
) |
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Purchase of common stock for treasury |
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(700 |
) |
Issuance of common stock in connection with employee benefit plans |
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4 |
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|
11 |
|
Benefit from tax deduction in excess of recognized stock-based compensation cost |
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|
1 |
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|
13 |
|
Common stock dividends |
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(155 |
) |
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|
(143 |
) |
Debt issuance costs |
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|
(8 |
) |
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Other financing activities |
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|
(2 |
) |
|
|
(2 |
) |
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|
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Net cash provided by (used in) financing activities |
|
|
1,428 |
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|
(1,195 |
) |
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|
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Effect of foreign exchange rate changes on cash |
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22 |
|
|
|
(7 |
) |
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|
|
|
|
|
|
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Net increase (decrease) in cash and temporary cash investments |
|
|
683 |
|
|
|
(820 |
) |
Cash and temporary cash investments at beginning of period |
|
|
940 |
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|
|
2,464 |
|
|
|
|
|
|
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Cash and temporary cash investments at end of period |
|
$ |
1,623 |
|
|
$ |
1,644 |
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|
|
|
|
|
|
|
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|
See Condensed Notes to Consolidated Financial Statements.
5
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Three Months Ended |
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Six Months Ended |
|
|
June 30, |
|
June 30, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
Net income (loss) |
|
$ |
(254 |
) |
|
$ |
734 |
|
|
$ |
55 |
|
|
$ |
995 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
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|
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|
|
|
|
|
|
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustment |
|
|
191 |
|
|
|
15 |
|
|
|
110 |
|
|
|
(62 |
) |
|
|
|
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Pension and other postretirement benefits
net (gain) loss reclassified into income, net of income
tax expense of $-, $1, $-, and $1 |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
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|
|
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|
|
|
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|
|
|
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|
|
|
|
|
|
|
|
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 |
) |
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss) |
|
|
122 |
|
|
|
(5 |
) |
|
|
61 |
|
|
|
(146 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss) |
|
$ |
(132 |
) |
|
$ |
729 |
|
|
$ |
116 |
|
|
$ |
849 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See Condensed Notes to Consolidated Financial Statements.
6
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
7
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 entitys 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
8
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 employers 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 entitys 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
9
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.
10
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 VeraSuns ethanol plant in Albert
City, Iowa, for consideration of $72 million and VeraSuns 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
11
VALERO ENERGY CORPORATION AND SUBSIDIARIES
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 |
|
12
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
13
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
14
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. |
15
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 |
|
16
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.
17
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 |
|
18
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.
19
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
20
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).
21
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 |
|
22
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.
23
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
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. |
25
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 |
|
|
|
|
|
|
|
|
|
|
|
|
26
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 |
|
|
|
|
|
|
|
|
|
|
27
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
28
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 Dows 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 Dows 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, Totals acquisition of Dows 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.
29
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
30
VALERO ENERGY CORPORATION AND SUBSIDIARIES
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 jurys award and decertified the class. Plaintiffs appealed, and in June
2008 the state appeals court reversed the trial judges 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.
31
VALERO ENERGY CORPORATION AND SUBSIDIARIES
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
32
VALERO ENERGY CORPORATION AND SUBSIDIARIES
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.
33
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35
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. |
36
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. |
37
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. |
38
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. |
39
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40
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
CompanyTennessee, L.L.C. (included in Other Non-Guarantor Subsidiaries) on April 1, 2008. |
41
Item 2. Managements 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;
|
42
|
|
|
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.
43
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.
44
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. |
45
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. |
46
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. |
47
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. |
48
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. |
49
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.
50
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.
51
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. |
52
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. |
53
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. |
54
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. |
55
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. |
56
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
57
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.
58
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; |
|
|
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|
purchase 12.6 million shares of our common stock at a cost of $700 million; |
|
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|
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. |
59
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 Dows 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 Dows 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, Totals acquisition of
60
Dows 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 Moodys Investors Service and Standard & Poors 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:
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Rating Agency |
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Rating |
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Standard & Poors Ratings Services |
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BBB (stable outlook) |
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Moodys Investors Service |
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Baa2 (stable outlook) |
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Fitch Ratings |
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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:
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Borrowing |
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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.
61
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
62
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.
63
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.
64
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
65
short positions. The weighted-average pay price and weighted-average receive price for options
represent their strike price.
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June 30, 2009 |
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Wtd Avg |
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Wtd Avg |
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Pre-tax |
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|
Contract |
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Pay |
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Receive |
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Contract |
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Market |
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Fair |
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Volumes |
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Price |
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Price |
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Value |
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Value |
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Value |
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Fair Value Hedges: |
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|
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|
|
|
|
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Futures short: |
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|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
2009 (crude oil and refined products) |
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|
5,178 |
|
|
|
N/A |
|
|
$ |
71.12 |
|
|
$ |
368 |
|
|
$ |
365 |
|
|
$ |
3 |
|
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Cash Flow Hedges: |
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Swaps long: |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
) |
|
|
|
|
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|
Economic Hedges: |
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Swaps long: |
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|
|
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 |
) |
66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
67
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
69
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.
70
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 TCEQs 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.
71
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. |
72
Item 4. Submission of Matters to a Vote of Security Holders.
Valeros 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. Valeros 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
directors election exceeds 50% of the number of votes cast with respect to that
directors election. The election of each Class III director was approved as follows. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
Valeros 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. |
73
|
(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 Valeros 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 brokers 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 NYSEs 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
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Exhibit No. |
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Description |
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*12.01 |
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Statements of Computations of Ratios of Earnings to Fixed
Charges and Ratios of Earnings to Fixed Charges and Preferred
Stock Dividends. |
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*31.01 |
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Rule 13a-14(a) Certification (under Section 302 of the
Sarbanes-Oxley Act of 2002) of principal executive officer. |
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*31.02 |
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Rule 13a-14(a) Certification (under Section 302 of the
Sarbanes-Oxley Act of 2002) of principal financial officer. |
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*32.01 |
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Section 1350 Certifications (as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002). |
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**101 |
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The following materials from Valero Energy Corporations 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. |
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* |
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Filed herewith. |
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** |
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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.
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VALERO ENERGY CORPORATION
(Registrant)
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By: |
/s/ Michael S. Ciskowski
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Michael S. Ciskowski |
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Executive Vice President and
Chief Financial Officer
(Duly Authorized Officer and
Principal
Financial and Accounting Officer) |
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Date: August 7, 2009
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