e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
|
|
|
þ |
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2009
OR
|
|
|
o |
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from
to
Commission file number 1-13175
VALERO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
|
|
|
Delaware
(State or other jurisdiction of
incorporation or organization)
|
|
74-1828067
(I.R.S. Employer
Identification No.) |
One Valero Way
San Antonio, Texas
(Address of principal executive offices)
78249
(Zip Code)
(210) 345-2000
(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.
|
|
|
|
|
|
|
Large accelerated filer þ
|
|
Accelerated filer o
|
|
Non-accelerated filer o
|
|
Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
The number of shares of the registrants only class of common stock, $0.01 par value, outstanding
as of October 30, 2009 was 564,349,512.
VALERO ENERGY CORPORATION AND SUBSIDIARIES
INDEX
|
|
|
|
|
|
|
Page |
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
4 |
|
|
|
|
5 |
|
|
|
|
6 |
|
|
|
|
7 |
|
|
|
|
46 |
|
|
|
|
72 |
|
|
|
|
77 |
|
|
|
|
|
|
|
|
|
78 |
|
|
|
|
79 |
|
|
|
|
80 |
|
|
|
|
81 |
|
|
|
|
82 |
|
2
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars, Except Par Value)
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
December 31, |
|
|
2009 |
|
2008 |
|
|
(Unaudited) |
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and temporary cash investments |
|
$ |
1,605 |
|
|
$ |
940 |
|
Restricted cash |
|
|
144 |
|
|
|
131 |
|
Receivables, net |
|
|
3,923 |
|
|
|
2,897 |
|
Inventories |
|
|
4,576 |
|
|
|
4,637 |
|
Income taxes receivable |
|
|
81 |
|
|
|
197 |
|
Deferred income taxes |
|
|
150 |
|
|
|
98 |
|
Prepaid expenses and other |
|
|
386 |
|
|
|
550 |
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
10,865 |
|
|
|
9,450 |
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, at cost |
|
|
29,863 |
|
|
|
28,103 |
|
Accumulated depreciation |
|
|
(5,632 |
) |
|
|
(4,890 |
) |
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
24,231 |
|
|
|
23,213 |
|
|
|
|
|
|
|
|
|
|
Intangible assets, net |
|
|
229 |
|
|
|
224 |
|
Deferred charges and other assets, net |
|
|
1,480 |
|
|
|
1,530 |
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
36,805 |
|
|
$ |
34,417 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Current portion of debt and capital lease obligations |
|
$ |
213 |
|
|
$ |
312 |
|
Accounts payable |
|
|
5,756 |
|
|
|
4,446 |
|
Accrued expenses |
|
|
633 |
|
|
|
374 |
|
Taxes other than income taxes |
|
|
667 |
|
|
|
592 |
|
Income taxes payable |
|
|
64 |
|
|
|
|
|
Deferred income taxes |
|
|
424 |
|
|
|
485 |
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
7,757 |
|
|
|
6,209 |
|
|
|
|
|
|
|
|
|
|
Debt and capital lease obligations, less current portion |
|
|
7,162 |
|
|
|
6,264 |
|
|
|
|
|
|
|
|
|
|
Deferred income taxes |
|
|
3,872 |
|
|
|
4,163 |
|
|
|
|
|
|
|
|
|
|
Other long-term liabilities |
|
|
2,124 |
|
|
|
2,161 |
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
Common stock, $0.01 par value; 1,200,000,000 shares authorized;
673,501,593 and 627,501,593 shares issued |
|
|
7 |
|
|
|
6 |
|
Additional paid-in capital |
|
|
7,975 |
|
|
|
7,190 |
|
Treasury stock, at cost; 110,454,703 and 111,290,436 common shares |
|
|
(6,830 |
) |
|
|
(6,884 |
) |
Retained earnings |
|
|
14,670 |
|
|
|
15,484 |
|
Accumulated other comprehensive income (loss) |
|
|
68 |
|
|
|
(176 |
) |
|
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
15,890 |
|
|
|
15,620 |
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
36,805 |
|
|
$ |
34,417 |
|
|
|
|
|
|
|
|
|
|
See Condensed Notes to Consolidated Financial Statements.
3
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars, Except per Share Amounts)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
Operating revenues (1) |
|
$ |
19,489 |
|
|
$ |
35,960 |
|
|
$ |
51,238 |
|
|
$ |
100,545 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
18,104 |
|
|
|
32,506 |
|
|
|
46,275 |
|
|
|
91,848 |
|
Operating expenses |
|
|
923 |
|
|
|
1,136 |
|
|
|
2,778 |
|
|
|
3,383 |
|
Retail selling expenses |
|
|
182 |
|
|
|
201 |
|
|
|
522 |
|
|
|
579 |
|
General and administrative expenses |
|
|
167 |
|
|
|
169 |
|
|
|
435 |
|
|
|
421 |
|
Depreciation and amortization expense |
|
|
389 |
|
|
|
370 |
|
|
|
1,156 |
|
|
|
1,106 |
|
Asset impairment loss |
|
|
417 |
|
|
|
43 |
|
|
|
575 |
|
|
|
43 |
|
Gain on sale of Krotz Springs Refinery |
|
|
|
|
|
|
(305 |
) |
|
|
|
|
|
|
(305 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
20,182 |
|
|
|
34,120 |
|
|
|
51,741 |
|
|
|
97,075 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(693 |
) |
|
|
1,840 |
|
|
|
(503 |
) |
|
|
3,470 |
|
Other income (expense), net |
|
|
9 |
|
|
|
36 |
|
|
|
(16 |
) |
|
|
71 |
|
Interest and debt expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incurred |
|
|
(149 |
) |
|
|
(112 |
) |
|
|
(386 |
) |
|
|
(335 |
) |
Capitalized |
|
|
19 |
|
|
|
31 |
|
|
|
95 |
|
|
|
74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income tax expense (benefit) |
|
|
(814 |
) |
|
|
1,795 |
|
|
|
(810 |
) |
|
|
3,280 |
|
Income tax expense (benefit) |
|
|
(185 |
) |
|
|
643 |
|
|
|
(236 |
) |
|
|
1,133 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(629 |
) |
|
$ |
1,152 |
|
|
$ |
(574 |
) |
|
$ |
2,147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share |
|
$ |
(1.12 |
) |
|
$ |
2.20 |
|
|
$ |
(1.08 |
) |
|
$ |
4.07 |
|
Weighted-average common shares outstanding (in
millions) |
|
|
561 |
|
|
|
522 |
|
|
|
534 |
|
|
|
526 |
|
|
Earnings (loss) per common share assuming
dilution |
|
$ |
(1.12 |
) |
|
$ |
2.18 |
|
|
$ |
(1.08 |
) |
|
$ |
4.02 |
|
Weighted-average common shares outstanding assuming dilution (in millions) |
|
|
561 |
|
|
|
529 |
|
|
|
534 |
|
|
|
535 |
|
|
Dividends per common share |
|
$ |
0.15 |
|
|
$ |
0.15 |
|
|
$ |
0.45 |
|
|
$ |
0.42 |
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental information: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Includes excise taxes on sales by our U.S.
retail system |
|
$ |
226 |
|
|
$ |
207 |
|
|
$ |
659 |
|
|
$ |
605 |
|
See Condensed Notes to Consolidated Financial Statements.
4
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
2009 |
|
2008 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(574 |
) |
|
$ |
2,147 |
|
Adjustments to reconcile net income (loss) to net cash provided by operating
activities: |
|
|
|
|
|
|
|
|
Depreciation and amortization expense |
|
|
1,156 |
|
|
|
1,106 |
|
Asset impairment loss |
|
|
575 |
|
|
|
43 |
|
Gain on sale of Krotz Springs Refinery |
|
|
|
|
|
|
(305 |
) |
Stock-based compensation expense |
|
|
35 |
|
|
|
36 |
|
Deferred income tax expense (benefit) |
|
|
(302 |
) |
|
|
260 |
|
Changes in current assets and current liabilities |
|
|
1,154 |
|
|
|
381 |
|
Changes in deferred charges and credits and other operating activities, net |
|
|
(104 |
) |
|
|
(148 |
) |
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
1,940 |
|
|
|
3,520 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(1,820 |
) |
|
|
(1,894 |
) |
Deferred turnaround and catalyst costs |
|
|
(301 |
) |
|
|
(279 |
) |
Purchase of certain VeraSun Energy Corporation facilities |
|
|
(556 |
) |
|
|
|
|
Return of investment in Cameron Highway Oil Pipeline Company |
|
|
18 |
|
|
|
11 |
|
Proceeds from the sale of Krotz Springs Refinery |
|
|
|
|
|
|
463 |
|
Contingent payment in connection with acquisition |
|
|
|
|
|
|
(25 |
) |
Minor acquisitions |
|
|
(29 |
) |
|
|
(144 |
) |
Other investing activities, net |
|
|
5 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(2,683 |
) |
|
|
(1,852 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Proceeds from the sale of common stock, net of issuance costs |
|
|
799 |
|
|
|
|
|
Non-bank debt: |
|
|
|
|
|
|
|
|
Borrowings |
|
|
998 |
|
|
|
|
|
Repayments |
|
|
(209 |
) |
|
|
(374 |
) |
Bank credit agreements: |
|
|
|
|
|
|
|
|
Borrowings |
|
|
|
|
|
|
296 |
|
Repayments |
|
|
|
|
|
|
(296 |
) |
Accounts receivable sales program: |
|
|
|
|
|
|
|
|
Proceeds from sale of receivables |
|
|
500 |
|
|
|
|
|
Repayments |
|
|
(500 |
) |
|
|
|
|
Purchase of common stock for treasury |
|
|
|
|
|
|
(774 |
) |
Issuance of common stock in connection with employee benefit plans |
|
|
7 |
|
|
|
14 |
|
Effect of tax deduction in excess of (less than) recognized stock-based
compensation cost |
|
|
(2 |
) |
|
|
15 |
|
Common stock dividends |
|
|
(239 |
) |
|
|
(221 |
) |
Debt issuance costs |
|
|
(8 |
) |
|
|
|
|
Other financing activities |
|
|
(3 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
1,343 |
|
|
|
(1,342 |
) |
|
|
|
|
|
|
|
|
|
Effect of foreign exchange rate changes on cash |
|
|
65 |
|
|
|
(23 |
) |
|
|
|
|
|
|
|
|
|
Net increase in cash and temporary cash investments |
|
|
665 |
|
|
|
303 |
|
Cash and temporary cash investments at beginning of period |
|
|
940 |
|
|
|
2,464 |
|
|
|
|
|
|
|
|
|
|
Cash and temporary cash investments at end of period |
|
$ |
1,605 |
|
|
$ |
2,767 |
|
|
|
|
|
|
|
|
|
|
See Condensed Notes to Consolidated Financial Statements.
5
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of Dollars)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
Net income (loss) |
|
$ |
(629 |
) |
|
$ |
1,152 |
|
|
$ |
(574 |
) |
|
$ |
2,147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustment |
|
|
214 |
|
|
|
(105 |
) |
|
|
324 |
|
|
|
(167 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and other postretirement benefits
net (gain) loss reclassified into income, net of
income
tax expense of $1, $-, $1, and $1 |
|
|
(1 |
) |
|
|
|
|
|
|
(1 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) on derivative instruments
designated and qualifying as cash flow hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) arising during the period,
net of income
tax (expense) benefit of $(12), $(34),
$(46), and $20 |
|
|
24 |
|
|
|
62 |
|
|
|
87 |
|
|
|
(38 |
) |
Net (gain) loss reclassified into income, net
of income
tax expense (benefit) of $29, $(9), $89, and
$(18) |
|
|
(54 |
) |
|
|
16 |
|
|
|
(166 |
) |
|
|
33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) on cash flow hedges |
|
|
(30 |
) |
|
|
78 |
|
|
|
(79 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss) |
|
|
183 |
|
|
|
(27 |
) |
|
|
244 |
|
|
|
(173 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss) |
|
$ |
(446 |
) |
|
$ |
1,125 |
|
|
$ |
(330 |
) |
|
$ |
1,974 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 nine
months ended September 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 nine months ended September 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.
See Note 3 for a discussion of the presentation in the statements of income of the results of
operations of the Krotz Springs Refinery, which was sold effective July 1, 2008.
We have evaluated subsequent events that occurred after September 30, 2009 through the filing of
this Form 10-Q on November 5, 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 in 2008 and 2009 have been reclassified to conform to
the current 2009 presentation. The primary reclassification relates to the presentation of asset impairment
losses (discussed in Note 4) on a separate line in the consolidated statements of income due to the
materiality of the amount in the third quarter of 2009. For comparability with this presentation,
asset impairment losses resulting from the cancellation of certain capital projects classified as
construction in progress of
7
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
$158 million for the first six months of 2009 and $43 million for both the three months and nine months
ended September 30, 2008 have been reclassified from operating expenses and reflected on a separate
line. The asset impairment losses are also presented on a separate line in the consolidated
statements of cash flows, which resulted in
an adjustment to capital expenditures
previously reported for the nine months ended September 30, 2008.
2. ACCOUNTING PRONOUNCEMENTS
Financial
Accounting Standards Board (FASB) Accounting Standards
Codification (the Codification
or ASC)
The Codification is the single 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. The
Codification became effective for interim and annual periods ending after September 15, 2009 and
superseded all previously existing non-SEC accounting and reporting standards. All other
non-grandfathered non-SEC accounting literature not included in the Codification is
nonauthoritative. Commencing with the quarter ended September 30, 2009, all of our references to
GAAP now use the specific Codification Topic or Section rather than prior accounting and reporting
standards. The Codification did not change existing GAAP and, therefore, did not affect our
financial position or results of operations.
Fair Value Measurements and Disclosures
In February 2008, ASC Topic 820, Fair Value Measurements and Disclosures, was modified to delay
the effective date for applying fair value measurement disclosures for nonfinancial assets and
nonfinancial liabilities until fiscal years beginning after November 15, 2008. The implementation
of this provision of Topic 820 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 10.
In August 2009, the FASB modified Topic 820 to address the measurement of liabilities at fair value
in circumstances in which a quoted price in an active market for the identical liability is not
available. In such circumstances, a reporting entity is required to measure fair value using one or
more of the following techniques: (i) a valuation technique that uses the quoted price of the
identical liability when traded as an asset, or the quoted prices for similar liabilities or
similar liabilities when traded as assets; or (ii) another valuation technique that is consistent
with Topic 820. The FASB also clarified that when estimating the fair value of the liability, a
reporting entity is not required to include a separate input or adjustment to other inputs relating
to the existence of a restriction that prevents the transfer of the liability. This modification
also clarified that both a quoted price in an active market for the identical liability at the
measurement date and the quoted price for the identical liability when traded as an asset in an
active market when no adjustments to the quoted price of the asset are required are Level 1 fair
value measurements. This guidance is effective for the first reporting period (including interim
periods) beginning after issuance, the adoption of which in the fourth quarter of 2009 is not
expected to materially affect our financial position or results of operations.
8
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Business Combinations
In December 2007, ASC Topic 805, Business Combinations, was issued to improve the financial
reporting of business combinations and clarify the accounting for these transactions. This guidance
in Topic 805 is 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. In April 2009, Topic 805 was modified 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. These provisions 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.
Due to the adoption of the new business combination provisions of Topic 805 effective January 1,
2009, these provisions were applied to the acquisition of certain ethanol plants from VeraSun
Energy Corporation (VeraSun, with the acquisition referred to as the VeraSun Acquisition) in the
second quarter of 2009, which is discussed in Note 3.
Noncontrolling Interests in Consolidated Financial Statements
In December 2007, ASC Topic 810, Consolidation, was modified to provide guidance for the
accounting and reporting of noncontrolling interests, changes in controlling interests, and the
deconsolidation of subsidiaries. In addition, this modification provides that an entity shall
disclose pro forma net income and pro forma earnings per share if an entity has one or more
noncontrolling interests. The adoption of these provisions of Topic 810 effective January 1, 2009
has not affected our financial position or results of operations.
Derivatives and Hedging
In March 2008, ASC Topic 815, Derivatives and Hedging, was modified to establish disclosure
requirements for derivative instruments and for hedging activities. The required disclosures
include 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. These
disclosures are effective for fiscal years, and interim periods within those fiscal years,
beginning on or after November 15, 2008. The adoption of these provisions of Topic 815 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 11.
Earnings Per Share
In June 2008, the FASB modified ASC Topic 260, Earnings Per Share, to address 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 Topic 260. These Codification amendments are effective for fiscal
years, and interim periods within those fiscal years, beginning 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 these provisions. The adoption of
these provisions effective January 1, 2009 did not have any effect on the calculation of basic
earnings per common share for the three and nine months ended September 30, 2009, but did reduce
basic earnings per common share from the $2.21 and $4.08 amounts originally reported for the three
and nine months ended September 30, 2008, respectively, to $2.20 and $4.07, respectively. The
calculation is provided in Note 8.
9
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Equity Method Investments
In November 2008, the FASB modified ASC Topic 323, InvestmentsEquity Method and Joint Ventures,
to provide 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. These provisions are effective for fiscal years beginning on or after December 15,
2008, and interim periods within those fiscal years. These provisions are to be applied
prospectively to equity method investments acquired after the effective date, and earlier
application is not permitted. Because we have not acquired any equity method investments during
2009, the adoption of these provisions effective January 1, 2009 has not affected our financial
position or results of operations.
Compensation Retirement Benefits
In December 2008, the FASB modified ASC Topic 715, CompensationRetirement Benefits, to require
enhanced 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.
These disclosures are effective for fiscal years ending after December 15, 2009, with earlier
application permitted. Since only disclosures are affected by these requirements, the adoption of
these provisions will not affect our financial position or results of operations.
Financial Instruments
In April 2009, the provisions of ASC Topic 825, Financial Instruments, were modified 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. This provision is
effective for interim reporting periods ending after June 15, 2009. Early adoption is permitted for
periods ending after March 15, 2009 if an entity also elects to apply the early adoption provisions
of certain other fair value modifications in Topic 820, Fair Value Measurements and Disclosures,
and Topic 320, InvestmentsDebt and Equity Securities. We adopted all of these provisions in the
first quarter of 2009, none of which has affected our financial position or results of operations.
However, the adoption of the modified provisions of Topic 825 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 6. 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.
Subsequent Events
In May 2009, ASC Topic 855, Subsequent Events, was issued, which established 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, guidance was provided
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 occur after the balance
sheet date. The provisions of Topic 855 are to be applied
10
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
prospectively and are effective for interim or annual financial periods ending after June 15, 2009.
The adoption of the provisions of Topic 855 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. According to ASC Topic 105, Generally Accepted Accounting
Principles, Statement No. 166 shall continue to represent authoritative guidance until it is
integrated into the Codification. Statement No. 166 amends and clarifies provisions related to the
transfer of financial assets 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.
FASB Statement No. 167
In June 2009, the FASB issued Statement No. 167, Amendments to FASB Interpretation No. 46(R).
According to ASC Topic 105, Statement No. 167 shall continue to represent authoritative guidance
until it is integrated into the Codification. Statement No. 167 amends provisions related to
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.
3. ACQUISITION AND DISPOSITION
Acquisition of VeraSun
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. We incurred approximately $10 million of acquisition-related costs that
were recognized in general and administrative expenses in the consolidated statement of income for
the nine months ended September 30, 2009.
11
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The acquired ethanol business involves the production and marketing of ethanol and its co-products,
including distillers grains. The ethanol operations are reflected as a reportable segment
in Note 12, the operations of which will complement our existing clean motor fuels business. The
acquisition cost was funded with part of the proceeds from a $1 billion issuance of notes in March
2009, which is discussed in Note 6.
An independent appraisal of the assets acquired in the VeraSun Acquisition has been 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. As a result, pro forma information for the
three months ended September 30, 2009 presented below represents actual results of operations. The
operating revenues and net income associated with the acquired ethanol plants included in our
consolidated statements of income for the three and nine months ended September 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 financial information is not
necessarily indicative of the results of future operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30, |
|
September 30, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
Actual amounts from acquired business: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
410 |
|
|
|
N/A |
|
|
$ |
673 |
|
|
|
N/A |
|
Net income |
|
|
29 |
|
|
|
N/A |
|
|
|
42 |
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated pro forma: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
|
19,489 |
|
|
$ |
36,429 |
|
|
|
51,461 |
|
|
$ |
101,756 |
|
Net income (loss) |
|
|
(629 |
) |
|
|
1,078 |
|
|
|
(581 |
) |
|
|
2,082 |
|
Earnings (loss) per common share assuming dilution |
|
|
(1.12 |
) |
|
|
2.04 |
|
|
|
(1.09 |
) |
|
|
3.89 |
|
12
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Sale of Krotz Springs Refinery
Effective July 1, 2008, we sold our refinery in Krotz Springs, Louisiana 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 in the consolidated
statements of income for the three and nine months ended September 30, 2008. Under the offtake
agreement, we agreed to (i) purchase all refined products from the Krotz Springs Refinery for three
months after the effective date of the sale, (ii) purchase certain products for an additional one
to five years after the expiration of the initial three-month period of the agreement, and (iii)
provide certain refined products to Alon that are not produced at the Krotz Springs Refinery for an
initial term of 15 months and thereafter until terminated by either party.
The sale resulted in a pre-tax gain of $305 million ($170 million after tax), which is presented in
gain on sale of Krotz Springs Refinery in the consolidated statements of income for the three and
nine months ended September 30, 2008. Cash proceeds, net of certain costs related to the sale, were
$463 million, including approximately $135 million from the sale of working capital to Alon
primarily related to the sale of inventory by our marketing and supply subsidiary.
In addition to the cash consideration received, we also received contingent consideration in the
form of a three-year earn-out agreement based on certain product margins. This earn-out agreement
qualified as a derivative contract and had a fair value of $171 million as of July 1, 2008. We
hedged the risk of a decline in the referenced product margins by entering into certain commodity
derivative contracts. On August 27, 2009, we settled the earn-out agreement with Alon for $35
million, of which $18 million was received on the settlement date and the remaining amount will be
received in eight payments of $2.2 million each quarter beginning in the fourth quarter of 2009. In
connection with the settlement of the earn-out agreement, we effectively closed our positions in
the related commodity derivative contracts during the third quarter of 2009, as a result of which
we locked in $175 million of cash proceeds on those contracts, approximately $80 million of which
was received as of September 30, 2009 with the remaining proceeds to be received in varying monthly
amounts through July 2011. As such, the total amount earned on the Alon earn-out agreement,
including the related commodity derivative contracts, was $210 million.
Financial information as of July 1, 2008 related to the Krotz Springs Refinery assets and
liabilities sold is summarized as follows (in millions):
|
|
|
|
|
|
Current assets (primarily inventory) |
|
$ |
138 |
|
Property, plant and equipment, net |
|
|
153 |
|
Goodwill |
|
|
42 |
|
Deferred charges and other assets, net |
|
|
4 |
|
|
|
|
|
|
Assets held for sale |
|
$ |
337 |
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
10 |
|
|
|
|
|
|
Liabilities related to assets held for sale |
|
$ |
10 |
|
|
|
|
|
|
13
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. ASSET IMPAIRMENTS
Impairment of Long-Lived Assets
Long-lived assets are 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.
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 second half 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 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 nine months of 2009, thereby impacting 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 September 30, 2009, as narrow heavy sour crude oil differentials made the
refinery uneconomical to operate. The Aruba Refinery was shut down in July 2009 and is expected to
continue to be shut down until market conditions improve. We are continuing to evaluate potential
alternatives 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 and remains shut down. In
September 2009, we announced the shutdown of our coker and gasification units at our Delaware City
Refinery also due to economic reasons. The coker unit is expected to remain shut down until
economics improve and the gasification unit has been permanently shut down. As a result of these
factors, we readdressed the potential impairment of all of our facilities (excluding the Delaware
City gasification unit) as of September 30, 2009 based on an assumption that we would operate these
facilities in the future, 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 September 30, 2009.
However, due to the permanent shutdown of the gasification unit at the Delaware City Refinery,
we recorded a pre-tax loss of approximately $280 million related to the abandonment of that unit.
Capital Project Write-offs
Due to the impact of the continuing economic slowdown on refining industry fundamentals, we further
evaluated the recoverability of all of our capital projects currently classified as construction
in progress during the third quarter of 2009. This is a continuation of an ongoing process that
had commenced during the second half of 2008. As a result of this assessment, certain additional
capital projects were permanently cancelled, resulting in write-offs of $137 million of project
costs for the three months ended
14
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
September 30, 2009 (of which approximately $60 million was for
projects related to the gasification unit at our Delaware City Refinery). This amount, combined
with capital projects written off earlier in 2009, has resulted in total write-offs of capital
projects of $295 million for the nine months ended September 30, 2009. During the three months and
nine months ended September 30, 2008, we wrote off $43 million of capital projects, the amount of
which has been reclassified from operating expenses and presented separately for comparability with
the 2009 presentation.
In addition to capital projects that have been written off, 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
temporarily suspended until market conditions and cash flows improve. As of September 30, 2009,
approximately $1.0 billion of costs had been incurred on these two projects. In addition, various
other projects with a total cost of approximately $600 million as of September 30, 2009 have also
been temporarily suspended. These suspended projects are included in our strategic plan, and the
costs incurred to date have not been written off. We believe that the overall market conditions and
our cash flows will improve in the future such that the completion and
recoverability of these temporarily suspended projects is probable.
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 additional potential asset impairments until
conditions improve. Changes in market conditions, as well as changes in assumptions used to test
for recoverability and to determine fair value, could result in additional significant impairment
charges in the future, thus affecting our earnings.
5. INVENTORIES
Inventories consisted of the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
December 31, |
|
|
2009 |
|
2008 |
|
Refinery feedstocks |
|
$ |
1,936 |
|
|
$ |
2,140 |
|
Refined products and blendstocks |
|
|
2,240 |
|
|
|
2,224 |
|
Ethanol feedstocks and products |
|
|
101 |
|
|
|
|
|
Convenience store merchandise |
|
|
94 |
|
|
|
90 |
|
Materials and supplies |
|
|
205 |
|
|
|
183 |
|
|
|
|
|
|
|
|
|
|
Inventories |
|
$ |
4,576 |
|
|
$ |
4,637 |
|
|
|
|
|
|
|
|
|
|
As of September 30, 2009 and December 31, 2008, the replacement cost (market value) of LIFO
inventories exceeded their LIFO carrying amounts by approximately $3.2 billion and $686 million,
respectively.
6. DEBT
Non-Bank 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) was received
from the holders prior to
15
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
September 15, 2009. A purchase notice was received related to $76 million
of the outstanding notes, which resulted in a charge of $6 million in the third quarter of 2009 to
write off a pro rata portion of unamortized fair value adjustment. We redeemed the $76 million of
notes at 100% of their principal amount plus accrued and unpaid interest to October 15, 2009, the
date of the payment of the purchase price.
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 $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.
Bank Credit Facilities
In October 2009, Lehman Brothers Bank, FSB, one of the participating banks under our $2.5 billion
revolving credit facility, failed to fund its loan commitment related to our borrowing under this facility discussed below.
Lehman Brothers aggregate commitment under the revolving credit facility was $84 million. As a
result, our borrowing capacity under that revolving credit facility has been reduced to $2.4 billion commencing in October 2009.
During the nine months ended September 30, 2009, we had no borrowings or repayments under our
revolving bank credit facilities. As of September 30, 2009, we had no borrowings outstanding under
our revolving bank credit facilities. In October 2009, we borrowed
and subsequently repaid approximately $40 million under our U.S. committed revolving bank credit facility.
As of September 30, 2009, we had $76 million of letters of credit outstanding under our uncommitted
short-term bank credit facilities and $113 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 September 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 nine months ended September 30, 2008, we borrowed and repaid $296 million under our
U.S. committed 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.
16
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 September 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):
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
December 31, |
|
|
2009 |
|
2008 |
|
Carrying amount |
|
$ |
7,338 |
|
|
$ |
6,537 |
|
Fair value |
|
|
8,335 |
|
|
|
6,462 |
|
7. 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 nine months ended September 30,
2009. During the nine months ended September 30, 2008, we purchased 14.6 million shares of our
common stock at a cost of $774 million in connection with the administration of our employee
benefit plans and common stock purchase programs authorized by our board of directors. During the
nine months ended September 30, 2009 and 2008, we issued 0.9 million shares and 1.3 million shares,
respectively, from treasury for our employee benefit plans.
Common Stock Dividends
On October 15, 2009, our board of directors declared a regular quarterly cash dividend of $0.15 per
common share payable on December 9, 2009 to holders of record at the close of business on November
11, 2009.
17
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
8. 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 September 30, |
|
|
2009 |
|
2008 |
|
|
Restricted |
|
Common |
|
Restricted |
|
Common |
|
|
Stock |
|
Stock |
|
Stock |
|
Stock |
|
Earnings (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
|
|
|
$ |
(629 |
) |
|
|
|
|
|
$ |
1,152 |
|
Less dividends paid: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock |
|
|
|
|
|
|
84 |
|
|
|
|
|
|
|
78 |
|
Nonvested restricted stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undistributed earnings (loss) |
|
|
|
|
|
$ |
(713 |
) |
|
|
|
|
|
$ |
1,074 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average common shares outstanding |
|
|
2 |
|
|
|
561 |
|
|
|
1 |
|
|
|
522 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributed earnings |
|
$ |
0.15 |
|
|
$ |
0.15 |
|
|
$ |
0.14 |
|
|
$ |
0.15 |
|
Undistributed earnings (loss) |
|
|
|
|
|
|
(1.27 |
) |
|
|
2.05 |
|
|
|
2.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total earnings (loss) per common share (1) |
|
$ |
0.15 |
|
|
$ |
(1.12 |
) |
|
$ |
2.19 |
|
|
$ |
2.20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share assuming
dilution: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
|
|
|
$ |
(629 |
) |
|
|
|
|
|
$ |
1,152 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average common shares outstanding |
|
|
|
|
|
|
561 |
|
|
|
|
|
|
|
522 |
|
Common equivalent shares (2): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6 |
|
Performance awards and other benefit plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average common shares outstanding assuming dilution |
|
|
|
|
|
|
561 |
|
|
|
|
|
|
|
529 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share assuming
dilution |
|
|
|
|
|
$ |
(1.12 |
) |
|
|
|
|
|
$ |
2.18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The basic earnings per common share amount for the three months ended September 30, 2008
changed from the $2.21 originally reported as a result of the adoption of certain
modifications that require our restricted stock to be treated as a participating security in
calculating basic earnings per common share effective January 1, 2009, as discussed in Note 2. |
|
(2) |
|
Common equivalent shares were excluded from the computation of diluted earnings (loss) per common share for
the three months ended September 30, 2009 because the effect of including such shares would be
antidilutive. |
18
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
2009 |
|
2008 |
|
|
Restricted |
|
Common |
|
Restricted |
|
Common |
|
|
Stock |
|
Stock |
|
Stock |
|
Stock |
|
Earnings (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
|
|
|
$ |
(574 |
) |
|
|
|
|
|
$ |
2,147 |
|
Less dividends paid: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock |
|
|
|
|
|
|
238 |
|
|
|
|
|
|
|
221 |
|
Nonvested restricted stock |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undistributed earnings (loss) |
|
|
|
|
|
$ |
(813 |
) |
|
|
|
|
|
$ |
1,926 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average common shares outstanding |
|
|
2 |
|
|
|
534 |
|
|
|
1 |
|
|
|
526 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributed earnings |
|
$ |
0.44 |
|
|
$ |
0.45 |
|
|
$ |
0.41 |
|
|
$ |
0.42 |
|
Undistributed earnings (loss) |
|
|
|
|
|
|
(1.53 |
) |
|
|
3.65 |
|
|
|
3.65 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total earnings (loss) per common share (1) |
|
$ |
0.44 |
|
|
$ |
(1.08 |
) |
|
$ |
4.06 |
|
|
$ |
4.07 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share assuming
dilution: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
|
|
|
$ |
(574 |
) |
|
|
|
|
|
$ |
2,147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average common shares outstanding |
|
|
|
|
|
|
534 |
|
|
|
|
|
|
|
526 |
|
Common equivalent shares (2): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8 |
|
Performance awards and other benefit plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average common shares outstanding assuming dilution |
|
|
|
|
|
|
534 |
|
|
|
|
|
|
|
535 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share assuming
dilution |
|
|
|
|
|
$ |
(1.08 |
) |
|
|
|
|
|
$ |
4.02 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The basic earnings per common share amount for the nine months ended September 30, 2008
changed from the $4.08 originally reported as a result of the adoption of certain
modifications that require our restricted stock to be treated as a participating security in
calculating basic earnings per common share effective January 1, 2009, as discussed in Note 2. |
|
(2) |
|
Common equivalent shares were excluded from the computation of diluted earnings (loss) per common share for
the nine months ended September 30, 2009 because the effect of including such shares would be
antidilutive. |
19
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 antidilutive (in millions). As indicated above, common equivalent
shares, which represent primarily stock options, were excluded as a result of the net losses
reported for the three and nine months ended September 30, 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 September 30, |
|
Nine Months Ended September 30, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
Common equivalent shares |
|
|
4 |
|
|
|
|
|
|
|
4 |
|
|
|
|
|
Stock options |
|
|
10 |
|
|
|
7 |
|
|
|
10 |
|
|
|
7 |
|
9. SUPPLEMENTAL CASH FLOW INFORMATION
In order to determine net cash provided by operating activities, net income (loss) is adjusted by,
among other things, changes in current assets and current liabilities as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
2009 |
|
2008 |
|
Decrease (increase) in current assets: |
|
|
|
|
|
|
|
|
Restricted cash |
|
$ |
(13 |
) |
|
$ |
(90 |
) |
Receivables, net |
|
|
(966 |
) |
|
|
1,120 |
|
Inventories |
|
|
198 |
|
|
|
(842 |
) |
Income taxes receivable |
|
|
137 |
|
|
|
|
|
Prepaid expenses and other |
|
|
119 |
|
|
|
(6 |
) |
Increase (decrease) in current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
|
1,466 |
|
|
|
476 |
|
Accrued expenses |
|
|
94 |
|
|
|
32 |
|
Taxes other than income taxes |
|
|
54 |
|
|
|
(77 |
) |
Income taxes payable |
|
|
65 |
|
|
|
(232 |
) |
|
|
|
|
|
|
|
|
|
Changes in current assets and current liabilities |
|
$ |
1,154 |
|
|
$ |
381 |
|
|
|
|
|
|
|
|
|
|
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; |
|
|
|
amounts accrued for capital expenditures, deferred turnaround and catalyst costs,
and contingent earn-out payments are reflected in investing activities in the consolidated
statements of cash flows when such amounts are paid; |
|
|
|
amounts accrued for common stock purchases in the open market that are not settled
as of the balance sheet date are reflected in financing activities in the consolidated
statements of cash flows when the purchases are settled and paid; |
20
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
|
|
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 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 nine months ended September 30, 2009 and 2008.
Cash flows related to interest and income taxes were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
2009 |
|
2008 |
|
Interest paid in excess of amount capitalized |
|
$ |
232 |
|
|
$ |
187 |
|
Income taxes paid (net of tax refunds received) |
|
|
(134 |
) |
|
|
1,092 |
|
10. FAIR VALUE MEASUREMENTS
A fair value hierarchy (Level 1, Level 2, or Level 3) is used to categorize fair value amounts
based on the quality of inputs used to measure fair value. Accordingly, 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 tables below present information (dollars in millions) about our financial assets and
liabilities measured and recorded at fair value on a recurring basis and indicate the fair value
hierarchy of the inputs utilized by us to determine the fair values as of September 30, 2009 and
December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
|
|
Quoted |
|
Significant |
|
|
|
|
|
|
Prices |
|
Other |
|
Significant |
|
|
|
|
in Active |
|
Observable |
|
Unobservable |
|
Total as of |
|
|
Markets |
|
Inputs |
|
Inputs |
|
September 30, |
|
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
2009 |
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative contracts |
|
$ |
44 |
|
|
$ |
490 |
|
|
$ |
|
|
|
$ |
534 |
|
Nonqualified benefit plans |
|
|
106 |
|
|
|
|
|
|
|
|
|
|
|
106 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative contracts |
|
|
149 |
|
|
|
11 |
|
|
|
|
|
|
|
160 |
|
Certain nonqualified benefit plans |
|
|
32 |
|
|
|
|
|
|
|
|
|
|
|
32 |
|
21
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. 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, was measured at fair value using a
discounted cash flow model and was categorized in Level 3 of the fair value hierarchy
through July 2009. Significant inputs to the model included expected payments and discount
rates that considered the effects of both credit risk and the time value of money. On
August 27, 2009, we settled the Alon earn-out agreement as discussed in Note 3. We have
elected not to apply the fair value option to this settlement receivable. |
Cash received from brokers of $41 million, resulting from the equity in broker accounts covered by
master netting arrangements exceeding the minimum margin requirements for such accounts, is netted
against 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.
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.
22
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 nine months ended
September 30, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
Balance at beginning of period |
|
$ |
38 |
|
|
$ |
|
|
|
$ |
13 |
|
|
$ |
|
|
Alon earn-out agreement (see Note 3) |
|
|
(33 |
) |
|
|
171 |
|
|
|
(33 |
) |
|
|
171 |
|
Net realized and unrealized
gains (losses) included in earnings |
|
|
(5 |
) |
|
|
(14 |
) |
|
|
20 |
|
|
|
(14 |
) |
Transfers in and/or out of Level 3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of period |
|
$ |
|
|
|
$ |
157 |
|
|
$ |
|
|
|
$ |
157 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The above realized and unrealized gains and losses, which are reported in other income (expense),
net in the consolidated statements of income, related to the Alon earn-out agreement that was
settled in August 2009, as discussed above. These gains and losses were offset by the recognition
in other income (expense), net of losses and gains 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 prior to the settlement are included in the
commodity derivative contracts amounts reflected in the fair value table as of December 31, 2008
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,
and indicates the fair value hierarchy of the inputs utilized by us to determine the fair values as
of September 30, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
|
|
Quoted |
|
Significant |
|
|
|
|
|
|
Prices |
|
Other |
|
Significant |
|
|
|
|
in Active |
|
Observable |
|
Unobservable |
|
Total as of |
|
|
Markets |
|
Inputs |
|
Inputs |
|
September 30, |
|
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
2009 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations |
|
$ |
|
|
|
$ |
|
|
|
$ |
13 |
|
|
$ |
13 |
|
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.
23
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. 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 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. The cash flow effects of all of our
derivative contracts are reflected in operating activities in the consolidated statements
of cash flows for all periods presented.
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
commodity derivative 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 commodity derivative 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 September 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 September 30, 2009, we had the following outstanding commodity derivative 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) |
|
|
5,133 |
|
24
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 September 30, 2009, we had the following outstanding commodity derivative instruments that
were entered into to hedge forecasted purchases or sales of crude oil and refined products. The
information presents the volume of outstanding contracts by type of instrument and year of maturity
(volumes in thousands of barrels).
|
|
|
|
|
Derivative
Instrument / Maturity |
|
Contract Volumes |
|
Swaps long: |
|
|
|
|
2009 |
|
|
10,722 |
|
2010 |
|
|
24,810 |
|
Swaps short: |
|
|
|
|
2009 |
|
|
10,722 |
|
2010 |
|
|
24,810 |
|
Futures long (2009) |
|
|
1,218 |
|
25
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, and
(ii) manage price volatility in certain forecasted refinery feedstock, product, and grain
purchases, refined product sales, and natural gas purchases. In addition, through August 2009, we
used economic hedges to manage price volatility in the referenced product margins associated with
the Alon earn-out agreement, which was a separate contractual derivative that we entered into with
the sale of our Krotz Springs Refinery but which was settled in August 2009, as further discussed
in Note 3. Our objective in entering into economic hedges is consistent with the objectives
discussed above for fair value hedges and cash flow hedges. However, the economic hedges are not
designated as a fair value hedge or a cash flow hedge for accounting purposes, usually due to the
difficulty of establishing the required documentation at the date that the derivative instrument is
entered into that would allow us to achieve hedge deferral accounting. As of September 30, 2009,
we had the following outstanding commodity derivative 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 |
|
|
45,030 |
|
2010 |
|
|
107,194 |
|
2011 |
|
|
26,275 |
|
Swaps short: |
|
|
|
|
2009 |
|
|
20,458 |
|
2010 |
|
|
63,633 |
|
2011 |
|
|
11,025 |
|
Futures long: |
|
|
|
|
2009 |
|
|
222,053 |
|
2010 |
|
|
102,235 |
|
2009 (grain) |
|
|
3,705 |
|
2010 (grain) |
|
|
75 |
|
Futures short: |
|
|
|
|
2009 |
|
|
216,315 |
|
2010 |
|
|
101,388 |
|
2009 (grain) |
|
|
10,585 |
|
2010 (grain) |
|
|
4,495 |
|
Options long: |
|
|
|
|
2009 |
|
|
6 |
|
2010 |
|
|
511 |
|
Options short: |
|
|
|
|
2010 |
|
|
500 |
|
26
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Trading Activities
These represent commodity derivative instruments held or issued for trading purposes. Our objective
in entering into commodity derivative 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 September 30, 2009, we had the following outstanding
commodity derivative 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 |
|
|
6,502 |
|
2010 |
|
|
23,589 |
|
2011 |
|
|
3,000 |
|
Swaps short: |
|
|
|
|
2009 |
|
|
5,679 |
|
2010 |
|
|
27,946 |
|
2011 |
|
|
3,900 |
|
Futures long: |
|
|
|
|
2009 |
|
|
25,809 |
|
2010 |
|
|
4,318 |
|
2009 (natural gas) |
|
|
3,750 |
|
2010 (natural gas) |
|
|
100 |
|
Futures short: |
|
|
|
|
2009 |
|
|
25,859 |
|
2010 |
|
|
4,268 |
|
2009 (natural gas) |
|
|
3,750 |
|
2010 (natural gas) |
|
|
100 |
|
Options long: |
|
|
|
|
2009 |
|
|
40 |
|
Options short: |
|
|
|
|
2009 |
|
|
40 |
|
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.
27
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 September 30, 2009, we had
commitments to purchase $248 million of U.S. dollars. These commitments matured on or before
November 2, 2009, resulting in a $5 million loss in the fourth quarter of 2009.
28
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Fair Values of Derivative Instruments
The following tables provide information about the fair values of our derivative instruments as of
September 30, 2009 (in millions) and the line items in the balance sheet in which the fair values
are reflected. See Note 10 for additional information related to the fair values of our derivative
instruments. As indicated in Note 10, 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, which results in the
reflection of certain assets in liability accounts and certain liabilities in asset accounts. In
addition, in Note 10 we netted cash received from brokers attributable to excess margin against the
fair value of the commodity derivatives; this cash receipt 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
|
|
$ |
12 |
|
|
Receivables, net
|
|
$ |
5 |
|
Futures
|
|
Accrued expenses
|
|
|
60 |
|
|
Accrued expenses
|
|
|
52 |
|
Swaps
|
|
Receivables, net
|
|
|
315 |
|
|
Receivables, net
|
|
|
267 |
|
Swaps
|
|
Prepaid expenses
and other current
assets
|
|
|
1,025 |
|
|
Prepaid expenses
and other
current
assets
|
|
|
902 |
|
Swaps
|
|
Accrued expenses
|
|
|
3 |
|
|
Accrued expenses
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives designated as
hedging instruments
|
|
|
|
$ |
1,415 |
|
|
|
|
$ |
1,230 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
Futures
|
|
Receivables, net
|
|
$ |
23 |
|
|
Receivables, net
|
|
$ |
26 |
|
Futures
|
|
Accrued expenses
|
|
|
2,273 |
|
|
Accrued expenses
|
|
|
2,349 |
|
Swaps
|
|
Receivables, net
|
|
|
575 |
|
|
Receivables, net
|
|
|
430 |
|
Swaps
|
|
Prepaid expenses
and other
current
assets
|
|
|
1,254 |
|
|
Prepaid expenses
and other
current
assets
|
|
|
1,079 |
|
Swaps
|
|
Accrued expenses
|
|
|
13 |
|
|
Accrued expenses
|
|
|
24 |
|
Options
|
|
Prepaid expenses
and other
current
assets
|
|
|
1 |
|
|
Prepaid expenses
and other
current
assets
|
|
|
1 |
|
Options
|
|
Accrued expenses
|
|
|
|
|
|
Accrued expenses
|
|
|
|
|
Foreign currency contracts
|
|
Receivables, net
|
|
|
|
|
|
Accounts payable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives not designated
as hedging instruments
|
|
|
|
$ |
4,139 |
|
|
|
|
$ |
3,909 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
|
|
$ |
5,554 |
|
|
|
|
$ |
5,139 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
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 September 30, 2009, we had net receivables related to derivative instruments of $27 million
from counterparties in the refining industry and $271 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 nine months ended September
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 |
|
Nine |
|
|
|
|
|
Three |
|
Nine |
|
Three |
|
Nine |
|
|
|
|
|
|
Months |
|
Months |
|
|
|
|
|
Months |
|
Months |
|
Months |
|
Months |
|
|
|
|
|
|
Ended |
|
Ended |
|
|
|
|
|
Ended |
|
Ended |
|
Ended |
|
Ended |
|
|
|
|
|
|
September 30, 2009 |
|
|
|
|
|
September 30, 2009 |
|
September 30, 2009 |
|
Commodity contracts |
|
Cost of sales |
|
$ |
(5 |
) |
|
$ |
(94 |
) |
|
Cost of sales |
|
$ |
(3 |
) |
|
$ |
87 |
|
|
$ |
(8 |
) |
|
$ |
(7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
$ |
(5 |
) |
|
$ |
(94 |
) |
|
|
|
|
|
$ |
(3 |
) |
|
$ |
87 |
|
|
$ |
(8 |
) |
|
$ |
(7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.
|
30
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 |
|
Recognized in |
|
Recognized in |
Cash Flow |
|
OCI on |
|
Accumulated OCI |
|
from Accumulated |
|
Income on |
|
Income on |
Hedging |
|
Derivatives |
|
into Income |
|
OCI into Income |
|
Derivatives |
|
Derivatives |
Relationships |
|
(Effective Portion) |
|
(Effective Portion) |
|
(Effective Portion) |
|
(Ineffective Portion) |
|
(Ineffective Portion) (1) |
|
|
Three |
|
Nine |
|
|
|
|
|
Three |
|
Nine |
|
|
|
|
|
Three |
|
Nine |
|
|
Months |
|
Months |
|
|
|
|
|
Months |
|
Months |
|
|
|
|
|
Months |
|
Months |
|
|
Ended |
|
Ended |
|
|
|
|
|
Ended |
|
Ended |
|
|
|
|
|
Ended |
|
Ended |
|
|
September
30, 2009 |
|
|
|
|
|
September
30, 2009 |
|
|
|
|
|
September
30, 2009 |
|
Commodity contracts
(2) |
|
$ |
36 |
|
|
$ |
133 |
|
|
Cost of sales |
|
$ |
83 |
|
|
$ |
255 |
|
|
Cost of sales |
|
$ |
6 |
|
|
$ |
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
36 |
|
|
$ |
133 |
|
|
|
|
|
|
$ |
83 |
|
|
$ |
255 |
|
|
|
|
|
|
$ |
6 |
|
|
$ |
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
No component of the derivative instruments gains or losses was excluded from the assessment
of hedge effectiveness. |
|
(2) |
|
For the three and nine months ended September 30, 2009, cash flow hedges primarily related to
forward sales of distillates and associated forward purchases of crude oil, with $90 million
of cumulative after-tax gains on cash flow hedges remaining in accumulated other comprehensive
income as of September 30, 2009. We expect that a significant amount of the deferred gains at
September 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 nine months ended September
30, 2009, there were no amounts reclassified from accumulated other comprehensive income 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 |
|
Nine Months |
|
|
|
|
|
|
Ended |
|
Ended |
|
|
|
|
|
|
September
30, 2009 |
|
Commodity contracts |
|
Cost of sales |
|
$ |
(68 |
) |
|
$ |
(30 |
) |
Foreign currency contracts |
|
Cost of sales |
|
|
(9 |
) |
|
|
(25 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(77 |
) |
|
|
(55 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Alon earn-out agreement |
|
Other income (expense) |
|
|
(5 |
) |
|
|
20 |
|
Alon earn-out hedge
(commodity contracts) |
|
Other income (expense) |
|
|
1 |
|
|
|
(62 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4 |
) |
|
|
(42 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
$ |
(81 |
) |
|
$ |
(97 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
Nine Months |
|
|
|
|
|
|
Ended |
|
Ended |
|
|
|
|
|
|
September 30, 2009 |
|
Commodity contracts |
|
Cost of sales |
|
|
$ 9 |
|
|
$ |
125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
$ 9 |
|
|
$ |
125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. 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
September 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues from external customers |
|
$ |
16,932 |
|
|
$ |
2,147 |
|
|
$ |
410 |
|
|
$ |
|
|
|
$ |
19,489 |
|
Intersegment revenues |
|
|
1,388 |
|
|
|
|
|
|
|
47 |
|
|
|
|
|
|
|
1,435 |
|
Operating income (loss) |
|
|
(674 |
) |
|
|
111 |
|
|
|
49 |
|
|
|
(179 |
) |
|
|
(693 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues from external
customers |
|
|
32,903 |
|
|
|
3,057 |
|
|
|
|
|
|
|
|
|
|
|
35,960 |
|
Intersegment revenues |
|
|
2,296 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,296 |
|
Operating income (loss) |
|
|
1,913 |
|
|
|
107 |
|
|
|
|
|
|
|
(180 |
) |
|
|
1,840 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues from external customers |
|
|
44,817 |
|
|
|
5,748 |
|
|
|
673 |
|
|
|
|
|
|
|
51,238 |
|
Intersegment revenues |
|
|
3,676 |
|
|
|
|
|
|
|
76 |
|
|
|
|
|
|
|
3,752 |
|
Operating income (loss) |
|
|
(335 |
) |
|
|
232 |
|
|
|
71 |
|
|
|
(471 |
) |
|
|
(503 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues from external customers |
|
|
91,958 |
|
|
|
8,587 |
|
|
|
|
|
|
|
|
|
|
|
100,545 |
|
Intersegment revenues |
|
|
6,563 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,563 |
|
Operating income (loss) |
|
|
3,716 |
|
|
|
206 |
|
|
|
|
|
|
|
(452 |
) |
|
|
3,470 |
|
Total assets by reportable segment were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
December 31, |
|
|
2009 |
|
2008 |
|
Refining |
|
$ |
32,056 |
|
|
$ |
30,801 |
|
Retail |
|
|
1,863 |
|
|
|
1,818 |
|
Ethanol |
|
|
605 |
|
|
|
|
|
Corporate |
|
|
2,281 |
|
|
|
1,798 |
|
|
|
|
|
|
|
|
|
|
Total consolidated assets |
|
$ |
36,805 |
|
|
$ |
34,417 |
|
|
|
|
|
|
|
|
|
|
32
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. EMPLOYEE BENEFIT PLANS
The components of net periodic benefit cost related to our defined benefit plans were as follows
for the three and nine months ended September 30, 2009 and 2008 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement |
|
|
Pension Plans |
|
Benefit Plans |
|
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
Three months ended September 30: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
26 |
|
|
$ |
22 |
|
|
$ |
3 |
|
|
$ |
3 |
|
Interest cost |
|
|
19 |
|
|
|
19 |
|
|
|
6 |
|
|
|
7 |
|
Expected return on plan assets |
|
|
(27 |
) |
|
|
(26 |
) |
|
|
|
|
|
|
|
|
Amortization of: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service cost (credit) |
|
|
1 |
|
|
|
1 |
|
|
|
(5 |
) |
|
|
(2 |
) |
Net loss |
|
|
3 |
|
|
|
|
|
|
|
2 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
$ |
22 |
|
|
$ |
16 |
|
|
$ |
6 |
|
|
$ |
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
78 |
|
|
$ |
69 |
|
|
$ |
9 |
|
|
$ |
10 |
|
Interest cost |
|
|
59 |
|
|
|
57 |
|
|
|
19 |
|
|
|
21 |
|
Expected return on plan assets |
|
|
(81 |
) |
|
|
(78 |
) |
|
|
|
|
|
|
|
|
Amortization of: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service cost (credit) |
|
|
2 |
|
|
|
2 |
|
|
|
(14 |
) |
|
|
(7 |
) |
Net loss |
|
|
8 |
|
|
|
1 |
|
|
|
5 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
$ |
66 |
|
|
$ |
51 |
|
|
$ |
19 |
|
|
$ |
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During the nine months ended September 30, 2009 and 2008, we contributed $72 million and $110
million, respectively, to our qualified pension plans.
14. 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
September 30, 2009, we have no further commitments with respect to contingent earn-out agreements.
However, as discussed in Note 3, in July 2008 we received contingent consideration from Alon in the
form of a three-year earn-out agreement based on certain product margins, as partial consideration
for the sale of our Krotz Springs Refinery. On August 27, 2009, we settled this earn-out agreement
with Alon for $35 million, of which $18 million was received on the settlement date and the
remaining amount will be received in eight payments of $2.2 million each quarter beginning in the
fourth quarter of 2009.
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 insurance carriers under our insurance policies. We reached a settlement with the insurance
carriers on
33
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 extended through December 31, 2009 and
provided 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 and in
September 2009, Total completed its acquisition of Dows equity interest in TRN. Our obligations
under the Agreement have since been terminated.
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 (NAI) pursuant to which we sought 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 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.
Amounts deposited under the escrow
agreement, which totaled $114 million and $102 million as of September 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 $20 million related to dividends.
We have also challenged
approximately $35 million in foreign exchange payments made to the Central Bank of Aruba as
payments exempted under our tax
34
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
holiday, as well as other reasons.
Both the dividend tax and the foreign exchange payment matters were also
addressed in the arbitration proceedings discussed above.
On November 3, we received an interim First Partial Award from the NAI arbitral panel. The panels
ruling validated our tax holiday agreement, but the panel also ruled in favor of the GOA on our
dispute of the $35 million in foreign exchange payments previously made to the Central Bank of
Aruba. The panels decision did not, however, fully resolve the remaining two items in the
arbitration, the applicable dividend tax rate and the turnover tax. With respect to the dividend
tax, the panel ruled that the dividend tax was not a profit tax covered by the tax holiday
agreement, but the panel did not address the fact that Aruban companies with tax holidays are
subject to a 0% dividend withholding rate rather than the 5% rate alleged by the GOA. With respect
to the turnover tax, the panel did reject our contractual claims but it decided that our
non-contractual claims against the turnover tax merited further discussion with and review by the
panel before a final decision could be rendered. Prior to this interim decision, no expense or
liability had been recognized in our consolidated financial statements with respect to unfunded amounts.
In light of the now uncertain timing of any final resolution of these claims,
we have recorded a loss contingency accrual of approximately $140 million, including interest,
with respect to both the dividend and turnover taxes. We continue to believe that our remaining
claims against these taxes have significant merit, and intend to vigorously pursue these claims
through the arbitration proceedings and in on-island proceedings as well.
American Clean Energy and Security Act of 2009 and Clean Energy Jobs and American Power Act of 2009
On June 26, 2009, the U.S. House of Representatives narrowly approved the American Clean Energy and
Security Act of 2009, also known as the Waxman-Markey bill. On September 30, 2009, the U.S. Senate
Committee on Environment and Public Works introduced a similar bill in the Senate, the Clean Energy
Jobs and American Power Act of 2009, also known as the Kerry-Boxer bill. These bills, if passed by
Congress, would establish a national cap-and-trade program beginning in 2012 to address
greenhouse gas emissions and climate change. The Waxman-Markey bill 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, while the Kerry-Boxer
bill proposes a more accelerated timetable for carbon dioxide reductions. The
cap-and-trade program would require businesses that emit greenhouse gases to buy 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
would 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 a cap-and-trade bill (or whether such a bill will be passed by Congress), any new
federal restrictions on greenhouse gas emissions including a cap-and-trade program could
result in material increased compliance costs, additional operating restrictions for our business,
and an increase in the cost of the products we produce, which could have an adverse effect on our
financial position, results of operations, and liquidity.
35
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Litigation
MTBE Litigation
As of November 5, 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). Sixteen cases are pending in state court. We recently settled the City of
New York case, which had been set for trial in June 2009. The Village of Hempstead
and West Hempstead Water District cases will be set for
trial in the summer of 2010. Discovery is open in all
cases. We believe that we have strong defenses to all claims and are vigorously defending the
lawsuits.
We have recorded a loss contingency liability with respect to our MTBE litigation portfolio.
However, due to the inherent uncertainty of litigation, we believe that it is reasonably possible
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 November 5, 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 may rule on certain class certification
issues in 2009 or early 2010. 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 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.
36
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
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.
15. 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 September
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.
37
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Balance Sheet as of September 30, 2009
(unaudited, in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valero |
|
|
|
|
|
Other Non- |
|
|
|
|
|
|
Energy |
|
|
|
|
|
Guarantor |
|
|
|
|
|
|
Corporation |
|
PRG |
|
Subsidiaries |
|
Eliminations |
|
Consolidated |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and temporary cash investments |
|
$ |
298 |
|
|
$ |
|
|
|
$ |
1,307 |
|
|
$ |
|
|
|
$ |
1,605 |
|
Restricted cash |
|
|
23 |
|
|
|
1 |
|
|
|
120 |
|
|
|
|
|
|
|
144 |
|
Receivables, net |
|
|
|
|
|
|
38 |
|
|
|
3,885 |
|
|
|
|
|
|
|
3,923 |
|
Inventories |
|
|
|
|
|
|
521 |
|
|
|
4,055 |
|
|
|
|
|
|
|
4,576 |
|
Income taxes receivable |
|
|
58 |
|
|
|
|
|
|
|
81 |
|
|
|
(58 |
) |
|
|
81 |
|
Deferred income taxes |
|
|
|
|
|
|
|
|
|
|
150 |
|
|
|
|
|
|
|
150 |
|
Prepaid expenses and other |
|
|
|
|
|
|
8 |
|
|
|
378 |
|
|
|
|
|
|
|
386 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
379 |
|
|
|
568 |
|
|
|
9,976 |
|
|
|
(58 |
) |
|
|
10,865 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, at cost |
|
|
|
|
|
|
5,834 |
|
|
|
24,029 |
|
|
|
|
|
|
|
29,863 |
|
Accumulated depreciation |
|
|
|
|
|
|
(582 |
) |
|
|
(5,050 |
) |
|
|
|
|
|
|
(5,632 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
|
|
|
|
5,252 |
|
|
|
18,979 |
|
|
|
|
|
|
|
24,231 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible assets, net |
|
|
|
|
|
|
|
|
|
|
229 |
|
|
|
|
|
|
|
229 |
|
Investment in Valero Energy affiliates |
|
|
5,553 |
|
|
|
3,410 |
|
|
|
(701 |
) |
|
|
(8,262 |
) |
|
|
|
|
Long-term
notes receivable from affiliates |
|
|
16,745 |
|
|
|
|
|
|
|
|
|
|
|
(16,745 |
) |
|
|
|
|
Deferred income tax receivable |
|
|
1,351 |
|
|
|
|
|
|
|
|
|
|
|
(1,351 |
) |
|
|
|
|
Deferred charges and other assets, net |
|
|
132 |
|
|
|
134 |
|
|
|
1,214 |
|
|
|
|
|
|
|
1,480 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
24,160 |
|
|
$ |
9,364 |
|
|
$ |
29,697 |
|
|
$ |
(26,416 |
) |
|
$ |
36,805 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of debt and
capital lease obligations |
|
$ |
109 |
|
|
$ |
|
|
|
$ |
104 |
|
|
$ |
|
|
|
$ |
213 |
|
Accounts payable |
|
|
42 |
|
|
|
180 |
|
|
|
5,534 |
|
|
|
|
|
|
|
5,756 |
|
Accrued expenses |
|
|
166 |
|
|
|
99 |
|
|
|
368 |
|
|
|
|
|
|
|
633 |
|
Taxes other than income taxes |
|
|
|
|
|
|
21 |
|
|
|
646 |
|
|
|
|
|
|
|
667 |
|
Income taxes payable |
|
|
|
|
|
|
|
|
|
|
122 |
|
|
|
(58 |
) |
|
|
64 |
|
Deferred income taxes |
|
|
424 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
424 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
741 |
|
|
|
300 |
|
|
|
6,774 |
|
|
|
(58 |
) |
|
|
7,757 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt and capital lease obligations,
less current portion |
|
|
6,233 |
|
|
|
896 |
|
|
|
33 |
|
|
|
|
|
|
|
7,162 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term notes payable to affiliates |
|
|
|
|
|
|
7,646 |
|
|
|
9,099 |
|
|
|
(16,745 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes |
|
|
|
|
|
|
1,076 |
|
|
|
4,147 |
|
|
|
(1,351 |
) |
|
|
3,872 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other long-term liabilities |
|
|
1,296 |
|
|
|
147 |
|
|
|
681 |
|
|
|
|
|
|
|
2,124 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock |
|
|
7 |
|
|
|
|
|
|
|
1 |
|
|
|
(1 |
) |
|
|
7 |
|
Additional paid-in capital |
|
|
7,975 |
|
|
|
1,598 |
|
|
|
4,402 |
|
|
|
(6,000 |
) |
|
|
7,975 |
|
Treasury stock |
|
|
(6,830 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,830 |
) |
Retained earnings |
|
|
14,670 |
|
|
|
(2,289 |
) |
|
|
4,479 |
|
|
|
(2,190 |
) |
|
|
14,670 |
|
Accumulated other comprehensive
income (loss) |
|
|
68 |
|
|
|
(10 |
) |
|
|
81 |
|
|
|
(71 |
) |
|
|
68 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
15,890 |
|
|
|
(701 |
) |
|
|
8,963 |
|
|
|
(8,262 |
) |
|
|
15,890 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and
stockholders equity |
|
$ |
24,160 |
|
|
$ |
9,364 |
|
|
$ |
29,697 |
|
|
$ |
(26,416 |
) |
|
$ |
36,805 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
39
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Income for the Three Months Ended September 30, 2009
(unaudited, in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valero |
|
|
|
|
|
Other Non- |
|
|
|
|
|
|
Energy |
|
|
|
|
|
Guarantor |
|
|
|
|
|
|
Corporation |
|
PRG |
|
Subsidiaries |
|
Eliminations |
|
Consolidated |
|
Operating revenues |
|
$ |
|
|
|
$ |
3,925 |
|
|
$ |
17,533 |
|
|
$ |
(1,969 |
) |
|
$ |
19,489 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
|
|
|
|
4,406 |
|
|
|
15,667 |
|
|
|
(1,969 |
) |
|
|
18,104 |
|
Operating expenses |
|
|
|
|
|
|
149 |
|
|
|
774 |
|
|
|
|
|
|
|
923 |
|
Retail selling expenses |
|
|
|
|
|
|
|
|
|
|
182 |
|
|
|
|
|
|
|
182 |
|
General and
administrative
expenses |
|
|
1 |
|
|
|
39 |
|
|
|
127 |
|
|
|
|
|
|
|
167 |
|
Depreciation and
amortization expense |
|
|
|
|
|
|
56 |
|
|
|
333 |
|
|
|
|
|
|
|
389 |
|
Asset impairment loss |
|
|
|
|
|
|
370 |
|
|
|
47 |
|
|
|
|
|
|
|
417 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and
expenses |
|
|
1 |
|
|
|
5,020 |
|
|
|
17,130 |
|
|
|
(1,969 |
) |
|
|
20,182 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(1 |
) |
|
|
(1,095 |
) |
|
|
403 |
|
|
|
|
|
|
|
(693 |
) |
Equity in earnings
(losses) of subsidiaries |
|
|
(650 |
) |
|
|
358 |
|
|
|
(406 |
) |
|
|
698 |
|
|
|
|
|
Other income (expense),
net |
|
|
309 |
|
|
|
(5 |
) |
|
|
187 |
|
|
|
(482 |
) |
|
|
9 |
|
Interest and debt expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incurred |
|
|
(176 |
) |
|
|
(142 |
) |
|
|
(313 |
) |
|
|
482 |
|
|
|
(149 |
) |
Capitalized |
|
|
|
|
|
|
1 |
|
|
|
18 |
|
|
|
|
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before
income tax expense
(benefit) |
|
|
(518 |
) |
|
|
(883 |
) |
|
|
(111 |
) |
|
|
698 |
|
|
|
(814 |
) |
Income tax expense
(benefit) (1) |
|
|
111 |
|
|
|
(477 |
) |
|
|
181 |
|
|
|
|
|
|
|
(185 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(629 |
) |
|
$ |
(406 |
) |
|
$ |
(292 |
) |
|
$ |
698 |
|
|
$ |
(629 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The income tax expense (benefit) reflected in each column does not include any tax effect of
the equity in earnings (losses) of subsidiaries. |
40
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed
Consolidating Statement of Income for the Three Months Ended September 30, 2008
(unaudited, in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valero |
|
|
|
|
|
Other Non- |
|
|
|
|
|
|
Energy |
|
|
|
|
|
Guarantor |
|
|
|
|
|
|
Corporation |
|
PRG |
|
Subsidiaries |
|
Eliminations |
|
Consolidated |
|
Operating revenues |
|
$ |
|
|
|
$ |
6,952 |
|
|
$ |
35,548 |
|
|
$ |
(6,540 |
) |
|
$ |
35,960 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
|
|
|
|
6,736 |
|
|
|
32,310 |
|
|
|
(6,540 |
) |
|
|
32,506 |
|
Operating expenses |
|
|
|
|
|
|
183 |
|
|
|
953 |
|
|
|
|
|
|
|
1,136 |
|
Retail selling expenses |
|
|
|
|
|
|
|
|
|
|
201 |
|
|
|
|
|
|
|
201 |
|
General and administrative
expenses |
|
|
(1 |
) |
|
|
5 |
|
|
|
165 |
|
|
|
|
|
|
|
169 |
|
Depreciation and
amortization expense |
|
|
|
|
|
|
57 |
|
|
|
313 |
|
|
|
|
|
|
|
370 |
|
Asset impairment loss |
|
|
|
|
|
|
11 |
|
|
|
32 |
|
|
|
|
|
|
|
43 |
|
Gain on sale of Krotz
Springs Refinery |
|
|
|
|
|
|
|
|
|
|
(305 |
) |
|
|
|
|
|
|
(305 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
(1 |
) |
|
|
6,992 |
|
|
|
33,669 |
|
|
|
(6,540 |
) |
|
|
34,120 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
1 |
|
|
|
(40 |
) |
|
|
1,879 |
|
|
|
|
|
|
|
1,840 |
|
Equity in earnings of
subsidiaries |
|
|
1,116 |
|
|
|
296 |
|
|
|
181 |
|
|
|
(1,593 |
) |
|
|
|
|
Other income (expense), net |
|
|
265 |
|
|
|
(24 |
) |
|
|
232 |
|
|
|
(437 |
) |
|
|
36 |
|
Interest and debt expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incurred |
|
|
(152 |
) |
|
|
(134 |
) |
|
|
(263 |
) |
|
|
437 |
|
|
|
(112 |
) |
Capitalized |
|
|
|
|
|
|
7 |
|
|
|
24 |
|
|
|
|
|
|
|
31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income tax
expense (benefit) |
|
|
1,230 |
|
|
|
105 |
|
|
|
2,053 |
|
|
|
(1,593 |
) |
|
|
1,795 |
|
Income tax expense (benefit)
(1) |
|
|
78 |
|
|
|
(76 |
) |
|
|
641 |
|
|
|
|
|
|
|
643 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
1,152 |
|
|
$ |
181 |
|
|
$ |
1,412 |
|
|
$ |
(1,593 |
) |
|
$ |
1,152 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The income tax expense (benefit) reflected in each column does not include any tax effect of
the equity in earnings of subsidiaries. |
41
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Income for the Nine Months Ended September 30, 2009
(unaudited, in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valero |
|
|
|
|
|
Other Non- |
|
|
|
|
|
|
Energy |
|
|
|
|
|
Guarantor |
|
|
|
|
|
|
Corporation |
|
PRG |
|
Subsidiaries |
|
Eliminations |
|
Consolidated |
|
Operating revenues |
|
$ |
|
|
|
$ |
10,116 |
|
|
$ |
49,003 |
|
|
$ |
(7,881 |
) |
|
$ |
51,238 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
|
|
|
|
10,838 |
|
|
|
43,318 |
|
|
|
(7,881 |
) |
|
|
46,275 |
|
Operating expenses |
|
|
|
|
|
|
529 |
|
|
|
2,249 |
|
|
|
|
|
|
|
2,778 |
|
Retail selling expenses |
|
|
|
|
|
|
|
|
|
|
522 |
|
|
|
|
|
|
|
522 |
|
General and administrative
expenses |
|
|
2 |
|
|
|
41 |
|
|
|
392 |
|
|
|
|
|
|
|
435 |
|
Depreciation and
amortization expense |
|
|
|
|
|
|
179 |
|
|
|
977 |
|
|
|
|
|
|
|
1,156 |
|
Asset impairment loss |
|
|
|
|
|
|
475 |
|
|
|
100 |
|
|
|
|
|
|
|
575 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
2 |
|
|
|
12,062 |
|
|
|
47,558 |
|
|
|
(7,881 |
) |
|
|
51,741 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(2 |
) |
|
|
(1,946 |
) |
|
|
1,445 |
|
|
|
|
|
|
|
(503 |
) |
Equity in
earnings (losses) of subsidiaries |
|
|
(728 |
) |
|
|
692 |
|
|
|
(766 |
) |
|
|
802 |
|
|
|
|
|
Other income (expense), net |
|
|
853 |
|
|
|
(47 |
) |
|
|
500 |
|
|
|
(1,322 |
) |
|
|
(16 |
) |
Interest and debt expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incurred |
|
|
(481 |
) |
|
|
(384 |
) |
|
|
(843 |
) |
|
|
1,322 |
|
|
|
(386 |
) |
Capitalized |
|
|
|
|
|
|
15 |
|
|
|
80 |
|
|
|
|
|
|
|
95 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income tax
expense
(benefit) |
|
|
(358 |
) |
|
|
(1,670 |
) |
|
|
416 |
|
|
|
802 |
|
|
|
(810 |
) |
Income tax expense (benefit) (1) |
|
|
216 |
|
|
|
(904 |
) |
|
|
452 |
|
|
|
|
|
|
|
(236 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(574 |
) |
|
$ |
(766 |
) |
|
$ |
(36 |
) |
|
$ |
802 |
|
|
$ |
(574 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The income tax expense (benefit) reflected in each column does not include any tax
effect of the equity in earnings (losses) of subsidiaries. |
42
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Income for the Nine Months Ended September 30, 2008
(unaudited, in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valero |
|
|
|
|
|
Other Non- |
|
|
|
|
|
|
Energy |
|
|
|
|
|
Guarantor |
|
|
|
|
|
|
Corporation |
|
PRG |
|
Subsidiaries |
|
Eliminations |
|
Consolidated |
|
Operating revenues |
|
$ |
|
|
|
$ |
22,691 |
|
|
$ |
99,226 |
|
|
$ |
(21,372 |
) |
|
$ |
100,545 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
|
|
|
|
22,004 |
|
|
|
91,216 |
|
|
|
(21,372 |
) |
|
|
91,848 |
|
Operating expenses |
|
|
|
|
|
|
624 |
|
|
|
2,759 |
|
|
|
|
|
|
|
3,383 |
|
Retail selling expenses |
|
|
|
|
|
|
|
|
|
|
579 |
|
|
|
|
|
|
|
579 |
|
General and administrative expenses |
|
|
(4 |
) |
|
|
19 |
|
|
|
406 |
|
|
|
|
|
|
|
421 |
|
Depreciation and amortization
expense |
|
|
|
|
|
|
195 |
|
|
|
911 |
|
|
|
|
|
|
|
1,106 |
|
Asset impairment loss |
|
|
|
|
|
|
11 |
|
|
|
32 |
|
|
|
|
|
|
|
43 |
|
Gain on sale of Krotz Springs
Refinery |
|
|
|
|
|
|
|
|
|
|
(305 |
) |
|
|
|
|
|
|
(305 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
(4 |
) |
|
|
22,853 |
|
|
|
95,598 |
|
|
|
(21,372 |
) |
|
|
97,075 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
4 |
|
|
|
(162 |
) |
|
|
3,628 |
|
|
|
|
|
|
|
3,470 |
|
Equity in earnings of subsidiaries |
|
|
1,903 |
|
|
|
472 |
|
|
|
89 |
|
|
|
(2,464 |
) |
|
|
|
|
Other income (expense), net |
|
|
838 |
|
|
|
(50 |
) |
|
|
614 |
|
|
|
(1,331 |
) |
|
|
71 |
|
Interest and debt expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Incurred |
|
|
(424 |
) |
|
|
(414 |
) |
|
|
(828 |
) |
|
|
1,331 |
|
|
|
(335 |
) |
Capitalized |
|
|
|
|
|
|
16 |
|
|
|
58 |
|
|
|
|
|
|
|
74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income tax
expense (benefit) |
|
|
2,321 |
|
|
|
(138 |
) |
|
|
3,561 |
|
|
|
(2,464 |
) |
|
|
3,280 |
|
Income tax expense (benefit) (1) |
|
|
174 |
|
|
|
(227 |
) |
|
|
1,186 |
|
|
|
|
|
|
|
1,133 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
2,147 |
|
|
$ |
89 |
|
|
$ |
2,375 |
|
|
$ |
(2,464 |
) |
|
$ |
2,147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The income tax expense (benefit) reflected in each column does not include any tax
effect of the equity in earnings of subsidiaries. |
43
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2009
(unaudited, in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valero |
|
|
|
|
|
Other Non- |
|
|
|
|
|
|
Energy |
|
|
|
|
|
Guarantor |
|
|
|
|
|
|
Corporation |
|
PRG |
|
Subsidiaries |
|
Eliminations |
|
Consolidated |
|
Net cash provided by (used in) operating activities |
|
$ |
(164 |
) |
|
$ |
(1,216 |
) |
|
$ |
3,320 |
|
|
$ |
|
|
|
$ |
1,940 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
|
|
|
|
(420 |
) |
|
|
(1,400 |
) |
|
|
|
|
|
|
(1,820 |
) |
Deferred turnaround and catalyst costs |
|
|
|
|
|
|
(41 |
) |
|
|
(260 |
) |
|
|
|
|
|
|
(301 |
) |
Purchase of certain VeraSun Energy Corporation
facilities |
|
|
|
|
|
|
|
|
|
|
(556 |
) |
|
|
|
|
|
|
(556 |
) |
Return of investment in Cameron Highway Oil
Pipeline Company |
|
|
|
|
|
|
|
|
|
|
18 |
|
|
|
|
|
|
|
18 |
|
Minor acquisition |
|
|
|
|
|
|
|
|
|
|
(29 |
) |
|
|
|
|
|
|
(29 |
) |
Net intercompany loans |
|
|
(1,099 |
) |
|
|
|
|
|
|
|
|
|
|
1,099 |
|
|
|
|
|
Other investing activities, net |
|
|
|
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(1,099 |
) |
|
|
(461 |
) |
|
|
(2,222 |
) |
|
|
1,099 |
|
|
|
(2,683 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
(239 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(239 |
) |
Net intercompany borrowings (repayments) |
|
|
|
|
|
|
1,677 |
|
|
|
(578 |
) |
|
|
(1,099 |
) |
|
|
|
|
Other financing activities, net |
|
|
(3 |
) |
|
|
|
|
|
|
(3 |
) |
|
|
|
|
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
1,346 |
|
|
|
1,677 |
|
|
|
(581 |
) |
|
|
(1,099 |
) |
|
|
1,343 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of foreign exchange rate changes on cash |
|
|
|
|
|
|
|
|
|
|
65 |
|
|
|
|
|
|
|
65 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and temporary cash investments |
|
|
83 |
|
|
|
|
|
|
|
582 |
|
|
|
|
|
|
|
665 |
|
Cash and temporary cash investments
at beginning of period |
|
|
215 |
|
|
|
|
|
|
|
725 |
|
|
|
|
|
|
|
940 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and temporary cash investments at end of period |
|
$ |
298 |
|
|
$ |
|
|
|
$ |
1,307 |
|
|
$ |
|
|
|
$ |
1,605 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2008
(unaudited, in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Valero |
|
|
|
|
|
Other Non- |
|
|
|
|
|
|
Energy |
|
|
|
|
|
Guarantor |
|
|
|
|
|
|
Corporation |
|
PRG (1) |
|
Subsidiaries (1) |
|
Eliminations |
|
Consolidated |
|
Net cash provided by operating activities |
|
$ |
248 |
|
|
$ |
53 |
|
|
$ |
3,219 |
|
|
$ |
|
|
|
$ |
3,520 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
|
|
|
|
(397 |
) |
|
|
(1,497 |
) |
|
|
|
|
|
|
(1,894 |
) |
Deferred turnaround and catalyst costs |
|
|
|
|
|
|
(62 |
) |
|
|
(217 |
) |
|
|
|
|
|
|
(279 |
) |
Return of investment in Cameron Highway Oil
Pipeline Company |
|
|
|
|
|
|
|
|
|
|
11 |
|
|
|
|
|
|
|
11 |
|
Proceeds from the sale of Krotz Springs Refinery |
|
|
|
|
|
|
|
|
|
|
463 |
|
|
|
|
|
|
|
463 |
|
Contingent payment in connection with acquisition |
|
|
|
|
|
|
|
|
|
|
(25 |
) |
|
|
|
|
|
|
(25 |
) |
Investments in subsidiaries |
|
|
(1,043 |
) |
|
|
|
|
|
|
|
|
|
|
1,043 |
|
|
|
|
|
Net intercompany loan repayments |
|
|
1,993 |
|
|
|
|
|
|
|
|
|
|
|
(1,993 |
) |
|
|
|
|
Minor acquisitions |
|
|
|
|
|
|
|
|
|
|
(144 |
) |
|
|
|
|
|
|
(144 |
) |
Other investing activities, net |
|
|
|
|
|
|
1 |
|
|
|
15 |
|
|
|
|
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) investing activities |
|
|
950 |
|
|
|
(458 |
) |
|
|
(1,394 |
) |
|
|
(950 |
) |
|
|
(1,852 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
(774 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(774 |
) |
Common stock dividends |
|
|
(221 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(221 |
) |
Net intercompany borrowings (repayments) |
|
|
|
|
|
|
773 |
|
|
|
(2,766 |
) |
|
|
1,993 |
|
|
|
|
|
Capital contributions from parent |
|
|
|
|
|
|
|
|
|
|
1,043 |
|
|
|
(1,043 |
) |
|
|
|
|
Other financing activities |
|
|
29 |
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
(972 |
) |
|
|
405 |
|
|
|
(1,725 |
) |
|
|
950 |
|
|
|
(1,342 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of foreign exchange rate changes on cash |
|
|
|
|
|
|
|
|
|
|
(23 |
) |
|
|
|
|
|
|
(23 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase in cash and temporary cash investments |
|
|
226 |
|
|
|
|
|
|
|
77 |
|
|
|
|
|
|
|
303 |
|
Cash and temporary cash investments
at beginning of period |
|
|
1,414 |
|
|
|
|
|
|
|
1,050 |
|
|
|
|
|
|
|
2,464 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and temporary cash investments at end of period |
|
$ |
1,640 |
|
|
$ |
|
|
|
$ |
1,127 |
|
|
$ |
|
|
|
$ |
2,767 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
45
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; |
46
|
|
|
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.
47
OVERVIEW
In this overview, we describe some of the primary factors that we believe affected our results of
operations in the third quarter and first nine months of 2009. We reported a net loss of $629
million, or $1.12 per share, for the third quarter of 2009, compared to net income of $1.2 billion,
or $2.18 per share, for the third quarter of 2008. We reported a net
loss of $574 million, or $1.08
per share, for the first nine months of 2009, compared to net income of $2.1 billion, or $4.02 per
share, for the first nine months of 2008. The results of operations for the third quarter and first
nine months of 2009 were unfavorably impacted by asset impairment losses of $417 million ($0.48 per
share) and $575 million ($0.70 per share), respectively, which
are discussed further below, as well as a $140 million ($0.25
per share and $0.26 per share, respectively, for the third quarter
and first nine months of 2009) loss contingency accrual (including interest) recorded in the
third quarter of 2009 related to our dispute of a turnover tax on export sales and other tax
matters involving the Government of Aruba.
The
results of operations for the third quarter and first nine months of 2008 included a $0.32 per
share benefit from the gain on the sale of our Krotz Springs Refinery. In addition, results of
operations for the first nine months of 2008 included a pre-tax benefit of approximately $100
million, or $0.12 per share, resulting from a settlement of our business interruption insurance
claims related to a 2007 fire at our McKee Refinery.
Due to the impact of the continuing economic slowdown on refining industry fundamentals, during the
third quarter of 2009, we continued to assess our assets for potential impairment. This evaluation
included an assessment of our operating assets as well as an evaluation of our capital projects
classified as construction in progress. As a result of this analysis, we recorded asset
impairment losses of $417 million and $575 million for the third quarter and first nine months of
2009, respectively. Of these amounts, approximately $340 million related to the write-off in the
third quarter of 2009 of costs related to the gasification unit at our Delaware City Refinery. The
remaining write-offs related to the permanent cancellation of various capital projects at various
refineries.
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 economic slowdown that
has existed throughout 2009 has caused a continuing weakness in demand for refined products, which
put pressure on refined product margins during the third quarter and first nine months of 2009.
This reduced demand, combined with increased inventory levels, caused a significant decline in
diesel and jet fuel margins in the third quarter and first nine months of 2009 compared to the
corresponding periods of 2008. However, margins on other refined products were generally favorable
in 2009 compared to 2008. Although overall gasoline margins were somewhat lower in the third
quarter of 2009 compared to the third quarter of 2008, they were favorable in all of our regions
for the first nine months of 2009 compared to the same period of 2008. 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 third quarter and first nine months of 2009
compared to 2008.
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 third quarter and first nine months of 2009 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 addition, high prices of residual fuel oil relative
to sweet crude oil prices caused a significant reduction in discounts realized on residual fuel oil
that we processed during the third quarter and first nine months of 2009.
These higher residual fuel oil
48
prices also contributed to the decrease in sour crude oil
differentials because sour crude oil competes with residual fuel oil
as a refinery feedstock.
In March 2009, we issued $750 million of 10-year notes and $250 million of 30-year notes. Proceeds
from these notes were 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 $49 million and $71 million of operating income for the
three and nine months ended September 30, 2009, respectively.
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.
49
RESULTS OF OPERATIONS
Third Quarter 2009 Compared to Third Quarter 2008
Financial Highlights
(millions of dollars, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
2009 (a) |
|
2008 |
|
Change |
|
Operating revenues |
|
$ |
19,489 |
|
|
$ |
35,960 |
|
|
$ |
(16,471 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
18,104 |
|
|
|
32,506 |
|
|
|
(14,402 |
) |
Operating expenses |
|
|
923 |
|
|
|
1,136 |
|
|
|
(213 |
) |
Retail selling expenses |
|
|
182 |
|
|
|
201 |
|
|
|
(19 |
) |
General and administrative expenses |
|
|
167 |
|
|
|
169 |
|
|
|
(2 |
) |
Depreciation and amortization expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Refining |
|
|
345 |
|
|
|
331 |
|
|
|
14 |
|
Retail |
|
|
25 |
|
|
|
28 |
|
|
|
(3 |
) |
Ethanol |
|
|
7 |
|
|
|
|
|
|
|
7 |
|
Corporate |
|
|
12 |
|
|
|
11 |
|
|
|
1 |
|
Asset impairment loss (b) |
|
|
417 |
|
|
|
43 |
|
|
|
374 |
|
Gain on sale of Krotz Springs Refinery |
|
|
|
|
|
|
(305 |
) |
|
|
305 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
20,182 |
|
|
|
34,120 |
|
|
|
(13,938 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(693 |
) |
|
|
1,840 |
|
|
|
(2,533 |
) |
Other income, net |
|
|
9 |
|
|
|
36 |
|
|
|
(27 |
) |
Interest and debt expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Incurred |
|
|
(149 |
) |
|
|
(112 |
) |
|
|
(37 |
) |
Capitalized |
|
|
19 |
|
|
|
31 |
|
|
|
(12 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income tax expense (benefit) |
|
|
(814 |
) |
|
|
1,795 |
|
|
|
(2,609 |
) |
Income tax expense (benefit) |
|
|
(185 |
) |
|
|
643 |
|
|
|
(828 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(629 |
) |
|
$ |
1,152 |
|
|
$ |
(1,781 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share assuming
dilution |
|
$ |
(1.12 |
) |
|
$ |
2.18 |
|
|
$ |
(3.30 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the footnote references on page 54. |
50
Operating Highlights
(millions of dollars, except per barrel and per gallon amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
2009 |
|
2008 |
|
Change |
|
Refining: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
$ |
(674 |
) |
|
$ |
1,913 |
|
|
$ |
(2,587 |
) |
Throughput margin per barrel (c) |
|
$ |
4.86 |
|
|
$ |
13.11 |
|
|
$ |
(8.25 |
) |
Operating costs per barrel (b): |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
3.94 |
|
|
$ |
4.78 |
|
|
$ |
(0.84 |
) |
Depreciation and amortization |
|
|
1.58 |
|
|
|
1.39 |
|
|
|
0.19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
5.52 |
|
|
$ |
6.17 |
|
|
$ |
(0.65 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput volumes (thousand barrels per day): |
|
|
|
|
|
|
|
|
|
|
|
|
Feedstocks: |
|
|
|
|
|
|
|
|
|
|
|
|
Heavy sour crude |
|
|
443 |
|
|
|
565 |
|
|
|
(122 |
) |
Medium/light sour crude |
|
|
544 |
|
|
|
670 |
|
|
|
(126 |
) |
Acidic sweet crude |
|
|
24 |
|
|
|
75 |
|
|
|
(51 |
) |
Sweet crude |
|
|
676 |
|
|
|
578 |
|
|
|
98 |
|
Residuals |
|
|
211 |
|
|
|
282 |
|
|
|
(71 |
) |
Other feedstocks |
|
|
179 |
|
|
|
136 |
|
|
|
43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total feedstocks |
|
|
2,077 |
|
|
|
2,306 |
|
|
|
(229 |
) |
Blendstocks and other |
|
|
302 |
|
|
|
281 |
|
|
|
21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput volumes |
|
|
2,379 |
|
|
|
2,587 |
|
|
|
(208 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Yields (thousand barrels per day): |
|
|
|
|
|
|
|
|
|
|
|
|
Gasolines and blendstocks |
|
|
1,207 |
|
|
|
1,136 |
|
|
|
71 |
|
Distillates |
|
|
744 |
|
|
|
906 |
|
|
|
(162 |
) |
Petrochemicals |
|
|
72 |
|
|
|
66 |
|
|
|
6 |
|
Other products (d) |
|
|
360 |
|
|
|
464 |
|
|
|
(104 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total yields |
|
|
2,383 |
|
|
|
2,572 |
|
|
|
(189 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
79 |
|
|
$ |
81 |
|
|
$ |
(2 |
) |
Company-operated fuel sites (average) |
|
|
998 |
|
|
|
984 |
|
|
|
14 |
|
Fuel volumes (gallons per day per site) |
|
|
4,963 |
|
|
|
4,946 |
|
|
|
17 |
|
Fuel margin per gallon |
|
$ |
0.231 |
|
|
$ |
0.273 |
|
|
$ |
(0.042 |
) |
Merchandise sales |
|
$ |
315 |
|
|
$ |
292 |
|
|
$ |
23 |
|
Merchandise margin (percentage of sales) |
|
|
28.7 |
% |
|
|
29.8 |
% |
|
|
(1.1 |
)% |
Margin on miscellaneous sales |
|
$ |
22 |
|
|
$ |
24 |
|
|
$ |
(2 |
) |
Retail selling expenses |
|
$ |
120 |
|
|
$ |
134 |
|
|
$ |
(14 |
) |
Depreciation and amortization expense |
|
$ |
17 |
|
|
$ |
18 |
|
|
$ |
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail Canada: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
32 |
|
|
$ |
26 |
|
|
$ |
6 |
|
Fuel volumes (thousand gallons per day) |
|
|
3,115 |
|
|
|
3,126 |
|
|
|
(11 |
) |
Fuel margin per gallon |
|
$ |
0.263 |
|
|
$ |
0.261 |
|
|
$ |
0.002 |
|
Merchandise sales |
|
$ |
58 |
|
|
$ |
56 |
|
|
$ |
2 |
|
Merchandise margin (percentage of sales) |
|
|
28.6 |
% |
|
|
28.6 |
% |
|
|
|
% |
Margin on miscellaneous sales |
|
$ |
10 |
|
|
$ |
10 |
|
|
$ |
|
|
Retail selling expenses |
|
$ |
62 |
|
|
$ |
67 |
|
|
$ |
(5 |
) |
Depreciation and amortization expense |
|
$ |
8 |
|
|
$ |
10 |
|
|
$ |
(2 |
) |
|
|
|
See the footnote references on page 54. |
51
Operating Highlights (continued)
(millions of dollars, except per gallon amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
2009 |
|
2008 |
|
Change |
|
Ethanol (a): |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
49 |
|
|
|
N/A |
|
|
$ |
49 |
|
Ethanol production (thousand gallons per day) |
|
|
2,116 |
|
|
|
N/A |
|
|
|
2,116 |
|
Gross margin per gallon of ethanol production |
|
$ |
0.59 |
|
|
|
N/A |
|
|
$ |
0.59 |
|
Operating costs per gallon of ethanol production: |
|
|
|
|
|
|
|
|
|
|
|
|
Ethanol operating expenses |
|
$ |
0.31 |
|
|
|
N/A |
|
|
$ |
0.31 |
|
Depreciation and amortization |
|
|
0.03 |
|
|
|
N/A |
|
|
|
0.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per gallon
of ethanol production |
|
$ |
0.34 |
|
|
|
N/A |
|
|
$ |
0.34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the footnote references on page 54. |
52
Refining Operating Highlights by Region (e)
(millions of dollars, except per barrel amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
2009 |
|
2008 |
|
Change |
|
Gulf Coast: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
$ |
(81 |
) |
|
$ |
1,159 |
|
|
$ |
(1,240 |
) |
Throughput volumes (thousand barrels per day) |
|
|
1,238 |
|
|
|
1,324 |
|
|
|
(86 |
) |
Throughput margin per barrel (c) |
|
$ |
4.66 |
|
|
$ |
13.21 |
|
|
$ |
(8.55 |
) |
Operating costs per barrel (b): |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
3.81 |
|
|
$ |
4.83 |
|
|
$ |
(1.02 |
) |
Depreciation and amortization |
|
|
1.57 |
|
|
|
1.37 |
|
|
|
0.20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
5.38 |
|
|
$ |
6.20 |
|
|
$ |
(0.82 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Continent: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
5 |
|
|
$ |
296 |
|
|
$ |
(291 |
) |
Throughput volumes (thousand barrels per day) |
|
|
374 |
|
|
|
426 |
|
|
|
(52 |
) |
Throughput margin per barrel (c) |
|
$ |
5.38 |
|
|
$ |
13.23 |
|
|
$ |
(7.85 |
) |
Operating costs per barrel (b): |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
3.69 |
|
|
$ |
4.41 |
|
|
$ |
(0.72 |
) |
Depreciation and amortization |
|
|
1.53 |
|
|
|
1.28 |
|
|
|
0.25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
5.22 |
|
|
$ |
5.69 |
|
|
$ |
(0.47 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
$ |
(134 |
) |
|
$ |
387 |
|
|
$ |
(521 |
) |
Throughput volumes (thousand barrels per day) |
|
|
485 |
|
|
|
552 |
|
|
|
(67 |
) |
Throughput margin per barrel (c) |
|
$ |
2.86 |
|
|
$ |
13.53 |
|
|
$ |
(10.67 |
) |
Operating costs per barrel (b): |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
4.26 |
|
|
$ |
4.54 |
|
|
$ |
(0.28 |
) |
Depreciation and amortization |
|
|
1.59 |
|
|
|
1.36 |
|
|
|
0.23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
5.85 |
|
|
$ |
5.90 |
|
|
$ |
(0.05 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Coast: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
67 |
|
|
$ |
114 |
|
|
$ |
(47 |
) |
Throughput volumes (thousand barrels per day) |
|
|
282 |
|
|
|
285 |
|
|
|
(3 |
) |
Throughput margin per barrel (c) |
|
$ |
8.51 |
|
|
$ |
11.60 |
|
|
$ |
(3.09 |
) |
Operating costs per barrel (b): |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
4.35 |
|
|
$ |
5.53 |
|
|
$ |
(1.18 |
) |
Depreciation and amortization |
|
|
1.58 |
|
|
|
1.70 |
|
|
|
(0.12 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
5.93 |
|
|
$ |
7.23 |
|
|
$ |
(1.30 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) for regions above |
|
$ |
(143 |
) |
|
$ |
1,956 |
|
|
$ |
(2,099 |
) |
Asset impairment loss applicable to refining |
|
|
(417 |
) |
|
|
(43 |
) |
|
|
(374 |
) |
Loss contingency accrual related to Aruban tax matter (f) |
|
|
(114 |
) |
|
|
|
|
|
|
(114 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total refining operating income (loss) |
|
$ |
(674 |
) |
|
$ |
1,913 |
|
|
$ |
(2,587 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the footnote references on page 54. |
53
Average
Market Reference Prices and Differentials (g)
(dollars per barrel)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
2009 |
|
2008 |
|
Change |
|
Feedstocks: |
|
|
|
|
|
|
|
|
|
|
|
|
West Texas Intermediate (WTI) crude oil |
|
$ |
68.18 |
|
|
$ |
117.83 |
|
|
$ |
(49.65 |
) |
WTI less
sour crude oil at U.S. Gulf Coast (h) |
|
|
1.72 |
|
|
|
4.05 |
|
|
|
(2.33 |
) |
WTI less Mars crude oil |
|
|
1.78 |
|
|
|
5.26 |
|
|
|
(3.48 |
) |
WTI less Maya crude oil |
|
|
5.01 |
|
|
|
11.36 |
|
|
|
(6.35 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Products: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Gulf Coast: |
|
|
|
|
|
|
|
|
|
|
|
|
Conventional 87 gasoline less WTI |
|
|
7.85 |
|
|
|
12.13 |
|
|
|
(4.28 |
) |
No. 2 fuel oil less WTI |
|
|
4.53 |
|
|
|
19.27 |
|
|
|
(14.74 |
) |
Ultra-low-sulfur diesel less WTI |
|
|
6.99 |
|
|
|
23.91 |
|
|
|
(16.92 |
) |
Propylene less WTI |
|
|
8.22 |
|
|
|
7.21 |
|
|
|
1.01 |
|
U.S. Mid-Continent: |
|
|
|
|
|
|
|
|
|
|
|
|
Conventional 87 gasoline less WTI |
|
|
8.11 |
|
|
|
8.62 |
|
|
|
(0.51 |
) |
Low-sulfur diesel less WTI |
|
|
8.01 |
|
|
|
25.55 |
|
|
|
(17.54 |
) |
U.S. Northeast: |
|
|
|
|
|
|
|
|
|
|
|
|
Conventional 87 gasoline less WTI |
|
|
8.34 |
|
|
|
5.80 |
|
|
|
2.54 |
|
No. 2 fuel oil less WTI |
|
|
4.95 |
|
|
|
19.86 |
|
|
|
(14.91 |
) |
Lube oils less WTI |
|
|
28.89 |
|
|
|
89.33 |
|
|
|
(60.44 |
) |
U.S. West Coast: |
|
|
|
|
|
|
|
|
|
|
|
|
CARBOB 87 gasoline less WTI |
|
|
18.00 |
|
|
|
11.28 |
|
|
|
6.72 |
|
CARB diesel less WTI |
|
|
9.29 |
|
|
|
22.94 |
|
|
|
(13.65 |
) |
|
|
|
The following notes relate to references on pages 50 through 54. |
|
(a) |
|
The information presented for the three months ended September 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. |
|
(b) |
|
The asset impairment loss for the three months ended September 30, 2009 relates primarily to
charges of approximately $340 million resulting from the permanent shutdown of the
gasification unit at our Delaware City Refinery. The remaining loss for the three
months ended September 30, 2009 relates to the permanent cancellation of certain capital
projects classified as construction in progress as a result of the unfavorable impact of the
continuing economic slowdown on refining industry fundamentals. Losses resulting from the
permanent cancellation of certain capital projects in prior periods have been reclassified
from operating expenses and presented separately for comparability with the third quarter 2009
presentation. The asset impairment loss amounts have been excluded from operating costs in
determining operating costs per barrel, resulting in an adjustment to the operating costs per
barrel previously reported in 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, 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. In addition, the gain on the sale of the Krotz Springs
Refinery to Alon Refining Krotz Springs, Inc. (Alon), a subsidiary of Alon USA Energy, Inc.
effective July 1, 2008 is included in the operating income of the Gulf Coast refining region
for the third quarter of 2008. |
|
(f) |
|
A loss contingency accrual of $140 million ($0.25 per share) was recorded
in the third quarter of 2009 related to our dispute with the Government of Aruba regarding a turnover
tax on export sales as well as other tax matters. The portion of the loss contingency accrual that relates to the
turnover tax was recorded in cost of sales for the three months ended September 30, 2009, and therefore is included
in refining operating income (loss) but has been excluded in determining throughput margin per barrel.
|
54
|
|
|
|
(g) |
|
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. |
|
(h) |
|
The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab
Light posted prices. |
General
Operating revenues decreased 46% for the third quarter of 2009 compared to the third quarter of
2008 primarily as a result of lower refined product prices between the two periods. Operating
income declined $2.5 billion and net income decreased $1.8 billion for the three months ended
September 30, 2009 compared to amounts reported for the three months ended September 30, 2008
primarily due to a $2.6 billion decrease in refining segment operating income discussed below.
Refining
Results of operations of our refining segment decreased from operating income of $1.9 billion for
the third quarter of 2008 to an operating loss of $674 million for the third quarter of 2009. The
decrease in operating income was attributable to a $374 million increase in asset impairment losses
(as further discussed in Note 4 of Condensed Notes to Consolidated Financial Statements), a $305
million gain on the sale of the Krotz Springs Refinery in the third quarter of 2008 (as further
discussed in Note 3 of Condensed Notes to Consolidated Financial Statements), a $114 million loss contingency accrual recorded in the third quarter of 2009 related to our dispute of a
turnover tax on export sales in Aruba (as further
discussed in Note 14 of Condensed Notes to Consolidated Financial Statements),
a 63% decrease in
throughput margin per barrel, and an 8% decline in throughput volumes, partially offset by an 18%
decrease in refining operating expenses (including depreciation and amortization expense).
Total refining throughput margins for the third quarter of 2009 compared to the third quarter of
2008 were impacted by the following factors:
|
|
|
Distillate margins in the third quarter of 2009 decreased significantly in all of
our refining regions from the high margins in the third 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. |
|
|
|
Sour crude oil and residual fuel oil feedstock differentials to WTI crude oil
during the third quarter of 2009 declined significantly compared to the differentials in
the third quarter of 2008. The unfavorable sour crude oil differentials were attributable
mainly to reduced production of sour crude oil by OPEC and other producers as well as high
relative prices for residual fuel oil with which sour crude oil competes as a refinery
feedstock. The high relative residual fuel oil prices, and resulting narrow residual fuel
oil discounts, were caused by lower production of residual fuel oil attributable to reduced
refinery throughput due to lower refined product demand. This reduced supply more than
offset the effect of reduced worldwide demand for residual fuel oil. |
|
|
|
Margins on various secondary refined products such as asphalt, fuel oils, and
petroleum coke improved significantly from the third quarter of 2008 to the third 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. The price of West Texas Intermediate
crude oil declined by approximately $50 per barrel, or 42%, from the third quarter of 2008
to the third quarter of 2009. |
55
|
|
|
Throughput volumes decreased 208,000 barrels per day during the third quarter of
2009 compared to the third quarter of 2008 primarily due to the temporary shutdown of our
Aruba Refinery commencing in July 2009 and 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 24% lower for
the quarter ended September 30, 2009 compared to the quarter ended September 30, 2008 primarily due
to a significant decrease in energy costs. Refining depreciation and amortization expense increased
4% from the third quarter of 2008 to the third quarter of 2009 primarily due to the completion of
new capital projects.
Retail
Retail operating income was $111 million for the quarter ended
September 30, 2009 compared to $107 million for the quarter ended September 30, 2008. The increase
in operating income was primarily due to a $6 million increase in our Canadian retail operations
resulting mainly from lower selling expenses. In our U.S. retail operations, a $0.042 per gallon
decrease in fuel margins was offset by lower selling expenses.
Ethanol
Ethanol operating income was $49 million for the quarter ended September 30, 2009, which represents
the operations of the seven ethanol plants acquired in the second quarter of 2009 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, reflected
almost no change from the third quarter of 2008 to the third quarter of 2009 as reductions in
variable compensation expense, insurance expense, and tax expense were offset by increased
litigation costs.
Other income for the third quarter of 2009 decreased from the third quarter of 2008 due mainly to a
$16 million unfavorable change in fair value adjustments related to the Alon earn-out agreement
and associated derivative instruments, as discussed in Notes 3, 10, and 11 of Condensed
Notes to Consolidated Financial Statements, and reduced interest income resulting from lower cash
balances and interest rates.
Interest and debt expense increased from the third quarter of 2008 to the third quarter of 2009 due
mainly to interest incurred in the third quarter of 2009 on $1 billion of notes issued in March
2009, a $6 million charge in the third quarter of 2009 to write off a pro rata portion of the
unamortized fair value adjustment related to $76 million of 6.75% putable senior notes for which we
received purchase notices from the holders of the notes, as discussed in Note 6 of Condensed Notes
to Consolidated Financial Statements, and decreased capitalized interest due to the cancellation or
deferral of various capital projects.
Income tax expense decreased $828 million from $643 million of expense in the third quarter of 2008
to a $185 million benefit in the third quarter of 2009 mainly as a result of lower operating
income.
56
Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008
Financial Highlights
(millions of dollars, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
2009 (a) |
|
2008 (b) |
|
Change |
|
Operating revenues |
|
$ |
51,238 |
|
|
$ |
100,545 |
|
|
$ |
(49,307 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
46,275 |
|
|
|
91,848 |
|
|
|
(45,573 |
) |
Operating expenses |
|
|
2,778 |
|
|
|
3,383 |
|
|
|
(605 |
) |
Retail selling expenses |
|
|
522 |
|
|
|
579 |
|
|
|
(57 |
) |
General and administrative expenses |
|
|
435 |
|
|
|
421 |
|
|
|
14 |
|
Depreciation and amortization expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Refining |
|
|
1,035 |
|
|
|
998 |
|
|
|
37 |
|
Retail |
|
|
74 |
|
|
|
77 |
|
|
|
(3 |
) |
Ethanol |
|
|
12 |
|
|
|
|
|
|
|
12 |
|
Corporate |
|
|
35 |
|
|
|
31 |
|
|
|
4 |
|
Asset impairment loss (c) |
|
|
575 |
|
|
|
43 |
|
|
|
532 |
|
Gain on sale of Krotz Springs Refinery |
|
|
|
|
|
|
(305 |
) |
|
|
305 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
51,741 |
|
|
|
97,075 |
|
|
|
(45,334 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(503 |
) |
|
|
3,470 |
|
|
|
(3,973 |
) |
Other income (expense), net |
|
|
(16 |
) |
|
|
71 |
|
|
|
(87 |
) |
Interest and debt expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Incurred |
|
|
(386 |
) |
|
|
(335 |
) |
|
|
(51 |
) |
Capitalized |
|
|
95 |
|
|
|
74 |
|
|
|
21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income tax expense (benefit) |
|
|
(810 |
) |
|
|
3,280 |
|
|
|
(4,090 |
) |
Income tax expense (benefit) |
|
|
(236 |
) |
|
|
1,133 |
|
|
|
(1,369 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(574 |
) |
|
$ |
2,147 |
|
|
$ |
(2,721 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per common share assuming
dilution |
|
$ |
(1.08 |
) |
|
$ |
4.02 |
|
|
$ |
(5.10 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the footnote references on page 61. |
57
Operating Highlights
(millions of dollars, except per barrel and per gallon amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
2009 |
|
2008 |
|
Change |
|
Refining (b): |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
$ |
(335 |
) |
|
$ |
3,716 |
|
|
$ |
(4,051 |
) |
Throughput margin per barrel (d) |
|
$ |
6.09 |
|
|
$ |
10.80 |
|
|
$ |
(4.71 |
) |
Operating costs per barrel (c): |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
4.01 |
|
|
$ |
4.66 |
|
|
$ |
(0.65 |
) |
Depreciation and amortization |
|
|
1.55 |
|
|
|
1.38 |
|
|
|
0.17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
5.56 |
|
|
$ |
6.04 |
|
|
$ |
(0.48 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput volumes (thousand barrels per day): |
|
|
|
|
|
|
|
|
|
|
|
|
Feedstocks: |
|
|
|
|
|
|
|
|
|
|
|
|
Heavy sour crude |
|
|
489 |
|
|
|
580 |
|
|
|
(91 |
) |
Medium/light sour crude |
|
|
582 |
|
|
|
680 |
|
|
|
(98 |
) |
Acidic sweet crude |
|
|
80 |
|
|
|
76 |
|
|
|
4 |
|
Sweet crude |
|
|
619 |
|
|
|
622 |
|
|
|
(3 |
) |
Residuals |
|
|
193 |
|
|
|
242 |
|
|
|
(49 |
) |
Other feedstocks |
|
|
177 |
|
|
|
141 |
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total feedstocks |
|
|
2,140 |
|
|
|
2,341 |
|
|
|
(201 |
) |
Blendstocks and other |
|
|
305 |
|
|
|
306 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput volumes |
|
|
2,445 |
|
|
|
2,647 |
|
|
|
(202 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Yields (thousand barrels per day): |
|
|
|
|
|
|
|
|
|
|
|
|
Gasolines and blendstocks |
|
|
1,176 |
|
|
|
1,197 |
|
|
|
(21 |
) |
Distillates |
|
|
789 |
|
|
|
920 |
|
|
|
(131 |
) |
Petrochemicals |
|
|
67 |
|
|
|
74 |
|
|
|
(7 |
) |
Other products (e) |
|
|
409 |
|
|
|
449 |
|
|
|
(40 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total yields |
|
|
2,441 |
|
|
|
2,640 |
|
|
|
(199 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail U.S.: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
140 |
|
|
$ |
120 |
|
|
$ |
20 |
|
Company-operated fuel sites (average) |
|
|
1,001 |
|
|
|
961 |
|
|
|
40 |
|
Fuel volumes (gallons per day per site) |
|
|
5,022 |
|
|
|
4,997 |
|
|
|
25 |
|
Fuel margin per gallon |
|
$ |
0.157 |
|
|
$ |
0.173 |
|
|
$ |
(0.016 |
) |
Merchandise sales |
|
$ |
888 |
|
|
$ |
819 |
|
|
$ |
69 |
|
Merchandise margin (percentage of sales) |
|
|
29.2 |
% |
|
|
30.0 |
% |
|
|
(0.8 |
)% |
Margin on miscellaneous sales |
|
$ |
66 |
|
|
$ |
74 |
|
|
$ |
(8 |
) |
Retail selling expenses |
|
$ |
349 |
|
|
$ |
375 |
|
|
$ |
(26 |
) |
Depreciation and amortization expense |
|
$ |
52 |
|
|
$ |
51 |
|
|
$ |
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retail Canada: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
92 |
|
|
$ |
86 |
|
|
$ |
6 |
|
Fuel volumes (thousand gallons per day) |
|
|
3,155 |
|
|
|
3,169 |
|
|
|
(14 |
) |
Fuel margin per gallon |
|
$ |
0.255 |
|
|
$ |
0.278 |
|
|
$ |
(0.023 |
) |
Merchandise sales |
|
$ |
146 |
|
|
$ |
156 |
|
|
$ |
(10 |
) |
Merchandise margin (percentage of sales) |
|
|
29.1 |
% |
|
|
28.5 |
% |
|
|
0.6 |
% |
Margin on miscellaneous sales |
|
$ |
25 |
|
|
$ |
29 |
|
|
$ |
(4 |
) |
Retail selling expenses |
|
$ |
173 |
|
|
$ |
204 |
|
|
$ |
(31 |
) |
Depreciation and amortization expense |
|
$ |
22 |
|
|
$ |
26 |
|
|
$ |
(4 |
) |
|
|
|
See the footnote references on page 61. |
58
Operating Highlights (continued)
(millions of dollars, except per gallon amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
2009 |
|
2008 |
|
Change |
|
Ethanol (a): |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
71 |
|
|
|
N/A |
|
|
$ |
71 |
|
Ethanol production (thousand gallons per day) |
|
|
1,229 |
|
|
|
N/A |
|
|
|
1,229 |
|
Gross margin per gallon of ethanol production |
|
$ |
0.55 |
|
|
|
N/A |
|
|
$ |
0.55 |
|
Operating costs per gallon of ethanol production: |
|
|
|
|
|
|
|
|
|
|
|
|
Ethanol operating expenses |
|
$ |
0.31 |
|
|
|
N/A |
|
|
$ |
0.31 |
|
Depreciation and amortization |
|
|
0.03 |
|
|
|
N/A |
|
|
|
0.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per gallon
of ethanol production |
|
$ |
0.34 |
|
|
|
N/A |
|
|
$ |
0.34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the footnote references on page 61. |
59
Refining Operating Highlights by Region (f)
(millions of dollars, except per barrel amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
2009 |
|
2008 |
|
Change |
|
Gulf Coast (b): |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
28 |
|
|
$ |
2,639 |
|
|
$ |
(2,611 |
) |
Throughput volumes (thousand barrels per day) |
|
|
1,316 |
|
|
|
1,399 |
|
|
|
(83 |
) |
Throughput margin per barrel (d) |
|
$ |
5.22 |
|
|
$ |
12.01 |
|
|
$ |
(6.79 |
) |
Operating costs per barrel (c): |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
3.65 |
|
|
$ |
4.62 |
|
|
$ |
(0.97 |
) |
Depreciation and amortization |
|
|
1.49 |
|
|
|
1.30 |
|
|
|
0.19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
5.14 |
|
|
$ |
5.92 |
|
|
$ |
(0.78 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mid-Continent: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
197 |
|
|
$ |
514 |
|
|
$ |
(317 |
) |
Throughput volumes (thousand barrels per day) |
|
|
381 |
|
|
|
426 |
|
|
|
(45 |
) |
Throughput margin per barrel (d) |
|
$ |
7.18 |
|
|
$ |
9.94 |
|
|
$ |
(2.76 |
) |
Operating costs per barrel (c): |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
3.72 |
|
|
$ |
4.25 |
|
|
$ |
(0.53 |
) |
Depreciation and amortization |
|
|
1.57 |
|
|
|
1.29 |
|
|
|
0.28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
5.29 |
|
|
$ |
5.54 |
|
|
$ |
(0.25 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
$ |
(203 |
) |
|
$ |
357 |
|
|
$ |
(560 |
) |
Throughput volumes (thousand barrels per day) |
|
|
467 |
|
|
|
545 |
|
|
|
(78 |
) |
Throughput margin per barrel (d) |
|
$ |
4.94 |
|
|
$ |
8.50 |
|
|
$ |
(3.56 |
) |
Operating costs per barrel (c): |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
4.90 |
|
|
$ |
4.69 |
|
|
$ |
0.21 |
|
Depreciation and amortization |
|
|
1.62 |
|
|
|
1.42 |
|
|
|
0.20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
6.52 |
|
|
$ |
6.11 |
|
|
$ |
0.41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West Coast: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
331 |
|
|
$ |
249 |
|
|
$ |
82 |
|
Throughput volumes (thousand barrels per day) |
|
|
281 |
|
|
|
277 |
|
|
|
4 |
|
Throughput margin per barrel (d) |
|
$ |
10.59 |
|
|
$ |
10.55 |
|
|
$ |
0.04 |
|
Operating costs per barrel (c): |
|
|
|
|
|
|
|
|
|
|
|
|
Refining operating expenses |
|
$ |
4.60 |
|
|
$ |
5.50 |
|
|
$ |
(0.90 |
) |
Depreciation and amortization |
|
|
1.67 |
|
|
|
1.76 |
|
|
|
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs per barrel |
|
$ |
6.27 |
|
|
$ |
7.26 |
|
|
$ |
(0.99 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income for regions above |
|
$ |
353 |
|
|
$ |
3,759 |
|
|
$ |
(3,406 |
) |
Asset impairment loss applicable to refining |
|
|
(574 |
) |
|
|
(43 |
) |
|
|
(531 |
) |
Loss
contingency accrual related to Aruban tax matter (g) |
|
|
(114 |
) |
|
|
|
|
|
|
(114 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total refining operating income (loss) |
|
$ |
(335 |
) |
|
$ |
3,716 |
|
|
$ |
(4,051 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See the footnote references on pages 61 and 62. |
60
Average
Market Reference Prices and Differentials (h)
(dollars per barrel)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
2009 |
|
2008 |
|
Change |
|
Feedstocks: |
|
|
|
|
|
|
|
|
|
|
|
|
WTI crude oil |
|
$ |
56.90 |
|
|
$ |
113.25 |
|
|
$ |
(56.35 |
) |
WTI less
sour crude oil at U.S. Gulf Coast (i) |
|
|
1.25 |
|
|
|
5.20 |
|
|
|
(3.95 |
) |
WTI less Mars crude oil |
|
|
1.06 |
|
|
|
6.40 |
|
|
|
(5.34 |
) |
WTI less Maya crude oil |
|
|
4.68 |
|
|
|
16.39 |
|
|
|
(11.71 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Products: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Gulf Coast: |
|
|
|
|
|
|
|
|
|
|
|
|
Conventional 87 gasoline less WTI |
|
|
8.85 |
|
|
|
7.66 |
|
|
|
1.19 |
|
No. 2 fuel oil less WTI |
|
|
6.40 |
|
|
|
19.17 |
|
|
|
(12.77 |
) |
Ultra-low-sulfur diesel less WTI |
|
|
8.59 |
|
|
|
24.38 |
|
|
|
(15.79 |
) |
Propylene less WTI |
|
|
(3.05 |
) |
|
|
(0.11 |
) |
|
|
(2.94 |
) |
U.S. Mid-Continent: |
|
|
|
|
|
|
|
|
|
|
|
|
Conventional 87 gasoline less WTI |
|
|
9.09 |
|
|
|
6.49 |
|
|
|
2.60 |
|
Low-sulfur diesel less WTI |
|
|
8.63 |
|
|
|
25.10 |
|
|
|
(16.47 |
) |
U.S. Northeast: |
|
|
|
|
|
|
|
|
|
|
|
|
Conventional 87 gasoline less WTI |
|
|
8.78 |
|
|
|
4.62 |
|
|
|
4.16 |
|
No. 2 fuel oil less WTI |
|
|
7.68 |
|
|
|
20.85 |
|
|
|
(13.17 |
) |
Lube oils less WTI |
|
|
40.54 |
|
|
|
51.75 |
|
|
|
(11.21 |
) |
U.S. West Coast: |
|
|
|
|
|
|
|
|
|
|
|
|
CARBOB 87 gasoline less WTI |
|
|
18.40 |
|
|
|
12.13 |
|
|
|
6.27 |
|
CARB diesel less WTI |
|
|
10.30 |
|
|
|
24.57 |
|
|
|
(14.27 |
) |
|
|
|
The following notes relate to references on pages 57 through 61. |
|
(a) |
|
The information presented for the nine months ended September 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 nine months ended September 30, 2009 are based on 273 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 nine months ended September
30, 2008. |
|
(c) |
|
The asset impairment loss for the nine months ended September 30, 2009 relates primarily to
charges of approximately $340 million resulting from the permanent shutdown of the
gasification unit at our Delaware City Refinery. The remaining loss for the nine
months ended September 30, 2009 relates to the permanent cancellation of certain capital
projects classified as construction in progress as a result of the unfavorable impact of the
continuing economic slowdown on refining industry fundamentals. Losses resulting from the
permanent cancellation of certain capital projects in prior periods have been reclassified
from operating expenses and presented separately for comparability with the 2009 presentation.
The asset impairment loss amounts have been excluded from operating costs in determining
operating costs per barrel, resulting in an adjustment to the operating costs per barrel
previously reported in 2008. |
|
(d) |
|
Throughput margin per barrel represents operating revenues less cost of sales divided by
throughput volumes. |
|
(e) |
|
Other products primarily include gas oils, No. 6 fuel oil, petroleum coke, and asphalt. |
|
(f) |
|
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 (prior to its sale effective July 1, 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. |
61
|
|
|
(g) |
|
A loss contingency accrual of $140 million was recorded in the third quarter of 2009
related to our dispute with the Government of Aruba regarding a turnover tax on export sales as well as
other tax matters. The portion of the loss contingency accrual that relates to the turnover tax was
recorded in cost of sales for the nine months ended September 30, 2009, and therefore is included in
refining operating income (loss) but has been excluded in determining throughput margin per barrel.
|
|
(h) |
|
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. |
|
(i) |
|
The market reference differential for sour crude oil is based on 50% Arab Medium and 50% Arab
Light posted prices. |
General
Operating revenues decreased 49% for the first nine months of 2009 compared to the first nine
months of 2008 primarily as a result of lower refined product prices between the two periods.
Operating income declined $4.0 billion and net income decreased
$2.7 billion for the nine months
ended September 30, 2009 compared to the amounts in the first nine months of 2008 primarily due to
a $4.1 billion decrease in refining segment operating income discussed below.
Refining
Operating income for our refining segment decreased from operating income of $3.7 billion for the
first nine months of 2008 to an operating loss of $335 million for the first nine months of 2009.
The decrease in operating income was attributable to a $532 million increase in asset impairment
losses (as further discussed in Note 4 of Condensed Notes to Consolidated Financial Statements), a
$305 million gain on the sale of the Krotz Springs Refinery in the third quarter of 2008 (as
further discussed in Note 3 of Condensed Notes to Consolidated
Financial Statements), a $114 million loss contingency accrual recorded in the third quarter of 2009 related to our dispute of a turnover tax on export sales in Aruba (as further discussed in Note 14 of Condensed Notes to Consolidated Financial Statements), a 44%
decrease in throughput margin per barrel, and an 8% decline in throughput volumes, partially offset
by a 15% decrease in refining operating expenses (including depreciation and amortization expense).
Total refining throughput margins for the first nine months of 2009 compared to the first nine
months of 2008 were impacted by the following factors:
|
|
|
Distillate margins in the first nine months of 2009 decreased significantly in all
of our refining regions from the high margins in the first nine 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 and residual fuel oil feedstock differentials to WTI crude oil
during the first nine months of 2009 declined significantly compared to the differentials
in the first nine months of 2008. The unfavorable sour crude oil differentials were
attributable mainly to reduced production of sour crude oil by OPEC and other producers as
well as high relative prices for residual fuel oil with which sour crude oil competes as a
refinery feedstock. The high relative residual fuel oil prices, and resulting narrow
residual fuel oil discounts, were caused by lower production of residual fuel oil
attributable to reduced refinery throughput due to lower refined product demand. This
reduced supply more than offset the effect of reduced worldwide demand for residual fuel
oil. |
|
|
|
Gasoline margins increased in all of our refining regions in the first nine months
of 2009 compared to the first nine months of 2008 primarily due to a better balance of
supply and demand. |
62
|
|
|
Margins on various secondary refined products such as asphalt, fuel oils, and
petroleum coke improved significantly from the first nine months of 2008 to the first nine
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. The price of West Texas
Intermediate crude oil declined by approximately $56 per barrel, or 50%, from the first
nine months of 2008 to the first nine months of 2009. |
|
|
|
Throughput margin for the first nine months of 2008 included approximately $100
million related to the McKee Refinery business interruption insurance settlement discussed
in Note 14 of Condensed Notes to Consolidated Financial Statements. |
|
|
|
Throughput volumes decreased 202,000 barrels per day during the first nine months
of 2009 compared to the first nine 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, (iv) the temporary shutdown of our Aruba Refinery commencing
in July 2009, and (v) 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 21% lower for
the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008
primarily due to a decrease in energy costs, lower maintenance expenses, a reduction in sales and
use taxes, lower variable compensation and overtime costs, and $43 million of operating expenses
related to the Krotz Springs Refinery prior to its sale effective July 1, 2008. Refining
depreciation and amortization expense increased 4% from the first nine months of 2008 to the first
nine months of 2009 primarily due to the completion of new capital projects and increased
turnaround and catalyst amortization.
Retail
Retail operating income was $232 million for the nine months ended September 30, 2009 compared to
$206 million for the nine months ended September 30, 2008. This 13% increase was primarily due to
increased in-store sales and lower selling expenses, partially offset by a $0.016 per gallon
decrease in fuel margins, in our U.S. retail operations.
Ethanol
Ethanol operating income was $71 million for the nine months ended September 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 $18
million from the first nine months of 2008 to the first nine months of 2009 due mainly to increases
in litigation costs, severance expenses, and costs associated with the VeraSun Acquisition,
partially offset by lower variable compensation expense and reductions in insurance expense,
professional fees, and environmental costs.
Other income for the first nine months of 2009 decreased from the first nine months of 2008
primarily due to a $53 million unfavorable change in fair value adjustments related to the Alon
earn-out agreement and associated derivative instruments (as discussed in Notes 3, 10, and
11 of Condensed Notes to Consolidated Financial Statements), reduced interest income resulting from
lower cash balances and
63
interest rates, and the nonrecurrence of a $14 million gain recognized in
the first nine months of 2008 on the redemption of our 9.5% senior notes as discussed in Note 6 of
Condensed Notes to Consolidated Financial Statements.
Interest and debt expense increased from the first nine months of 2008 to the first nine months of
2009 due mainly to interest incurred on $1 billion of debt issued in March 2009, partially offset
by increased capitalized interest resulting from a higher balance of capital projects under
construction during the first half of 2009.
Income tax expense decreased $1.4 billion from $1.1 billion of expense for the first nine months of
2008 to a $236 million benefit for the first nine 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, 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 with a resulting increase in refined product margins
and sour crude oil differentials.
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. These facilities continue to be temporarily
shut down, and they are expected to remain shut down until economic conditions improve. In
addition, in September, we permanently shut down the gasification unit at our Delaware City
Refinery. 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. Although feedstock discounts have improved recently,
refined product margins have weakened, so we expect overall throughput margins for the fourth
quarter to be similar to what we experienced in the third quarter, which could result in losses in
the fourth quarter and for the full year of 2009.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows for the Nine Months Ended September 30, 2009 and 2008
Net cash provided by operating activities for the nine months ended September 30, 2009 was $1.9
billion compared to $3.5 billion for the nine months ended September 30, 2008. The decrease in cash
generated from operating activities was primarily due to the cash utilization attributable to the
decrease in operating income discussed above under Results of Operations, partially offset by an
approximate $1.2 billion 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 nine
months of 2009 and 2008 are shown in Note 9 of Condensed Notes to Consolidated Financial
Statements. Both receivables and accounts payable increased for the first nine months of 2009 due
mainly to a significant increase in gasoline, distillate, and crude oil prices at September 30,
2009 compared to such prices at the end of 2008.
64
The net cash generated from operating activities during the first nine months of 2009, combined
with $998 million of proceeds from the issuance of $1 billion of notes in March 2009 as discussed
in Note 6 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 7 of
Condensed Notes to Consolidated Financial Statements, were used mainly to:
|
|
|
fund $2.1 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 $239 million; and |
|
|
|
increase available cash on hand by $665 million. |
The net cash generated from operating activities during the first nine months of 2008, combined
with $463 million of proceeds from the sale of our Krotz Springs Refinery, were used mainly to:
|
|
|
fund $2.2 billion of capital expenditures and deferred turnaround and catalyst
costs; |
|
|
|
make an early redemption of our 9.5% senior notes for $367 million and scheduled
long-term note repayments of $7 million; |
|
|
|
purchase 14.6 million shares of our common stock at a cost of $774 million; |
|
|
|
fund a $25 million contingent earn-out payment in connection with the acquisition
of the St. Charles Refinery, an $87 million acquisition of retail fuel sites, and a $57
million acquisition primarily of an interest in a refined product pipeline; |
|
|
|
pay common stock dividends of $221 million; and |
|
|
|
increase available cash on hand by $303 million. |
Capital Investments
During the nine months ended September 30, 2009, we expended $1.8 billion for capital expenditures
and $301 million for deferred turnaround and catalyst costs. Capital expenditures for the nine
months ended September 30, 2009 included $292 million of costs related to environmental projects.
For 2009, we expect to incur approximately $2.7 billion for capital investments, including
approximately $2.2 billion for capital expenditures (approximately $475 million of which is for
environmental projects) and approximately $500 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 September 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 $998
million, before deducting underwriting discounts and other issuance costs of $8 million.
65
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 September 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) was received
from the holders prior to September 15, 2009. A purchase notice was received related to $76 million
of the outstanding notes. We redeemed the $76 million of notes at 100% of their principal amount
plus accrued and unpaid interest to October 15, 2009, the date of the 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 extended through December 31, 2009 and
provided 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 and in
September 2009, Total completed its acquisition of Dows equity interest in TRN. Our obligations
under the Agreement have since been terminated.
Other than the TRN Refinery commitment discussed above, during the nine months ended September 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 September 30, 2009, all of our ratings on our senior unsecured debt are at or above
investment grade level as follows:
|
|
|
|
|
|
|
Standard & Poors Ratings Services
|
|
BBB (negative outlook) |
Moodys Investors Service
|
|
Baa2 (stable outlook) |
Fitch Ratings
|
|
BBB (stable outlook) |
We cannot provide assurance that these ratings will remain in effect for any given period of
time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating
agency. We note that these credit ratings are not recommendations to buy, sell, or hold our
securities and may be revised or withdrawn at any time by the rating agency. Each rating should be
evaluated independently of any other rating. Any future reduction or withdrawal of one or more of
our credit ratings could have a material adverse impact on our ability to obtain short- and
long-term financing and the cost of such financings.
66
Other Commercial Commitments
As of September 30, 2009, our committed lines of credit were as follows:
|
|
|
|
|
|
|
Borrowing |
|
|
|
|
Capacity |
|
Expiration |
|
Letter of credit facility |
|
$300 million |
|
June 2010 |
Revolving credit facility |
|
$2.5 billion |
|
November 2012 |
Canadian revolving credit facility |
|
Cdn. $115 million |
|
December 2012 |
In October 2009, Lehman Brothers Bank, FSB, one of the participating banks under our $2.5 billion
revolving credit facility, failed to fund its loan commitment related
to our borrowing under this facility discussed below.
Lehman Brothers aggregate commitment under the revolving credit facility was $84 million. As a
result, our borrowing capacity under that revolving credit facility has been reduced to $2.4 billion commencing in October 2009.
As of September 30, 2009, we had no amounts borrowed under our revolving credit facilities. However, we had $76 million of letters of credit outstanding under our uncommitted
short-term bank credit facilities and $113 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 September 30, 2009. Our letters of
credit expire during 2009 and 2010. In October 2009, we borrowed and
subsequently repaid approximately $40 million under our U.S. committed
revolving bank credit facility.
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.
Stock Purchase Programs
As of September 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 14 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 (NAI) pursuant to which we sought 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 also filed protests of
these assessments through proceedings in Aruba.
67
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. Amounts deposited under the escrow agreement, which totaled $114 million and
$102 million as of September 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 $20 million related to dividends. We
have also
challenged approximately $35 million in foreign exchange payments made to the Central Bank of
Aruba as payments exempted under our tax holiday, as well as other
reasons. Both the dividend tax and the foreign exchange payment
matters were also addressed in the arbitration proceedings discussed above.
On November 3, we received an interim First
Partial Award from the NAI arbitral panel.
The panels ruling validated our tax holiday agreement, but the panel also ruled in favor of the GOA
on our dispute of the $35 million in foreign exchange payments previously made to the Central Bank of
Aruba. The panels decision did not, however, fully resolve the remaining two items in the arbitration,
the applicable dividend tax rate and the turnover tax. With respect to the dividend tax, the panel ruled that
the dividend tax was not a profit tax covered by the tax holiday agreement, but the panel did not address the
fact that Aruban companies with tax holidays are subject to a 0% dividend withholding rate rather than the 5%
rate alleged by the GOA. With respect to the turnover tax, the panel did reject our contractual claims but it
decided that our non-contractual claims against the turnover tax merited further discussion with and review by
the panel before a final decision could be rendered. Prior to this interim decision, no expense or liability had
been recognized in our consolidated financial statements with respect to unfunded amounts. In light of
the now uncertain timing of any final resolution of these claims, we have recorded a loss contingency accrual
of approximately $140 million, including interest, with respect to both the dividend and turnover taxes.
We continue to believe that our remaining claims against these taxes have significant merit, and intend to
vigorously pursue these claims through the arbitration proceedings and in on-island proceedings as well.
Asset Impairments
Long-lived assets are 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.
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 second half 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
68
conditions during 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 nine months of 2009, thereby impacting 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 September 30, 2009, as narrow heavy sour crude oil differentials made the
refinery uneconomical to operate. The Aruba Refinery was shut down in July 2009 and is expected to
continue to be shut down until market conditions improve. We are continuing to evaluate potential
alternatives 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 and remains shut down.
In September 2009, we announced the shutdown of our coker and gasification units at our Delaware
City Refinery also due to economic reasons. The coker unit is expected to remain shut down until
economics improve and the gasification unit has been permanently shut down. As a result
of these factors, we readdressed the potential impairment of all of our facilities (excluding the
Delaware City gasification unit) as of September 30, 2009 based on an assumption that we would
operate these facilities in the future, 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 September 30, 2009.
However, due to the permanent shutdown of the
gasification unit at the Delaware
City Refinery, we recorded a pre-tax loss of approximately $280 million related to the abandonment
of that unit.
Due to the impact of the continuing economic slowdown on refining industry fundamentals, we further
evaluated the recoverability of all of our capital projects currently classified as construction
in progress during the third quarter of 2009. This is a continuation of an ongoing process that
had commenced during the second half of 2008. As a result of this assessment, certain additional
capital projects were permanently cancelled, resulting in write-offs of $137 million of project
costs for the three months ended September 30, 2009 (of which approximately $60 million was for
projects related to the gasification unit at our Delaware City Refinery). This amount, combined
with capital projects written off earlier in 2009, has resulted in total write-offs of capital
projects of $295 million for the nine months ended September 30, 2009.
In addition to capital projects that have been written off, 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
temporarily suspended until market conditions and cash flows improve. As of September 30, 2009,
approximately $1.0 billion of costs had been incurred on these two projects. In addition, various
other projects with a total cost of approximately $600 million as of September 30, 2009 have also
been temporarily suspended. These suspended projects are included in our strategic plan, and the
costs incurred to date have not been written off. We believe that the overall
market conditions and our cash flows will improve in the future such that the completion and
recoverability of these temporarily suspended projects is probable.
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 additional potential asset impairments until
conditions improve. Changes in market conditions, as well as changes in assumptions used to test
for recoverability and to determine fair value, could result in additional significant impairment
charges in the future, thus affecting our earnings.
69
American Clean Energy and Security Act of 2009 and Clean Energy Jobs and American Power Act of 2009
On June 26, 2009, the U.S. House of Representatives narrowly approved the American Clean Energy and
Security Act of 2009, also known as the Waxman-Markey bill. On September 30, 2009, the U.S. Senate
Committee on Environment and Public Works introduced a similar bill in the Senate, the Clean Energy
Jobs and American Power Act of 2009, also known as the Kerry-Boxer bill. These bills, if passed by
Congress, would establish a national cap-and-trade program beginning in 2012 to address
greenhouse gas emissions and climate change. The Waxman-Markey bill 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, while the Kerry-Boxer
bill proposes a more accelerated timetable for carbon dioxide reductions. The cap-and-trade program
would require businesses that emit greenhouse gases to buy 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 would 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 a
cap-and-trade bill (or whether such a bill will be passed by Congress),
any new federal restrictions on greenhouse gas emissions including a cap-and-trade program
could result in material increased compliance costs, additional operating restrictions for our
business, and an increase in the cost of the products we produce, which could have an adverse
effect on our financial position, results of operations, and liquidity.
Other
During the nine months ended September 30, 2009, we contributed $72 million to our qualified
pension plans. No additional contributions to the qualified pension plans are anticipated during
2009.
On October 15, 2009, our board of directors declared a regular quarterly cash dividend of $0.15 per
common share payable on December 9, 2009 to holders of record at the close of business on November
11, 2009. At the same time, we announced that if industry conditions do not improve measurably for
2010, our board of directors would evaluate a reduction in the amount of our quarterly dividend
payment.
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.
70
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.
71
Item 3. Quantitative and Qualitative Disclosures About Market Risk
COMMODITY PRICE RISK
For information regarding gains and losses on our derivative instruments, see Note 11 of Condensed
Notes to Consolidated Financial Statements. The following tables provide information about our
commodity derivative instruments as of September 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 September 30, 2009 and December
31, 2008, respectively, and a fair value of $7.4 billion and $5.1 billion as of September 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; and |
|
|
|
|
manage price volatility in forecasted refinery feedstock, product, and grain
purchases, refined product sales, and
natural gas purchases. |
In addition, through August 2009, we used economic hedges to manage price volatility in the
referenced product margins associated with the three-year earn-out agreement with Alon that was
entered into in connection with the sale of our Krotz Springs Refinery, but which was settled
in the third quarter of 2009 as discussed in Note 3 of Condensed Notes to Consolidated
Financial Statements. 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 commodity derivative 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
72
contract price for long positions and the weighted-average receive price represents the contract
price for short positions. The weighted-average pay price and weighted-average receive price for
options represent their strike price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2009 |
|
|
|
|
|
|
Wtd Avg |
|
Wtd Avg |
|
|
|
|
|
|
|
|
|
Pre-tax |
|
|
Contract |
|
Pay |
|
Receive |
|
Contract |
|
Market |
|
Fair |
|
|
Volumes |
|
Price |
|
Price |
|
Value |
|
Value |
|
Value |
|
Fair Value Hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Futures short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
5,133 |
|
|
|
N/A |
|
|
$ |
71.05 |
|
|
$ |
364 |
|
|
$ |
364 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
10,722 |
|
|
$ |
99.45 |
|
|
|
74.59 |
|
|
|
N/A |
|
|
|
(267 |
) |
|
|
(267 |
) |
2010 (crude oil and refined products) |
|
|
24,810 |
|
|
|
67.67 |
|
|
|
77.14 |
|
|
|
N/A |
|
|
|
235 |
|
|
|
235 |
|
Swaps short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
10,722 |
|
|
|
74.59 |
|
|
|
107.41 |
|
|
|
N/A |
|
|
|
352 |
|
|
|
352 |
|
2010 (crude oil and refined products) |
|
|
24,810 |
|
|
|
80.16 |
|
|
|
72.65 |
|
|
|
N/A |
|
|
|
(186 |
) |
|
|
(186 |
) |
Futures long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
1,218 |
|
|
|
66.46 |
|
|
|
N/A |
|
|
|
81 |
|
|
|
86 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Economic Hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
45,030 |
|
|
|
25.21 |
|
|
|
21.70 |
|
|
|
N/A |
|
|
|
(158 |
) |
|
|
(158 |
) |
2010 (crude oil and refined products) |
|
|
107,194 |
|
|
|
31.37 |
|
|
|
26.58 |
|
|
|
N/A |
|
|
|
(513 |
) |
|
|
(513 |
) |
2011 (crude oil and refined products) |
|
|
26,275 |
|
|
|
21.55 |
|
|
|
14.49 |
|
|
|
N/A |
|
|
|
(186 |
) |
|
|
(186 |
) |
Swaps short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
20,458 |
|
|
|
47.93 |
|
|
|
57.57 |
|
|
|
N/A |
|
|
|
197 |
|
|
|
197 |
|
2010 (crude oil and refined products) |
|
|
63,633 |
|
|
|
47.78 |
|
|
|
58.42 |
|
|
|
N/A |
|
|
|
677 |
|
|
|
677 |
|
2011 (crude oil and refined products) |
|
|
11,025 |
|
|
|
34.68 |
|
|
|
52.45 |
|
|
|
N/A |
|
|
|
196 |
|
|
|
196 |
|
Futures long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
222,053 |
|
|
|
70.61 |
|
|
|
N/A |
|
|
|
15,678 |
|
|
|
16,153 |
|
|
|
475 |
|
2010 (crude oil and refined products) |
|
|
102,235 |
|
|
|
75.79 |
|
|
|
N/A |
|
|
|
7,748 |
|
|
|
8,189 |
|
|
|
441 |
|
2009 (grain) |
|
|
3,705 |
|
|
|
3.20 |
|
|
|
N/A |
|
|
|
12 |
|
|
|
13 |
|
|
|
1 |
|
2010 (grain) |
|
|
75 |
|
|
|
4.03 |
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
Futures short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
216,315 |
|
|
|
N/A |
|
|
|
71.20 |
|
|
|
15,401 |
|
|
|
15,767 |
|
|
|
(366 |
) |
2010 (crude oil and refined products) |
|
|
101,388 |
|
|
|
N/A |
|
|
|
74.63 |
|
|
|
7,567 |
|
|
|
7,998 |
|
|
|
(431 |
) |
2009 (grain) |
|
|
10,585 |
|
|
|
N/A |
|
|
|
3.51 |
|
|
|
37 |
|
|
|
36 |
|
|
|
1 |
|
2010 (grain) |
|
|
4,495 |
|
|
|
N/A |
|
|
|
4.26 |
|
|
|
19 |
|
|
|
16 |
|
|
|
3 |
|
Options long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
6 |
|
|
|
37.94 |
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 (crude oil and refined products) |
|
|
511 |
|
|
|
40.44 |
|
|
|
N/A |
|
|
|
1 |
|
|
|
1 |
|
|
|
|
|
Options short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 (crude oil and refined products) |
|
|
500 |
|
|
|
N/A |
|
|
|
42.50 |
|
|
|
2 |
|
|
|
1 |
|
|
|
1 |
|
73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2009 |
|
|
|
|
|
|
Wtd Avg |
|
Wtd Avg |
|
|
|
|
|
|
|
|
|
Pre-tax |
|
|
Contract |
|
Pay |
|
Receive |
|
Contract |
|
Market |
|
Fair |
|
|
Volumes |
|
Price |
|
Price |
|
Value |
|
Value |
|
Value |
|
Trading Activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
6,502 |
|
|
$ |
48.69 |
|
|
$ |
37.91 |
|
|
|
N/A |
|
|
$ |
(70 |
) |
|
$ |
(70 |
) |
2010 (crude oil and refined products) |
|
|
23,589 |
|
|
|
21.20 |
|
|
|
24.20 |
|
|
|
N/A |
|
|
|
71 |
|
|
|
71 |
|
2011 (crude oil and refined products) |
|
|
3,000 |
|
|
|
53.70 |
|
|
|
56.64 |
|
|
|
N/A |
|
|
|
9 |
|
|
|
9 |
|
Swaps short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
5,679 |
|
|
|
42.57 |
|
|
|
56.44 |
|
|
|
N/A |
|
|
|
79 |
|
|
|
79 |
|
2010 (crude oil and refined products) |
|
|
27,946 |
|
|
|
20.62 |
|
|
|
20.05 |
|
|
|
N/A |
|
|
|
(16 |
) |
|
|
(16 |
) |
2011 (crude oil and refined products) |
|
|
3,900 |
|
|
|
43.57 |
|
|
|
43.29 |
|
|
|
N/A |
|
|
|
(1 |
) |
|
|
(1 |
) |
Futures long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
25,809 |
|
|
|
76.91 |
|
|
|
N/A |
|
|
$ |
1,985 |
|
|
|
1,887 |
|
|
|
(98 |
) |
2010 (crude oil and refined products) |
|
|
4,318 |
|
|
|
77.88 |
|
|
|
N/A |
|
|
|
336 |
|
|
|
343 |
|
|
|
7 |
|
2009 (natural gas) |
|
|
3,750 |
|
|
|
5.59 |
|
|
|
N/A |
|
|
|
21 |
|
|
|
21 |
|
|
|
|
|
2010 (natural gas) |
|
|
100 |
|
|
|
6.10 |
|
|
|
N/A |
|
|
|
1 |
|
|
|
1 |
|
|
|
|
|
Futures short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
25,859 |
|
|
|
N/A |
|
|
|
77.22 |
|
|
|
1,997 |
|
|
|
1,893 |
|
|
|
104 |
|
2010 (crude oil and refined products) |
|
|
4,268 |
|
|
|
N/A |
|
|
|
76.94 |
|
|
|
328 |
|
|
|
338 |
|
|
|
(10 |
) |
2009 (natural gas) |
|
|
3,750 |
|
|
|
N/A |
|
|
|
5.37 |
|
|
|
20 |
|
|
|
21 |
|
|
|
(1 |
) |
2010 (natural gas) |
|
|
100 |
|
|
|
N/A |
|
|
|
5.46 |
|
|
|
1 |
|
|
|
1 |
|
|
|
|
|
Options long: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
40 |
|
|
|
42.50 |
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
Options short: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (crude oil and refined products) |
|
|
40 |
|
|
|
N/A |
|
|
|
17.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total pre-tax fair value of open
positions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
551 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
76
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 September 30, 2009 and December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2009 |
|
|
Expected Maturity Dates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
There- |
|
|
|
|
|
Fair |
|
|
2009 |
|
2010 |
|
2011 |
|
2012 |
|
2013 |
|
after |
|
Total |
|
Value |
|
Debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed rate |
|
$ |
76 |
|
|
$ |
33 |
|
|
$ |
418 |
|
|
$ |
759 |
|
|
$ |
489 |
|
|
$ |
5,521 |
|
|
$ |
7,296 |
|
|
$ |
8,235 |
|
Average interest rate |
|
|
6.8 |
% |
|
|
6.8 |
% |
|
|
6.4 |
% |
|
|
6.9 |
% |
|
|
5.5 |
% |
|
|
7.3 |
% |
|
|
7.1 |
% |
|
|
|
|
Floating rate |
|
$ |
|
|
|
$ |
100 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
100 |
|
|
$ |
100 |
|
Average interest rate |
|
|
|
% |
|
|
1.1 |
% |
|
|
|
% |
|
|
|
% |
|
|
|
% |
|
|
|
% |
|
|
1.1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 September 30, 2009, we had commitments to purchase $248 million of U.S. dollars. These
commitments matured on or before November 2, 2009, resulting in a $5 million loss in the fourth
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 September 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.
77
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 quarters ended March 31, 2009 and June 30, 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 14 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) (this matter was last
reported in our Form 10-Q for the quarter ended June 30, 2009). On July 9, 2009, the EPA issued a
demand for a stipulated penalty under a Section 114 Consent Decree for an acid gas flaring incident
in September 2008 at our Paulsboro Refinery. We paid the final penalty amount on August 20, 2009.
EPA (Paulsboro Refinery). In September 2009, the
EPA issued a proposed penalty of $211,000 in connection with an alleged unit leak of chlorinated
fluorocarbons at our Paulsboro Refinery. We are in negotiations with the EPA to resolve this
matter.
Delaware Department of Natural Resources and Environmental Control (DDNREC) (Delaware City
Refinery). Our Delaware City Refinery received a stipulated penalty demand from the DDNREC in
August 2009 for $200,000, and another in October 2009 for $100,000, for our alleged failure to
complete construction of a coke storage and handling system on a timely basis. The refinery
received an additional stipulated penalty demand in October 2009 for $250,000 for our alleged
failure to timely complete construction on certain FCCU NOx controls. We are filing dispute
resolutions at the DDNREC in connection with each of these stipulated penalty demands, and we are
negotiating with the DDNREC to resolve these matters.
78
New Jersey Department of Environmental Protection (NJDEP) (Paulsboro Refinery). In March 2009 and
August 2009, the NJDEP issued an Administrative Order of Revocation and Notice of Administrative
Civil Penalty Assessments (Notice) to our Paulsboro Refinery. The first Notice relates to an FCC
stack test conducted in 2007. The second Notice relates to an FCC stack test conducted in February
2009. The Notices assess penalties of $40,000 and $285,000, respectively, and direct the Refinery
to either perform a new stack test or submit an application to modify the permit limits. We have
commenced discussions with the NJDEP to resolve this matter, and we continue to work with the NJDEP
on additional stack testing. Appeals and requests for a stay on both Notices have been filed. The
stay on the first Notice has been granted, and the request for stay on the second Notice has yet to
be ruled on.
Texas Commission on Environmental Quality (TCEQ) (McKee Refinery). In August 2009, our McKee
Refinery received an agreed order from the TCEQ with a proposed administrative penalty of $469,251
for a number of self-reported Title V permit deviations that occurred in 2008 and several emission
events that occurred in 2009. We have commenced discussions with the TCEQ to resolve this matter.
TCEQ (Port Arthur Refinery) (this matter was last reported in our Form 10-K for the year ended
December 31, 2008). In September 2005, we received two enforcement actions from the TCEQ relating
to alleged Texas Clean Air Act violations at the Port Arthur Refinery dating back to 2002. In 2007,
these enforcement actions were referred to the Texas Attorney Generals office and consolidated
with TCEQ Docket No. 2005-1596-AIR-E. In the third quarter 2009, we settled these matters with the
Texas Attorney Generals office. The agreed final judgment was filed on September 23, 2009, and
this matter is now fully resolved.
TCEQ (Port Arthur Refinery). In October 2009, our Port Arthur Refinery received a proposed Agreed
Order from the TCEQ for $155,825 relating to alleged multiple emissions events in 2008 and early
2009. We are reviewing the proposed order and evaluating our options for response.
Item 1A. Risk Factors
There have been no material changes from the risk factors disclosed in the Risk Factors section
of our annual report on Form 10-K for the year ended December 31, 2008.
79
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) |
|
|
July 2009 |
|
|
|
1,939 |
|
|
|
$ 15.92 |
|
|
|
|
1,939 |
|
|
|
|
|
|
|
|
$ 3.46 billion |
|
|
August 2009 |
|
|
|
93 |
|
|
|
$ 18.60 |
|
|
|
|
93 |
|
|
|
|
|
|
|
|
$ 3.46 billion |
|
|
September 2009 |
|
|
|
1,448 |
|
|
|
$ 18.90 |
|
|
|
|
1,448 |
|
|
|
|
|
|
|
|
$ 3.46 billion |
|
|
Total |
|
|
|
3,480 |
|
|
|
$ 17.23 |
|
|
|
|
3,480 |
|
|
|
|
|
|
|
|
$ 3.46 billion |
|
|
|
|
|
(1) |
|
The shares reported in this column represent purchases settled in the third 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. |
80
Item 6. Exhibits
|
|
|
Exhibit No. |
|
Description |
|
|
|
|
*12.01
|
|
Statements of Computations of Ratios of Earnings to Fixed Charges and Ratios of Earnings to
Fixed Charges and Preferred Stock Dividends. |
|
|
|
*31.01
|
|
Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of
principal executive officer. |
|
|
|
*31.02
|
|
Rule 13a-14(a) Certification (under Section 302 of the Sarbanes-Oxley Act of 2002) of
principal financial officer. |
|
|
|
*32.01
|
|
Section 1350 Certifications (as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002). |
|
|
|
**101
|
|
The following materials from Valero Energy Corporations Form 10-Q for the quarter ended
September 30, 2009, formatted in XBRL (Extensible Business Reporting Language): (i)
Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated
Statements of Cash Flows, (iv) Consolidated Statements of Other Comprehensive Income, and (v)
Condensed Notes to Consolidated Financial Statements, tagged as blocks of text. |
|
|
|
* |
|
Filed herewith. |
|
** |
|
Submitted electronically herewith. |
In accordance with Rule 402 of Regulation S-T, the XBRL information in Exhibit 101 to this
Quarterly Report on Form 10-Q shall not be deemed to be filed for purposes of Section 18 of the
Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liability
of that section, and shall not be incorporated by reference into any registration statement or
other document filed under the Securities Act of 1933, as amended, or the Exchange Act, except as
shall be expressly set forth by specific reference in such filing.
81
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
|
|
|
|
VALERO ENERGY CORPORATION
(Registrant)
|
|
|
By: |
/s/ Michael S. Ciskowski
|
|
|
|
Michael S. Ciskowski |
|
|
|
Executive Vice President and
Chief Financial Officer
(Duly Authorized Officer and Principal
Financial and Accounting Officer) |
|
|
Date: November 5, 2009
82