e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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(Mark One) |
[X] |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For
the quarterly period ended
September 30, 2011
or
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[ ] |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from
to
Commission file number:
001-32395
ConocoPhillips
(Exact name of registrant as specified in its charter)
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Delaware
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01-0562944 |
(State or other jurisdiction of
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(I.R.S. Employer |
incorporation or organization)
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Identification No.) |
600 North Dairy Ashford, Houston, TX 77079
(Address of principal executive offices) (Zip Code)
281-293-1000
(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 [X] No [ ]
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 during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files). Yes [X] No [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
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Large accelerated filer [X]
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Accelerated filer [ ]
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Non-accelerated filer [ ]
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Smaller reporting company [ ] |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes [ ] No [X]
The registrant had 1,327,738,781 shares of common stock, $.01 par value, outstanding at September
30, 2011.
CONOCOPHILLIPS
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
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Consolidated Income Statement
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ConocoPhillips |
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Millions of Dollars |
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Three Months Ended |
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Nine Months Ended |
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September 30 |
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September 30 |
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2011 |
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2010 |
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2011 |
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2010 |
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Revenues and Other Income |
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Sales and other operating revenues* |
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$ |
62,784 |
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47,208 |
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184,941 |
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137,715 |
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Equity in earnings of affiliates |
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1,298 |
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|
1,004 |
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3,475 |
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2,960 |
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Gain (loss) on dispositions** |
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(480 |
) |
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1,398 |
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214 |
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4,671 |
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Other income (loss)** |
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27 |
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(61 |
) |
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207 |
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|
92 |
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Total Revenues and Other Income |
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63,629 |
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49,549 |
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188,837 |
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145,438 |
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Costs and Expenses |
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Purchased crude oil, natural gas and products |
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47,597 |
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34,051 |
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140,106 |
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97,660 |
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Production and operating expenses |
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2,768 |
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2,583 |
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8,002 |
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7,729 |
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Selling, general and administrative expenses |
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466 |
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493 |
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1,479 |
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|
1,375 |
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Exploration expenses |
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266 |
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252 |
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706 |
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848 |
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Depreciation, depletion and amortization |
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1,870 |
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2,246 |
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6,015 |
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6,844 |
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Impairments |
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486 |
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59 |
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|
488 |
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|
1,682 |
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Taxes other than income taxes* |
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4,579 |
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4,227 |
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13,773 |
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12,511 |
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Accretion on discounted liabilities |
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114 |
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110 |
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341 |
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337 |
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Interest and debt expense |
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235 |
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264 |
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744 |
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914 |
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Foreign currency transaction (gains) losses |
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68 |
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(10 |
) |
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15 |
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80 |
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Total Costs and Expenses |
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58,449 |
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44,275 |
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171,669 |
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129,980 |
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Income before income taxes |
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5,180 |
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5,274 |
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17,168 |
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15,458 |
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Provision for income taxes |
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2,549 |
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2,205 |
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8,076 |
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6,094 |
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Net income |
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2,631 |
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|
3,069 |
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|
9,092 |
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9,364 |
|
Less: net income attributable to noncontrolling interests |
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(15 |
) |
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(14 |
) |
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(46 |
) |
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(47 |
) |
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Net Income Attributable to ConocoPhillips |
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$ |
2,616 |
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3,055 |
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9,046 |
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9,317 |
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Net Income Attributable to ConocoPhillips Per Share of
Common Stock (dollars) |
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Basic |
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$ |
1.93 |
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2.06 |
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6.48 |
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6.26 |
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Diluted |
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1.91 |
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2.05 |
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6.42 |
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6.21 |
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Dividends Paid Per Share of Common Stock (dollars) |
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$ |
.66 |
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|
.55 |
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1.98 |
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1.60 |
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Average Common Shares Outstanding (in thousands) |
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Basic |
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1,357,710 |
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1,481,522 |
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1,396,216 |
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1,488,024 |
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Diluted |
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1,369,562 |
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1,493,080 |
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1,408,846 |
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1,499,367 |
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* Includes excise taxes on petroleum products sales: |
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$ |
3,596 |
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3,544 |
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10,532 |
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10,181 |
|
** 2010 has been reclassified to conform to current-year presentation.
See Notes to Consolidated Financial Statements.
1
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Consolidated Balance Sheet
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ConocoPhillips |
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Millions of Dollars |
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September 30 |
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December 31 |
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2011 |
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2010 |
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Assets |
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Cash and cash equivalents |
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$ |
3,437 |
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9,454 |
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Short-term investments* |
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2,589 |
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|
973 |
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Accounts and notes receivable (net of allowance of $29 million in 2011
and $32 million in 2010) |
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14,440 |
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13,787 |
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Accounts and notes receivablerelated parties |
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1,976 |
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2,025 |
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Investment in LUKOIL |
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- |
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|
1,083 |
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Inventories |
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7,164 |
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|
5,197 |
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Prepaid expenses and other current assets |
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2,785 |
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2,141 |
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Total Current Assets |
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32,391 |
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34,660 |
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Investments and long-term receivables |
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32,152 |
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31,581 |
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Loans and advancesrelated parties |
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1,694 |
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2,180 |
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Net properties, plants and equipment |
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|
83,090 |
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|
82,554 |
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Goodwill |
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|
3,606 |
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3,633 |
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Intangibles |
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|
764 |
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|
801 |
|
Other assets |
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|
992 |
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|
905 |
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Total Assets |
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$ |
154,689 |
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|
156,314 |
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Liabilities |
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Accounts payable |
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$ |
18,855 |
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|
16,613 |
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Accounts payablerelated parties |
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1,980 |
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|
1,786 |
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Short-term debt |
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616 |
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|
936 |
|
Accrued income and other taxes |
|
|
4,573 |
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|
4,874 |
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Employee benefit obligations |
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|
894 |
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1,081 |
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Other accruals |
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2,018 |
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2,129 |
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Total Current Liabilities |
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28,936 |
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27,419 |
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Long-term debt |
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22,534 |
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22,656 |
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Asset retirement obligations and accrued environmental costs |
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9,286 |
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9,199 |
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Joint venture acquisition obligationrelated party |
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3,769 |
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4,314 |
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Deferred income taxes |
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|
17,979 |
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|
17,335 |
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Employee benefit obligations |
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3,078 |
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|
3,683 |
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Other liabilities and deferred credits |
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|
2,781 |
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|
2,599 |
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Total Liabilities |
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88,363 |
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|
87,205 |
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Equity |
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Common stock (2,500,000,000 shares authorized at $.01 par value) |
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Issued (20111,746,731,975 shares; 20101,740,529,279 shares) |
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Par value |
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|
17 |
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|
17 |
|
Capital in excess of par |
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44,610 |
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|
44,132 |
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Grantor trusts (at cost: 2011189,697 shares; 201036,890,375 shares) |
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|
(11 |
) |
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|
(633 |
) |
Treasury stock (at cost: 2011418,803,497 shares; 2010272,873,537
shares) |
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|
(28,671 |
) |
|
|
(20,077 |
) |
Accumulated other comprehensive income |
|
|
3,203 |
|
|
|
4,773 |
|
Unearned employee compensation |
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|
(23 |
) |
|
|
(47 |
) |
Retained earnings |
|
|
46,681 |
|
|
|
40,397 |
|
|
Total Common Stockholders Equity |
|
|
65,806 |
|
|
|
68,562 |
|
Noncontrolling interests |
|
|
520 |
|
|
|
547 |
|
|
Total Equity |
|
|
66,326 |
|
|
|
69,109 |
|
|
Total Liabilities and Equity |
|
$ |
154,689 |
|
|
|
156,314 |
|
|
*Includes marketable securities of: |
|
$ |
1,442 |
|
|
|
602 |
|
See Notes to Consolidated Financial Statements.
2
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|
Consolidated Statement of Cash Flows
|
|
ConocoPhillips |
|
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|
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|
|
|
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|
Millions of Dollars |
|
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
|
2011 |
|
|
2010 |
|
|
|
|
Cash Flows From Operating Activities |
|
|
|
|
|
|
|
|
Net income |
|
$ |
9,092 |
|
|
|
9,364 |
|
Adjustments to reconcile net income to net cash provided by operating activities |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
6,015 |
|
|
|
6,844 |
|
Impairments |
|
|
488 |
|
|
|
1,682 |
|
Dry hole costs and leasehold impairments |
|
|
290 |
|
|
|
327 |
|
Accretion on discounted liabilities |
|
|
341 |
|
|
|
337 |
|
Deferred taxes |
|
|
809 |
|
|
|
(935 |
) |
Undistributed equity earnings |
|
|
(1,392 |
) |
|
|
(1,642 |
) |
Gain on dispositions |
|
|
(214 |
) |
|
|
(4,671 |
) |
Other |
|
|
(216 |
) |
|
|
(221 |
) |
Working capital adjustments |
|
|
|
|
|
|
|
|
Decrease (increase) in accounts and notes receivable |
|
|
(1,006 |
) |
|
|
323 |
|
Decrease (increase) in inventories |
|
|
(1,979 |
) |
|
|
(2,898 |
) |
Decrease (increase) in prepaid expenses and other current assets |
|
|
(556 |
) |
|
|
(459 |
) |
Increase (decrease) in accounts payable |
|
|
2,759 |
|
|
|
401 |
|
Increase (decrease) in taxes and other accruals |
|
|
(597 |
) |
|
|
2,402 |
|
|
Net Cash Provided by Operating Activities |
|
|
13,834 |
|
|
|
10,854 |
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities |
|
|
|
|
|
|
|
|
Capital expenditures and investments |
|
|
(9,394 |
) |
|
|
(6,371 |
) |
Proceeds from asset dispositions |
|
|
2,158 |
|
|
|
12,233 |
|
Net purchases of short-term investments |
|
|
(1,623 |
) |
|
|
- |
|
Long-term advances/loansrelated parties |
|
|
(14 |
) |
|
|
(296 |
) |
Collection of advances/loansrelated parties |
|
|
638 |
|
|
|
104 |
|
Other |
|
|
96 |
|
|
|
114 |
|
|
Net Cash Provided by (Used in) Investing Activities |
|
|
(8,139 |
) |
|
|
5,784 |
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities |
|
|
|
|
|
|
|
|
Issuance of debt |
|
|
- |
|
|
|
96 |
|
Repayment of debt |
|
|
(440 |
) |
|
|
(5,304 |
) |
Issuance of company common stock |
|
|
109 |
|
|
|
59 |
|
Repurchase of company common stock |
|
|
(7,984 |
) |
|
|
(1,258 |
) |
Dividends paid on company common stock |
|
|
(2,761 |
) |
|
|
(2,376 |
) |
Other |
|
|
(542 |
) |
|
|
(544 |
) |
|
Net Cash Used in Financing Activities |
|
|
(11,618 |
) |
|
|
(9,327 |
) |
|
|
|
|
|
|
|
|
|
|
Effect of Exchange Rate Changes on Cash and Cash Equivalents |
|
|
(94 |
) |
|
|
143 |
|
|
|
|
|
|
|
|
|
|
|
Net Change in Cash and Cash Equivalents |
|
|
(6,017 |
) |
|
|
7,454 |
|
Cash and cash equivalents at beginning of period |
|
|
9,454 |
|
|
|
542 |
|
|
Cash and Cash Equivalents at End of Period |
|
$ |
3,437 |
|
|
|
7,996 |
|
|
See Notes to Consolidated Financial Statements.
3
|
|
|
|
Notes to Consolidated Financial Statements
|
|
ConocoPhillips |
Note 1Interim Financial Information
The interim-period financial information presented in the financial statements included in this
report is unaudited and includes all known accruals and adjustments, in the opinion of management,
necessary for a fair presentation of the consolidated financial position of ConocoPhillips and its
results of operations and cash flows for such periods. All such adjustments are of a normal and
recurring nature. To enhance your understanding of these interim financial statements, see the
consolidated financial statements and notes included in our 2010 Annual Report on Form 10-K.
Note 2 Variable Interest Entities (VIEs)
We hold significant variable interests in VIEs that have not been consolidated because we are not
considered the primary beneficiary. Information on these VIEs follows:
We have a 30 percent ownership interest with a 50 percent governance interest in the OOO
Naryanmarneftegaz (NMNG) joint venture to develop resources in the Timan-Pechora province of
Russia. The NMNG joint venture is a VIE because we and our co-venturer, LUKOIL, have
disproportionate interests, and LUKOIL was a related party at inception of the joint venture.
Since LUKOIL is no longer a related party, we do not believe NMNG would be a VIE if reconsidered
today. LUKOIL owns 70 percent versus our 30 percent direct interest; therefore, we have determined
we are not the primary beneficiary of NMNG, and we use the equity method of accounting for this
investment. The funding of NMNG has been provided with equity contributions, primarily for the
development of the Yuzhno Khylchuyu (YK) Field. The book value of our investment in the venture
was $677 million and $735 million at September 30, 2011, and December 31, 2010, respectively.
We have an agreement with Freeport LNG Development, L.P. (Freeport LNG) to participate in a
liquefied natural gas (LNG) receiving terminal in Quintana, Texas. We have no ownership in
Freeport LNG; however, we own a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which
serves as the general partner managing the venture. We entered into a credit agreement with
Freeport LNG, whereby we agreed to provide loan financing for the construction of the terminal. We
also entered into a long-term agreement with Freeport LNG to use 0.9 billion cubic feet per day of
regasification capacity. The terminal became operational in June 2008, and we began making
payments under the terminal use agreement. Freeport LNG began making loan repayments in September
2008, and the loan balance outstanding was $622 million at September 30, 2011, and $653 million at
December 31, 2010. Freeport LNG is a VIE because Freeport GP holds no equity in Freeport LNG, and
the limited partners of Freeport LNG do not have any substantive decision making ability. We
performed an analysis of the expected losses and determined we are not the primary beneficiary.
This expected loss analysis took into account that the credit support arrangement requires Freeport
LNG to maintain sufficient commercial insurance to mitigate any loan losses. The loan to Freeport
LNG is accounted for as a financial asset, and our investment in Freeport GP is accounted for as an
equity investment.
Note 3Inventories
Inventories consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
September 30 |
|
|
December 31 |
|
|
|
2011 |
|
|
2010 |
|
|
|
|
Crude oil and petroleum products |
|
$ |
6,164 |
|
|
|
4,254 |
|
Materials, supplies and other |
|
|
1,000 |
|
|
|
943 |
|
|
|
|
$ |
7,164 |
|
|
|
5,197 |
|
|
4
Inventories valued on the last-in, first-out (LIFO) basis totaled $5,883 million and $4,051 million
at
September 30, 2011, and December 31, 2010, respectively. The estimated excess of current
replacement cost over LIFO cost of inventories amounted to approximately $7,300 million and $6,800
million at September 30, 2011, and December 31, 2010, respectively.
Note 4Investments, Loans and Long-Term Receivables
Australia Pacific LNG
In April 2011, Australia Pacific LNG Pty Ltd (APLNG) and China Petrochemical Corporation (Sinopec)
signed definitive agreements for APLNG to supply up to 4.3 million tonnes per annum of LNG for 20
years. The agreements also specify terms under which Sinopec subscribed for a 15 percent equity
interest in APLNG, with both our ownership interest and Origin Energys ownership interest diluting
to 42.5 percent. The Subscription Agreement was completed in August 2011, and we recorded a loss
on disposition of $279 million before- and after-tax from the dilution. The book value of our
investment in APLNG was reduced by $795 million, and we reduced the currency translation adjustment
associated with our investment by $516 million.
LUKOIL
We completed the disposition of our interest in LUKOIL during the first quarter of 2011, realizing
a before-tax gain of $360 million and cash proceeds of $1,243 million. The cost basis for shares
sold was average cost.
Loans and Long-Term Receivables
As part of our normal ongoing business operations and consistent with industry practice, we enter
into numerous agreements with other parties to pursue business opportunities. Included in such
activity are loans made to certain affiliated and non-affiliated companies. Significant loans to
affiliated companies at September 30, 2011, included the following:
|
|
|
$622 million in loan financing to Freeport LNG. |
|
|
|
$1,159 million in project financing to Qatar Liquefied Gas Company Limited (3) (QG3). |
The long-term portion of these loans is included in the Loans and advancesrelated parties line
on the consolidated balance sheet, while the short-term portion is in Accounts and notes
receivablerelated parties.
WRB Refining LP fully repaid its outstanding loans from us with payments of $150 million in the
third quarter of 2011 and $400 million in the second quarter of 2011.
Significant long-term receivables from, and loans to, non-affiliated companies at September 30,
2011, included $365 million related to seller financing of U.S. retail marketing assets. Long-term
receivables and the long-term portion of these loans are included in the Investments and long-term
receivables line item on the consolidated balance sheet, while the short-term portion related to
non-affiliate loans is in Accounts and notes receivable.
Other
We have investments remeasured at fair value on a recurring basis to support certain nonqualified
deferred compensation plans. The fair value of these assets at September 30, 2011, was $315
million, and at December 31, 2010, was $325 million. Substantially the entire value is categorized
in Level 1 of the fair value hierarchy. These investments are measured at fair value using a
market approach based on quotations from national securities exchanges.
Merey Sweeny, L.P. (MSLP) is a limited partnership that owns a delayed coker and related facilities
at the Sweeny Refinery. MSLP processes our long residue, which is produced from heavy sour crude
oil, for a processing fee. Fuel-grade petroleum coke is produced as a by-product and becomes the
property of MSLP. Prior to August 28, 2009, MSLP was owned 50/50 by us and Petróleos de Venezuela
S.A. (PDVSA). Under the agreements that govern the relationships between the partners, certain
defaults by PDVSA with respect to
5
supply of crude oil to the Sweeny Refinery gave us the right to acquire PDVSAs 50 percent
ownership interest in MSLP. On August 28, 2009, we exercised that right. PDVSA has initiated
arbitration in the International Chamber of Commerce challenging our actions, and the arbitration
process is underway. We continue to use the equity method of accounting for our investment in
MSLP.
Note 5Assets Held for Sale or Sold
On August 31, 2011, we sold our refinery in Wilhelmshaven, Germany, which had been operating as a
terminal since the fourth quarter of 2009. The refinery was included in our Refining and Marketing
segment and at the time of disposition had a net carrying value of $211 million, which
included $243 million of properties, plants and equipment. The $228 million before-tax loss on
this disposition was included in the Gain (loss) on dispositions line in the consolidated income
statement.
Note 6Properties, Plants and Equipment
Our investment in properties, plants and equipment (PP&E), with the associated accumulated
depreciation, depletion and amortization (Accum. DD&A), was:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
September 30, 2011 |
|
|
December 31, 2010 |
|
|
|
Gross |
|
|
Accum. |
|
|
Net |
|
|
Gross |
|
|
Accum. |
|
|
Net |
|
|
|
PP&E |
|
|
DD&A |
|
|
PP&E |
|
|
PP&E |
|
|
DD&A |
|
|
PP&E |
|
Exploration and
Production (E&P) |
|
$ |
122,378 |
|
|
|
54,763 |
|
|
|
67,615 |
|
|
|
116,805 |
|
|
|
50,501 |
|
|
|
66,304 |
|
Midstream |
|
|
133 |
|
|
|
84 |
|
|
|
49 |
|
|
|
128 |
|
|
|
80 |
|
|
|
48 |
|
Refining and Marketing (R&M) |
|
|
21,848 |
|
|
|
8,012 |
|
|
|
13,836 |
|
|
|
23,579 |
|
|
|
8,999 |
|
|
|
14,580 |
|
LUKOIL Investment |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Chemicals |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Emerging Businesses |
|
|
1,026 |
|
|
|
208 |
|
|
|
818 |
|
|
|
981 |
|
|
|
161 |
|
|
|
820 |
|
Corporate and Other |
|
|
1,750 |
|
|
|
978 |
|
|
|
772 |
|
|
|
1,732 |
|
|
|
930 |
|
|
|
802 |
|
|
|
|
$ |
147,135 |
|
|
|
64,045 |
|
|
|
83,090 |
|
|
|
143,225 |
|
|
|
60,671 |
|
|
|
82,554 |
|
|
Note 7Suspended Wells
The capitalized cost of suspended wells at September 30, 2011, was $1,044 million, an increase of
$31 million from $1,013 million at year-end 2010. For the category of exploratory well costs
capitalized for a period greater than one year as of December 31, 2010, no wells were charged to
dry hole expense during the first nine months of 2011.
6
Note 8Impairments
During the three- and nine-month periods of 2011 and 2010, we recognized the following before-tax
impairment charges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
September 30 |
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
E&P |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
- |
|
|
|
29 |
|
|
|
- |
|
|
|
29 |
|
International |
|
|
- |
|
|
|
4 |
|
|
|
- |
|
|
|
5 |
|
R&M |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
486 |
|
|
|
- |
|
|
|
487 |
|
|
|
17 |
|
International |
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
1,600 |
|
Emerging Businesses |
|
|
- |
|
|
|
26 |
|
|
|
- |
|
|
|
31 |
|
|
|
|
$ |
486 |
|
|
|
59 |
|
|
|
488 |
|
|
|
1,682 |
|
|
2011
The third quarter and nine-month periods of 2011 included the $484 million impairment of our
refinery and associated pipelines and terminals in Trainer, Pennsylvania. In September 2011, we
announced plans to seek a buyer for the refinery and have idled the facility. If
unable to sell the refinery, we expect to permanently close the plant by the end of the first
quarter of 2012.
2010
The nine-month period of 2010 included the $1,502 million impairment of our refinery in
Wilhelmshaven, Germany, due to canceled plans for a project to upgrade the refinery, and a $98
million property impairment in international R&M to write-off capitalized project costs, as a
result of our decision to end our participation in a new refinery project in Yanbu Industrial City,
Saudi Arabia.
Fair Value Remeasurements
There were no material fair value impairments as of September 30, 2011. The following table shows
the values of assets at December 31, 2010, by major category, measured at fair value on a
nonrecurring basis in periods subsequent to their initial recognition:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
|
|
|
Fair Value |
|
|
|
|
|
|
|
|
|
|
Measurements Using |
|
|
|
|
|
|
|
|
|
|
Level 1 |
|
|
Level 3 |
|
|
Before- |
|
|
|
Fair Value * |
|
|
Inputs |
|
|
Inputs |
|
|
Tax Loss |
December 31, 2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net properties, plants
and equipment (held for
use) |
|
$ |
307 |
|
|
|
- |
|
|
|
307 |
|
|
|
1,604* |
* |
Net properties, plants
and equipment (held for
sale) |
|
|
23 |
|
|
|
5 |
|
|
|
18 |
|
|
|
43 |
|
Equity method investments |
|
|
735 |
|
|
|
- |
|
|
|
735 |
|
|
|
645 |
|
|
*Represents the fair value at the time of the impairment. |
|
**Includes a $55 million leasehold impairment charged to exploration expenses. |
7
During 2010, net properties, plants and equipment held for use with a carrying amount of
$1,911 million were written down to a fair value of $307 million, resulting in a before-tax loss of
$1,604 million. The fair values were determined by the use of internal discounted cash flow models
using estimates of future production, prices, costs and a discount rate believed to be consistent
with those used by principal market participants and cash flow multiples for similar assets and
alternative use.
Also during 2010, net properties, plants and equipment held for sale with a carrying amount of $64
million were written down to their fair value of $23 million less cost to sell of $2 million for a
net $21 million, resulting in a before-tax loss of $43 million. The fair values were primarily
determined by binding negotiated selling prices with third parties, with some adjusted for the fair
value of certain liabilities retained.
In addition, an equity method investment associated with our E&P segment was determined to have a
fair value below carrying amount, and the impairment was considered to be other than temporary.
This investment with a book value of $1,380 million was written down to its fair value of $735
million, resulting in a charge of $645 million before-tax. The fair value was determined by the
application of an internal discounted cash flow model using estimates of future production, prices,
costs and a discount rate believed to be consistent with those used by principal market
participants; the analysis also considered market data for certain
undeveloped properties.
Note 9Debt
In August 2011, we increased our total revolving credit facilities from $7.85 billion to $8.0
billion. We replaced our $7.35 billion revolving credit facility with a $7.5 billion facility
expiring in August 2016. The terms of the new revolving credit facility are similar to the terms
of the replaced facility. We also have a $500 million facility expiring in July 2012.
We have two commercial paper programs supported by the $8.0 billion revolving credit facilities:
the ConocoPhillips $6.35 billion program, primarily a funding source for short-term working capital
needs, and the ConocoPhillips Qatar Funding Ltd. $1.5 billion program, which is used to fund
commitments relating to the QG3 Project. Commercial paper maturities are generally limited to 90
days.
At both September 30, 2011, and December 31, 2010, we had no direct outstanding borrowings under
our revolving credit facilities, but $40 million in letters of credit had been issued. In
addition, under the two commercial paper programs, there was $1,127 million of commercial paper
outstanding at September 30, 2011, compared with $1,182 million at December 31, 2010. Since we had
$1,127 million of commercial paper outstanding and had issued $40 million of letters of credit, we
had access to $6.8 billion in borrowing capacity under our revolving credit facilities at September
30, 2011.
During the first nine months of 2011, $328 million of our 9.375% Notes were repaid at their
maturity.
At September 30, 2011, we classified $1,060 million of short-term debt as long-term debt, based on
our ability and intent to refinance the obligation on a long-term basis under our revolving credit
facilities.
Note 10Joint Venture Acquisition Obligation
We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in
2007, to FCCL Partnership. Quarterly principal and interest payments of $237 million began in the
second quarter of 2007 and will continue until the balance is paid. Of the principal obligation
amount, $723 million was short-term and was included in the Accounts payablerelated parties
line on our September 30, 2011, consolidated balance sheet. The principal portion of these
payments, which totaled $518 million in the first nine months of 2011, is included in the Other
line in the financing activities section of our consolidated statement of cash flows. Interest
accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of
8
the quarterly interest payment is reflected as a capital contribution and is included in the
Capital expenditures and investments line on our consolidated statement of cash flows.
Note 11Noncontrolling Interests
Activity for the equity attributable to noncontrolling interests for the first nine months of 2011
and 2010 was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
2011 |
|
|
2010 |
|
|
|
Common |
|
|
Non- |
|
|
|
|
|
|
Common |
|
|
Non- |
|
|
|
|
|
|
Stockholders |
|
|
Controlling |
|
|
Total |
|
|
Stockholders |
|
|
Controlling |
|
|
Total |
|
|
|
Equity |
|
|
Interests |
|
|
Equity |
|
|
Equity |
|
|
Interests |
|
|
Equity |
|
Balance at January 1
|
|
$ |
68,562 |
|
|
|
547 |
|
|
|
69,109 |
|
|
|
62,023 |
|
|
|
590 |
|
|
|
62,613 |
|
Net income
|
|
|
9,046 |
|
|
|
46 |
|
|
|
9,092 |
|
|
|
9,317 |
|
|
|
47 |
|
|
|
9,364 |
|
Dividends
|
|
|
(2,761 |
) |
|
|
- |
|
|
|
(2,761 |
) |
|
|
(2,376 |
) |
|
|
- |
|
|
|
(2,376 |
) |
Repurchase of
company common
stock
|
|
|
(7,984 |
) |
|
|
- |
|
|
|
(7,984 |
) |
|
|
(1,258 |
) |
|
|
- |
|
|
|
(1,258 |
) |
Distributions to
noncontrolling
interests
|
|
|
- |
|
|
|
(70 |
) |
|
|
(70 |
) |
|
|
- |
|
|
|
(80 |
) |
|
|
(80 |
) |
Other changes, net*
|
|
|
(1,057 |
) |
|
|
(3 |
) |
|
|
(1,060 |
) |
|
|
1,655 |
|
|
|
(1 |
) |
|
|
1,654 |
|
|
Balance at
September 30
|
|
$ |
65,806 |
|
|
|
520 |
|
|
|
66,326 |
|
|
|
69,361 |
|
|
|
556 |
|
|
|
69,917 |
|
|
*Includes components of other comprehensive income, which are disclosed separately in Note 15Comprehensive Income. |
Note 12Guarantees
At September 30, 2011, we were liable for certain contingent obligations under various contractual
arrangements, as described below. We recognize a liability, at inception, for the fair value of our
obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of
the liability is noted below, we have not recognized a liability either because the guarantees were
issued prior to December 31, 2002, or because the fair value of the obligation is immaterial. In
addition, unless otherwise stated, we are not currently performing with any significance under the
guarantee and expect future performance to be either immaterial or have only a remote chance of
occurrence.
Construction Completion Guarantees
In December 2005, we issued a construction completion guarantee for 30 percent of the $4.0 billion
in loan facilities of QG3, which were used to finance the construction of an LNG train in Qatar.
Of the $4.0 billion in loan facilities, we committed to provide $1.2 billion. The maximum
potential amount of future payments to third-party lenders under the guarantee is estimated to be
$850 million, which could become payable if the full debt financing is utilized and completion of
the QG3 Project is not achieved. The project financing will be nonrecourse to ConocoPhillips upon
certified completion. Completion assessment is ongoing with certification expected later in 2011.
At September 30, 2011, the carrying value of the guarantee to third-party lenders was $11 million.
Guarantees of Joint Venture Debt
At September 30, 2011, we had guarantees outstanding for our portion of certain joint venture debt
obligations, which have terms of up to 14 years. The maximum potential amount of future payments
under the guarantees is approximately $70 million. Payment would be required if a joint venture
defaults on its debt obligations.
9
Other Guarantees
|
|
|
In conjunction with our purchase of an ownership interest in APLNG from Origin Energy in
2008, we agreed to participate, if and when requested, in any parent company guarantees that
were outstanding at that time. These parent company guarantees cover the obligation of APLNG
to deliver natural gas under several sales agreements with remaining terms of 6 to 20 years.
Our maximum potential amount of future payments, or cost of volume delivery, under these
guarantees is estimated to be $1,282 million ($2,824 million in the event of
intentional or reckless breach) at September 2011 exchange rates based on our 42.5 percent
share of the remaining contracted volumes, which could become payable if APLNG fails to meet
its obligations under these agreements and the obligations cannot otherwise be mitigated.
Future payments are considered unlikely, as the payments, or cost of volume delivery, would
only be triggered if APLNG does not have enough natural gas to meet these sales commitments
and if the co-venturers do not make necessary equity contributions into APLNG. Additionally,
we have guaranteed the performance of APLNG with regard to certain contracts executed in
connection with APLNGs issuance of the Train 1 Notice to Proceed. One guarantee is for the
life of the venture, and the others extend for a maximum of five years. Our maximum
potential amount of future payments related to these guarantees is estimated to be $177
million at September 30, 2011. |
|
|
|
|
We have other guarantees with maximum future potential payment amounts totaling $450
million, which consist primarily of guarantees to fund the short-term cash liquidity deficits
of certain joint ventures, guarantees of minimum charter revenue for two LNG vessels, one
small construction completion guarantee, guarantees of the lease payment obligations of a
joint venture, guarantees of the residual value of leased corporate aircraft, and guarantees
of the performance of a business partner or some of its customers. These guarantees
generally extend up to 13 years or life of the venture. |
Indemnifications
Over the years, we have entered into various agreements to sell ownership interests in certain
corporations, joint ventures and assets that gave rise to qualifying indemnifications. Agreements
associated with these sales include indemnifications for taxes, environmental liabilities, permits
and licenses, employee claims, real estate indemnity against tenant defaults, and litigation. The
terms of these indemnifications vary greatly. The majority of these indemnifications are related
to environmental issues, the term is generally indefinite and the maximum amount of future payments
is generally unlimited. The carrying amount recorded for these indemnifications at September 30,
2011, was $399 million. We amortize the indemnification liability over the relevant time period,
if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases
where the indemnification term is indefinite, we will reverse the liability when we have
information the liability is essentially relieved or amortize the liability over an appropriate
time period as the fair value of our indemnification exposure declines. Although it is reasonably
possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it
is not possible to make a reasonable estimate of the maximum potential amount of future payments.
Included in the recorded carrying amount were $231 million of environmental accruals for known
contamination that are included in asset retirement obligations and accrued environmental costs at
September 30, 2011. For additional information about environmental liabilities, see Note
13Contingencies and Commitments.
Note 13Contingencies and Commitments
A number of lawsuits involving a variety of claims have been made against ConocoPhillips that arise
in the ordinary course of business. We also may be required to remove or mitigate the effects on
the environment of the placement, storage, disposal or release of certain chemical, mineral and
petroleum substances at various active and inactive sites. We regularly assess the need for
accounting recognition or disclosure of these contingencies. In the case of all known
contingencies (other than those related to income taxes), we accrue a liability when the loss is
probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated
and no amount within the range is a better estimate than any other amount, then the minimum of the
range is accrued. We do not reduce these liabilities for potential insurance or third-party
10
recoveries. If applicable, we accrue receivables for probable insurance or other third-party
recoveries. In the case of income tax-related contingencies, we use a cumulative
probability-weighted loss accrual in cases where sustaining a tax position is less than certain.
Based on currently available information, we believe it is remote that future costs related to
known contingent liability exposures will exceed current accruals by an amount that would have a
material adverse impact on our consolidated financial statements. As we learn new facts concerning
contingencies, we reassess our position both with respect to accrued liabilities and other
potential exposures. Estimates particularly sensitive to future changes include contingent
liabilities recorded for environmental remediation, tax and legal matters. Estimated future
environmental remediation costs are subject to change due to such factors as the uncertain
magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be
required, and the determination of our liability in proportion to that of other responsible
parties. Estimated future costs related to tax and legal matters are subject to change as events
evolve and as additional information becomes available during the administrative and litigation
processes.
Environmental
We are subject to international, federal, state and local environmental laws and regulations. When
we prepare our consolidated financial statements, we record accruals for environmental liabilities
based on managements best estimates, using all information that is available at the time. We
measure estimates and base liabilities on currently available facts, existing technology, and
presently enacted laws and regulations, taking into account stakeholder and business
considerations. When measuring environmental liabilities, we also consider our prior experience in
remediation of contaminated sites, other companies cleanup experience, and data released by the
U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims
in our determination of environmental liabilities, and we accrue them in the period they are both
probable and reasonably estimable.
Although liability of those potentially responsible for environmental remediation costs is
generally joint and several for federal sites and frequently so for state sites, we are usually
only one of many companies cited at a particular site. Due to the joint and several liabilities,
we could be responsible for all cleanup costs related to any site at which we have been designated
as a potentially responsible party. We have been successful to date in sharing cleanup costs with
other financially sound companies. Many of the sites at which we are potentially responsible are
still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup,
those potentially responsible normally assess the site conditions, apportion responsibility and
determine the appropriate remediation. In some instances, we may have no liability or may attain a
settlement of liability. Where it appears that other potentially responsible parties may be
financially unable to bear their proportional share, we consider this inability in estimating our
potential liability, and we adjust our accruals accordingly. As a result of various acquisitions
in the past, we assumed certain environmental obligations. Some of these environmental obligations
are mitigated by indemnifications made by others for our benefit, and some of the indemnifications
are subject to dollar limits and time limits.
We are currently participating in environmental assessments and cleanups at numerous federal
Superfund and comparable state sites. After an assessment of environmental exposures for cleanup
and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase
business combination, which we record on a discounted basis) for planned investigation and
remediation activities for sites where it is probable future costs will be incurred and these costs
can be reasonably estimated. At September 30, 2011, our balance sheet included a total
environmental accrual of $926 million, compared with $994 million at December 31, 2010. We expect
to incur a substantial amount of these expenditures within the next 30 years. We have not reduced
these accruals for possible insurance recoveries. In the future, we may be involved in additional
environmental assessments, cleanups and proceedings.
Legal Proceedings
Our legal organization applies its knowledge, experience and professional judgment to the specific
characteristics of our cases, employing a litigation management process to manage and monitor the
legal proceedings against us. Our process facilitates the early evaluation and quantification of
potential exposures in individual cases. This process also enables us to track those cases that
have been scheduled for trial and/or
11
mediation. Based on professional judgment and experience in using these litigation management
tools and available information about current developments in all our cases, our legal organization
regularly assesses the adequacy of current accruals and determines if adjustment of existing
accruals, or establishment of new accruals, is required.
Other Contingencies
We have contingent liabilities resulting from throughput agreements with pipeline and processing
companies not associated with financing arrangements. Under these agreements, we may be required
to provide any such company with additional funds through advances and penalties for fees related
to throughput capacity not utilized. In addition, at September 30, 2011, we had performance
obligations secured by letters of credit of $1,962 million (of which $40 million was issued under
the provisions of our revolving credit facility, and the remainder was issued as direct bank
letters of credit) related to various purchase commitments for materials, supplies, services and
items of permanent investment incident to the ordinary conduct of business.
In 2007, we announced we had been unable to reach agreement with respect to our migration to an
empresa mixta structure mandated by the Venezuelan governments Nationalization Decree. As a
result, Venezuelas national oil company, PDVSA, or its affiliates directly assumed control over
ConocoPhillips interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro
development project. In response to this expropriation, we filed a request for international
arbitration on November 2, 2007, with the World Banks International Centre for Settlement of
Investment Disputes (ICSID). An arbitration hearing was held before an ICSID tribunal during the
summer of 2010, and we are currently awaiting an interim decision on key legal and factual issues.
In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated
arbitration before ICSID against The Republic of Ecuador, as a result of the newly enacted Windfall
Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite
a restraining order issued by ICSID, Ecuador confiscated the crude oil production of Burlington and
its co-venturer and sold the illegally seized crude oil. In 2009, Ecuador took over operations in
Blocks 7 and 21, fully expropriating our assets. In June 2010, the ICSID tribunal concluded it has
jurisdiction to hear the expropriation claim. An arbitration hearing on case merits occurred in
March 2011. On September 30, 2011, Ecuador filed a supplemental counterclaim asserting
environmental damages, which we believe will not be material. The arbitration process is ongoing.
12
Note 14Financial Instruments and Derivative Contracts
Financial Instruments
We invest excess cash in financial instruments with maturities based on our cash forecasts for the
various currency pools we manage. The maturities of these investments may from time to time extend
beyond 90 days. The types of financial instruments in which we currently invest include:
|
|
|
Time Deposits: Interest bearing deposits placed with approved financial institutions. |
|
|
|
Commercial Paper: Unsecured promissory notes issued by a corporation, commercial bank, or
government agency purchased at a discount, maturing at par. |
|
|
|
Government or government agency obligations: Negotiable debt obligations issued by a
government or government agency. |
These financial instruments appear in the Cash and cash equivalents line of our consolidated
balance sheet if the maturities at the time we made the investments were 90 days or less;
otherwise, these held-to-maturity investments are included in the Short-term investments line.
We held the following financial instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Carrying Amount |
|
|
|
Cash and Cash Equivalents |
|
|
Short-Term Investments* |
|
|
|
September 30 |
|
|
December 31 |
|
|
September 30 |
|
|
December 31 |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Cash |
|
$ |
902 |
|
|
|
1,284 |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Time Deposits |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining maturities from 1 to 90 days |
|
|
1,988 |
|
|
|
6,154 |
|
|
|
696 |
|
|
|
302 |
|
Remaining maturities from 91 to 180
days |
|
|
- |
|
|
|
- |
|
|
|
451 |
|
|
|
69 |
|
Commercial Paper |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining maturities from 1 to 90 days |
|
|
516 |
|
|
|
1,566 |
|
|
|
828 |
|
|
|
525 |
|
Remaining maturities from 91 to 182
days |
|
|
- |
|
|
|
- |
|
|
|
614 |
|
|
|
- |
|
Government Obligations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining maturities from 1 to 90 days |
|
|
31 |
|
|
|
450 |
|
|
|
- |
|
|
|
77 |
|
Remaining maturities from 91 to 180
days |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
$ |
3,437 |
|
|
|
9,454 |
|
|
|
2,589 |
|
|
|
973 |
|
|
*Carrying value approximates fair value. |
Derivative Instruments
We use financial and commodity-based derivative contracts to manage exposures to fluctuations in
foreign currency exchange rates, commodity prices, and interest rates, or to capture market
opportunities. Since we are not currently using cash flow hedge accounting, all gains and losses,
realized or unrealized, from derivative contracts have been recognized in the consolidated income
statement. Gains and losses from derivative contracts held for trading not directly related to our
physical business, whether realized or unrealized, have been reported net in the Other income (loss) line of our consolidated income statement.
Purchase and sales contracts with fixed minimum notional volumes for commodities that are readily
convertible to cash (e.g., crude oil, natural gas and gasoline) are recorded on the balance sheet
as derivatives unless the contracts are eligible for and we elect the normal purchases and normal
sales exception (i.e., contracts to purchase or sell quantities we expect to use or sell over a
reasonable period in the normal course of business). We record most of our contracts to buy or
sell natural gas and the majority of our contracts to sell power as derivatives, but we do apply
the normal purchases and normal sales exception to certain long-term contracts to sell our natural
gas production. We generally apply this normal purchases and normal sales exception to eligible
crude oil and refined product commodity purchase and sales contracts;
13
however, we may elect not to apply this exception (e.g., when another derivative instrument will be used to
mitigate the risk of the purchase or sales contract but hedge accounting will not be applied, in
which case both the purchase or sales contract and the derivative contract mitigating the resulting
risk will be recorded on the balance sheet at fair value).
We generally value our exchange-traded derivatives using closing prices provided by the exchange as
of the balance sheet date, and these are classified as Level 1 in the fair value hierarchy. Where
exchange-provided prices are adjusted, non-exchange quotes are used or when the instrument lacks
sufficient liquidity, we generally classify those exchange-cleared contracts as Level 2.
Over-the-counter (OTC) financial swaps and physical commodity forward purchase and sales contracts
are generally valued using quotations provided by brokers and price index developers, such as
Platts and Oil Price Information Service. These quotes are corroborated with market data and are
classified as Level 2. In certain less liquid markets or for longer-term contracts, forward prices
are not as readily available. In these circumstances, OTC swaps and physical commodity purchase
and sales contracts are valued using internally developed methodologies that consider historical
relationships among various commodities that result in managements best estimate of fair value.
These contracts are classified as Level 3. A contract that is initially classified as Level 3 due
to absence or insufficient corroboration of broker quotes over a material portion of the contract
will transfer to Level 2 when the portion of the trade having no quotes or insufficient
corroboration becomes an insignificant portion of the contract. A contract would also transfer to
Level 2 if we began using a corroborated broker quote that has become available. Conversely, if a
corroborated broker quote ceases to be available or used by us, the contract would transfer from
Level 2 to Level 3. There were no material transfers in or out of Level 1.
Financial OTC and physical commodity options are valued using industry-standard models that
consider various assumptions, including quoted forward prices for commodities, time value,
volatility factors, and contractual prices for the underlying instruments, as well as other
relevant economic measures. The degree to which these inputs are observable in the forward markets
determines whether the options are classified as Level 2 or 3.
We use a mid-market pricing convention (the mid-point between bid and ask prices). When
appropriate, valuations are adjusted to reflect credit considerations, generally based on available
market evidence.
The fair value hierarchy for our derivative assets and liabilities accounted for at fair value on a
recurring basis was:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
September 30, 2011 |
|
|
December 31, 2010 |
|
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total |
|
|
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives* |
|
$ |
3,851 |
|
|
|
1,895 |
|
|
|
68 |
|
|
|
5,814 |
|
|
|
1,456 |
|
|
|
1,744 |
|
|
|
63 |
|
|
|
3,263 |
|
Interest rate derivatives |
|
|
- |
|
|
|
31 |
|
|
|
- |
|
|
|
31 |
|
|
|
- |
|
|
|
20 |
|
|
|
- |
|
|
|
20 |
|
Foreign currency
exchange derivatives |
|
|
- |
|
|
|
10 |
|
|
|
- |
|
|
|
10 |
|
|
|
- |
|
|
|
15 |
|
|
|
- |
|
|
|
15 |
|
|
Total assets |
|
|
3,851 |
|
|
|
1,936 |
|
|
|
68 |
|
|
|
5,855 |
|
|
|
1,456 |
|
|
|
1,779 |
|
|
|
63 |
|
|
|
3,298 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives* |
|
|
3,839 |
|
|
|
1,713 |
|
|
|
21 |
|
|
|
5,573 |
|
|
|
1,611 |
|
|
|
1,737 |
|
|
|
36 |
|
|
|
3,384 |
|
Foreign currency
exchange derivatives |
|
|
- |
|
|
|
18 |
|
|
|
- |
|
|
|
18 |
|
|
|
- |
|
|
|
9 |
|
|
|
- |
|
|
|
9 |
|
|
Total liabilities |
|
|
3,839 |
|
|
|
1,731 |
|
|
|
21 |
|
|
|
5,591 |
|
|
|
1,611 |
|
|
|
1,746 |
|
|
|
36 |
|
|
|
3,393 |
|
|
Net assets (liabilities) |
|
$ |
12 |
|
|
|
205 |
|
|
|
47 |
|
|
|
264 |
|
|
|
(155 |
) |
|
|
33 |
|
|
|
27 |
|
|
|
(95 |
) |
|
* 2010 has been reclassified to conform to current-year presentation. |
14
The derivative values above are based on analysis of each contract as the fundamental unit
of account; therefore, derivative assets and liabilities with the same counterparty are not
reflected net where the right of setoff exists. Gains or losses from contracts in one level may be
offset by gains or losses on contracts in another level or by changes in values of physical
contracts or positions that are not reflected in the table above.
As reflected in the table above, Level 3 activity was not material.
Commodity Derivative Contracts We operate in the worldwide crude oil, bitumen, refined product,
natural gas, LNG, natural gas liquids and electric power markets and are exposed to fluctuations in
the prices for these commodities. These fluctuations can affect our revenues, as well as the cost
of operating, investing and financing activities. Generally, our policy is to remain exposed to
the market prices of commodities; however, we use futures, forwards, swaps and options in various
markets to balance physical systems, meet customer needs, manage price exposures on specific
transactions, and do a limited, immaterial amount of trading not directly related to our physical
business. We also use the market knowledge gained from these activities to capture market
opportunities such as moving physical commodities to more profitable locations, storing commodities
to capture seasonal or time premiums, and blending commodities to capture quality upgrades.
Derivatives may be used to optimize these activities which may move our risk profile away from
market average prices.
The fair value of commodity derivative assets and liabilities and the line items where they appear
on our consolidated balance sheet were:
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
September 30 |
|
|
December 31 |
|
|
|
2011 |
|
|
2010 |
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
Prepaid expenses and other current assets |
|
$ |
5,595 |
|
|
|
3,073 |
|
Other assets |
|
|
300 |
|
|
|
211 |
|
Liabilities |
|
|
|
|
|
|
|
|
Other accruals |
|
|
5,387 |
|
|
|
3,212 |
|
Other liabilities and deferred credits |
|
|
267 |
|
|
|
193 |
|
|
Hedge accounting has not been used for any item in the table. The
amounts shown are presented gross (i.e., without netting assets and
liabilities with the same counterparty where the right of setoff exists). |
The gains (losses) from commodity derivatives incurred, and the line items where they appear
on our consolidated income statement were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
September 30 |
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
Sales and other operating revenues |
|
$ |
437 |
|
|
|
227 |
|
|
|
(276 |
) |
|
|
(430 |
) |
Other income |
|
|
1 |
|
|
|
3 |
|
|
|
(8 |
) |
|
|
(26 |
) |
Purchased crude oil, natural gas and products |
|
|
(46 |
) |
|
|
(270 |
) |
|
|
179 |
|
|
|
596 |
|
|
Hedge accounting has not been used for any item in the table. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes our material net exposures resulting from outstanding
commodity derivative contracts. These financial and physical derivative contracts are primarily
used to manage price exposures on our underlying operations. The underlying exposures may be from
non-derivative positions, such as inventory volumes or firm natural gas transport contracts.
Financial derivative contracts may also offset physical derivative contracts, such as forward sales
contracts.
15
|
|
|
|
|
|
|
|
|
|
|
Open Position |
|
|
|
Long/(Short) |
|
|
|
September 30 |
|
|
December 31 |
|
|
|
2011 |
|
|
2010 |
|
|
|
|
Commodity |
|
|
|
|
|
|
|
|
Crude oil, refined products and natural gas liquids (millions of barrels) |
|
|
(38 |
) |
|
|
(16 |
) |
Natural gas and power (billions of cubic feet equivalent) |
|
|
|
|
|
|
|
|
Fixed price |
|
|
(53 |
) |
|
|
(69 |
) |
Basis |
|
|
(75 |
) |
|
|
(43 |
) |
|
Interest Rate Derivative Contracts During the second quarter of 2010, we executed interest rate
swaps to synthetically convert $500 million of our 4.60% fixed-rate notes due in 2015 to a floating
rate based on the London Interbank Offered Rate (LIBOR). These swaps qualify for and are
designated as fair-value hedges using the short-cut method of hedge accounting. The short-cut
method permits the assumption that changes in the value of the derivative perfectly offset changes
in the value of the debt; therefore, no gain or loss has been recognized due to hedge
ineffectiveness.
The adjustments to the fair values of the interest rate swaps and hedged debt have not been
material.
Foreign Currency Exchange Derivatives We have foreign currency exchange rate risk resulting from
international operations. We do not comprehensively hedge the exposure to movements in currency
exchange rates, although we may choose to selectively hedge certain foreign currency exchange rate
exposures, such as firm commitments for capital projects or local currency tax payments, dividends,
and cash returns from net investments in foreign affiliates to be remitted within the coming year.
The fair value of foreign currency exchange derivative assets and liabilities, and the line items
where they appear on our consolidated balance sheet were:
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
September 30 |
|
|
December 31 |
|
|
|
2011 |
|
|
2010 |
|
|
|
|
Assets |
|
|
|
|
|
|
|
|
Prepaid expenses and other current assets
|
|
$ |
8 |
|
|
|
14 |
|
Other assets
|
|
|
2 |
|
|
|
1 |
|
Liabilities |
|
|
|
|
|
|
|
|
Other accruals
|
|
|
18 |
|
|
|
7 |
|
Other liabilities and deferred credits
|
|
|
- |
|
|
|
2 |
|
|
Hedge accounting has not been used for any item in the table. The amounts shown are presented gross. |
Gains and losses from foreign currency exchange derivatives, and the line item where they
appear on our consolidated income statement were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
September 30 |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Foreign exchange transaction (gains) losses
|
|
$ |
3 |
|
|
|
18 |
|
|
|
(3 |
) |
|
|
121 |
|
|
Hedge accounting has not been used for any item in the table. |
16
We had the following net notional position of outstanding foreign exchange derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In Millions |
|
|
|
Notional Currency* |
|
|
|
|
|
|
|
September 30 |
|
|
December 31 |
|
|
|
|
|
|
|
2011 |
|
|
2010 |
|
|
|
|
Foreign Exchange Derivatives |
|
|
|
|
|
|
|
|
|
|
|
|
Sell U.S. dollar, buy other currencies** |
|
USD |
|
|
1,565 |
|
|
|
569 |
|
Sell euro, buy British pound |
|
EUR |
|
|
176 |
|
|
|
253 |
|
|
*Denominated in U.S. dollars (USD) and euros (EUR). |
|
|
|
**Primarily euro, Canadian dollar, Norwegian krone and British pound. |
|
|
Credit Risk
Financial instruments potentially exposed to concentrations of credit risk consist primarily of
cash equivalents, OTC derivative contracts and trade receivables. Our cash equivalents and
short-term investments are placed in high-quality commercial paper, money market funds, government
debt securities and time deposits with major international banks and financial institutions.
The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the
counterparty to the transaction. Individual counterparty exposure is managed within predetermined
credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk
of significant nonperformance. We also use futures, swaps and option contracts that have a
negligible credit risk because these trades are cleared with an exchange clearinghouse and subject
to mandatory margin requirements until settled.
Our trade receivables result primarily from our petroleum operations and reflect a broad national
and international customer base, which limits our exposure to concentrations of credit risk. The
majority of these receivables have payment terms of 30 days or less, and we continually monitor
this exposure and the creditworthiness of the counterparties. We do not generally require
collateral to limit the exposure to loss; however, we will sometimes use letters of credit,
prepayments, and master netting arrangements to mitigate credit risk with counterparties that both
buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be
offset against amounts due us.
Certain of our derivative instruments contain provisions that require us to post collateral if the
derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and
other contracts with variable threshold amounts that are contingent on our credit rating. The
variable threshold amounts typically decline for lower credit ratings, while both the variable and
fixed threshold amounts typically revert to zero if we fall below investment grade. Cash is the
primary collateral in all contracts; however, many also permit us to post letters of credit as
collateral.
The aggregate fair value of all derivative instruments with such credit-risk-related contingent
features that were in a liability position on September 30, 2011, and December 31, 2010, was $139
million and $225 million, respectively, for which no collateral was posted. If our credit rating
were lowered one level from its A rating (per Standard and Poors) on September 30, 2011, we
would be required to post no additional collateral to our counterparties. If we were downgraded
below investment grade, we would be required to post $139 million of additional collateral, either
with cash or letters of credit.
Fair Values of Financial Instruments
We used the following methods and assumptions to estimate the fair value of financial instruments:
|
|
|
Cash, cash equivalents and short-term investments: The carrying amount reported on the
balance sheet approximates fair value. |
|
|
|
Accounts and notes receivable: The carrying amount reported on the balance sheet
approximates fair value. |
17
|
|
|
Investment in LUKOIL shares: We completed the disposition of our interest in LUKOIL
during the first quarter of 2011. At December 31, 2010, our investment in LUKOIL was
carried at fair value of $1,083 million, reflecting a closing price of LUKOIL American
Depositary Receipts (ADRs) on the London Stock Exchange of $56.50 per share. |
|
|
|
Debt: The carrying amount of our floating-rate debt approximates fair value. The fair
value of the fixed-rate debt is estimated based on quoted market prices. |
|
|
|
Fixed-rate 5.3 percent joint venture acquisition obligation: Fair value is estimated
based on the net present value of the future cash flows, discounted at September 30, 2011,
and December 31, 2010, using effective yield rates of 1.25 percent and 1.87 percent,
respectively, based on yields of U.S. Treasury securities of similar average duration adjusted for our average credit risk spread
and the amortizing nature of the obligation principal. See Note 10Joint Venture
Acquisition Obligation, for additional information. |
|
|
|
Commodity swaps: Fair value is estimated based on forward market prices and approximates
the exit price at period end. When forward market prices are not available, fair value is
estimated using the forward prices of a similar commodity with adjustments for differences
in quality or location. |
|
|
|
Futures: Fair values are based on quoted market prices obtained from the New York
Mercantile Exchange, the Intercontinental Exchange (ICE) Futures, or other traded
exchanges. |
|
|
|
Interest rate swap contracts: Fair value is estimated based on a pricing model and
market observable interest rate swap curves obtained from a third-party market data
provider. |
|
|
|
Forward-exchange contracts: Fair values are estimated by comparing the contract rate to
the forward rates in effect at the end of the respective reporting periods, and approximate
the exit prices at those dates. |
Our commodity derivative and financial instruments were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Carrying Amount |
|
|
Fair Value |
|
|
|
September 30 |
|
|
December 31 |
|
|
September 30 |
|
|
December 31 |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Financial assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency exchange derivatives |
|
$ |
10 |
|
|
|
15 |
|
|
|
10 |
|
|
|
15 |
|
Interest rate derivatives |
|
|
31 |
|
|
|
20 |
|
|
|
31 |
|
|
|
20 |
|
Commodity derivatives |
|
|
762 |
|
|
|
624 |
|
|
|
762 |
|
|
|
624 |
|
Investment in LUKOIL |
|
|
- |
|
|
|
1,083 |
|
|
|
- |
|
|
|
1,083 |
|
Financial liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt, excluding capital leases |
|
|
23,118 |
|
|
|
23,553 |
|
|
|
27,074 |
|
|
|
26,144 |
|
Joint venture acquisition obligation |
|
|
4,492 |
|
|
|
5,009 |
|
|
|
5,041 |
|
|
|
5,600 |
|
Foreign currency exchange derivatives |
|
|
18 |
|
|
|
9 |
|
|
|
18 |
|
|
|
9 |
|
Commodity derivatives |
|
|
426 |
|
|
|
426 |
|
|
|
426 |
|
|
|
426 |
|
|
The amounts shown for derivatives in the preceding table are presented net (i.e., assets and
liabilities with the same counterparty are netted where the right of setoff exists). In addition,
the September 30, 2011, commodity derivative assets and liabilities appear net of $53 million of
obligations to return cash collateral and $148 million of rights to reclaim cash collateral,
respectively. The December 31, 2010, commodity derivative assets and liabilities appear net of $5
million of obligations to return cash collateral and $324 million of rights to reclaim cash
collateral, respectively. No collateral was deposited or held for the foreign currency derivatives
or interest rate derivatives.
18
Note 15Comprehensive Income (Loss)
ConocoPhillips comprehensive income (loss) was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
September 30 |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Net income |
|
$ |
2,631 |
|
|
|
3,069 |
|
|
|
9,092 |
|
|
|
9,364 |
|
After-tax changes in: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined benefit plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net prior service cost |
|
|
1 |
|
|
|
2 |
|
|
|
2 |
|
|
|
6 |
|
Net actuarial gain |
|
|
44 |
|
|
|
33 |
|
|
|
111 |
|
|
|
103 |
|
Nonsponsored plans |
|
|
3 |
|
|
|
14 |
|
|
|
10 |
|
|
|
35 |
|
|
Net defined benefit plans |
|
|
48 |
|
|
|
49 |
|
|
|
123 |
|
|
|
144 |
|
|
Unrealized gain on securities |
|
|
- |
|
|
|
423 |
|
|
|
- |
|
|
|
423 |
|
Less:
reclassification adjustment for gain on securities recognized in net
income |
|
|
- |
|
|
|
- |
|
|
|
(158 |
) |
|
|
- |
|
|
Net unrealized gain on securities |
|
|
- |
|
|
|
423 |
|
|
|
(158 |
) |
|
|
423 |
|
|
Foreign currency translation adjustments |
|
|
(2,454 |
) |
|
|
2,052 |
|
|
|
(1,020 |
) |
|
|
774 |
|
Less: reclassification adjustment for gains included in net
income |
|
|
(516 |
) |
|
|
- |
|
|
|
(516 |
) |
|
|
- |
|
|
Net foreign currency translation adjustments |
|
|
(2,970 |
) |
|
|
2,052 |
|
|
|
(1,536 |
) |
|
|
774 |
|
Hedging activities |
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
(1 |
) |
|
Comprehensive income (loss) |
|
|
(291 |
) |
|
|
5,593 |
|
|
|
7,522 |
|
|
|
10,704 |
|
Less: comprehensive income attributable to noncontrolling interests |
|
|
(15 |
) |
|
|
(14 |
) |
|
|
(46 |
) |
|
|
(47 |
) |
|
Comprehensive income (loss) attributable to ConocoPhillips |
|
$ |
(306 |
) |
|
|
5,579 |
|
|
|
7,476 |
|
|
|
10,657 |
|
|
Accumulated other comprehensive income in the equity section of the balance sheet included:
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
September 30 |
|
|
December 31 |
|
|
|
2011 |
|
|
2010 |
|
|
Defined benefit plans liability adjustments |
|
$ |
(1,235 |
) |
|
|
(1,358 |
) |
Net unrealized gain on securities |
|
|
- |
|
|
|
158 |
|
Foreign currency translation adjustments |
|
|
4,444 |
|
|
|
5,980 |
|
Deferred net hedging loss |
|
|
(6 |
) |
|
|
(7 |
) |
|
Accumulated other comprehensive income |
|
$ |
3,203 |
|
|
|
4,773 |
|
|
There were no items within accumulated other comprehensive income related to noncontrolling
interests.
19
Note 16Cash Flow Information
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
|
2011 |
|
|
2010 |
|
Cash Payments |
|
|
|
|
|
|
|
|
Interest |
|
$ |
748 |
|
|
|
996 |
|
Income taxes |
|
|
7,703 |
|
|
|
6,022 |
|
|
|
Net Purchases of Short-Term Investments |
|
|
|
|
|
|
|
|
Short-term investments purchased |
|
$ |
(6,642 |
) |
|
|
- |
|
Short-term investments sold |
|
|
5,019 |
|
|
|
- |
|
|
|
|
$ |
(1,623 |
) |
|
|
- |
|
|
Note 17Employee Benefit Plans
Pension and Postretirement Plans
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
|
|
Pension Benefits |
|
|
Other Benefits |
|
Components of Net Periodic Benefit Cost |
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
U.S. |
|
|
Intl. |
|
|
U.S. |
|
|
Intl. |
|
|
|
|
|
|
|
|
|
Three Months Ended September 30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
56 |
|
|
|
25 |
|
|
|
58 |
|
|
|
22 |
|
|
|
3 |
|
|
|
3 |
|
Interest cost |
|
|
62 |
|
|
|
45 |
|
|
|
65 |
|
|
|
42 |
|
|
|
10 |
|
|
|
11 |
|
Expected return on plan assets |
|
|
(70 |
) |
|
|
(44 |
) |
|
|
(56 |
) |
|
|
(37 |
) |
|
|
- |
|
|
|
- |
|
Amortization of prior service cost |
|
|
2 |
|
|
|
- |
|
|
|
2 |
|
|
|
- |
|
|
|
(1 |
) |
|
|
- |
|
Recognized net actuarial (gain) loss |
|
|
42 |
|
|
|
11 |
|
|
|
42 |
|
|
|
14 |
|
|
|
(1 |
) |
|
|
(1 |
) |
|
Net periodic benefit costs |
|
$ |
92 |
|
|
|
37 |
|
|
|
111 |
|
|
|
41 |
|
|
|
11 |
|
|
|
13 |
|
|
|
Nine Months Ended September 30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
169 |
|
|
|
74 |
|
|
|
172 |
|
|
|
67 |
|
|
|
8 |
|
|
|
8 |
|
Interest cost |
|
|
185 |
|
|
|
133 |
|
|
|
195 |
|
|
|
126 |
|
|
|
31 |
|
|
|
34 |
|
Expected return on plan assets |
|
|
(210 |
) |
|
|
(131 |
) |
|
|
(168 |
) |
|
|
(110 |
) |
|
|
- |
|
|
|
- |
|
Amortization of prior service cost |
|
|
7 |
|
|
|
- |
|
|
|
7 |
|
|
|
- |
|
|
|
(5 |
) |
|
|
2 |
|
Recognized net actuarial (gain) loss |
|
|
124 |
|
|
|
34 |
|
|
|
125 |
|
|
|
41 |
|
|
|
(4 |
) |
|
|
(5 |
) |
|
Net periodic benefit costs |
|
$ |
275 |
|
|
|
110 |
|
|
|
331 |
|
|
|
124 |
|
|
|
30 |
|
|
|
39 |
|
|
In the third quarter of 2011, we recognized pension settlement losses of $19 million. None were
recognized in the nine-month period of 2010. During the first nine months of 2011, we contributed
$642 million to our domestic benefit plans and $177 million to our international benefit plans.
Compensation and Benefits Trust
In August 2011, all of the approximately 36 million shares of company common stock held by the
Compensation and Benefits Trust (CBT) were transferred to ConocoPhillips, and those shares are now
held as non-voting treasury stock. Because the CBT is consolidated by us, the transfer of its
shares from Grantor trusts to Treasury stock in the equity section of our balance sheet was
recorded at the shares historical carrying value of approximately $610 million. This transfer did
not affect total equity, shares outstanding, or earnings per share. The CBT no longer holds any
assets.
20
Note 18Related Party Transactions
Significant transactions with related parties were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
September 30 |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Operating revenues and other income (a) |
|
$ |
1,976 |
|
|
|
2,556 |
|
|
|
6,147 |
|
|
|
6,540 |
|
Purchases (b) |
|
|
5,328 |
|
|
|
3,897 |
|
|
|
15,309 |
|
|
|
11,245 |
|
Operating expenses and selling,
general and administrative expenses
(c) |
|
|
94 |
|
|
|
88 |
|
|
|
308 |
|
|
|
253 |
|
Net interest expense (d) |
|
|
18 |
|
|
|
16 |
|
|
|
55 |
|
|
|
53 |
|
|
|
|
|
(a) |
|
We sold natural gas to DCP Midstream, LLC and crude oil to the Malaysian Refining Company
Sdn. Bhd. (MRC), among others, for processing and marketing. Natural gas liquids, solvents
and petrochemical feedstocks were sold to Chevron Phillips Chemical Company LLC (CPChem), and
gas oil and hydrogen feedstocks were sold to Excel Paralubes. Both periods of 2010 included
sales of refined products to CFJ Properties and LUKOIL, which were no longer considered
related parties beginning in the third and fourth quarters of 2010, respectively, due to the
sales of our interests. Natural gas, crude oil, blendstock and other intermediate products
were sold to WRB Refining LP. In addition, we charged several of our affiliates, including
CPChem and MSLP, for the use of common facilities, such as steam generators, waste and water
treaters, and warehouse facilities. |
|
(b) |
|
We purchased refined products from WRB and MRC. We purchased natural gas and natural gas
liquids from DCP Midstream and CPChem for use in our refinery processes and other feedstocks
from various affiliates. Both periods of 2010 included purchases of crude oil from LUKOIL,
which was no longer considered a related party beginning in the fourth quarter of 2010. We
also paid fees to various pipeline equity companies for transporting finished refined products
and natural gas, as well as a price upgrade to MSLP for heavy crude processing. We purchased
base oils and fuel products from Excel Paralubes for use in our refinery and lubricants
businesses. |
|
(c) |
|
We paid processing fees to various affiliates. Additionally, we paid transportation fees to
pipeline equity companies. |
|
(d) |
|
We paid and/or received interest to/from various affiliates, including FCCL Partnership. See
Note 4Investments, Loans and Long-Term Receivables, for additional information on loans to
affiliated companies. |
21
Note 19Segment Disclosures and Related Information
We have organized our reporting structure based on the grouping of similar products and services,
resulting in six operating segments:
|
1) |
|
E&PThis segment primarily explores for, produces, transports and markets crude oil,
bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. |
|
2) |
|
MidstreamThis segment gathers, processes and markets natural gas produced by
ConocoPhillips and others, and fractionates and markets natural gas liquids, predominantly
in the United States and Trinidad. The Midstream segment primarily consists of our 50
percent equity investment in DCP Midstream. |
|
3) |
|
R&MThis segment purchases, refines, markets and transports crude oil and petroleum
products, mainly in the United States, Europe and Asia. |
|
4) |
|
LUKOIL InvestmentThis segment represents our past investment in the ordinary shares
of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia.
In the first quarter of 2011, we completed the divestiture of our entire interest in
LUKOIL. |
|
5) |
|
ChemicalsThis segment manufactures and markets petrochemicals and plastics on a
worldwide basis. The Chemicals segment consists of our 50 percent equity investment in
CPChem. |
|
6) |
|
Emerging BusinessesThis segment represents our investment in new technologies or
businesses outside our normal scope of operations. |
Corporate and Other includes general corporate overhead, most interest expense and various other
corporate activities. Corporate assets include all cash and cash equivalents and short-term
investments.
We evaluate performance and allocate resources based on net income attributable to ConocoPhillips.
Intersegment sales are at prices that approximate market.
22
Analysis of Results by Operating Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
September 30 |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Sales and Other Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
E&P |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
8,465 |
|
|
|
6,983 |
|
|
|
24,658 |
|
|
|
22,003 |
|
International |
|
|
7,907 |
|
|
|
7,416 |
|
|
|
24,462 |
|
|
|
20,842 |
|
Intersegment eliminationsU.S. |
|
|
(1,963 |
) |
|
|
(1,385 |
) |
|
|
(5,555 |
) |
|
|
(4,117 |
) |
Intersegment eliminationsinternational |
|
|
(2,046 |
) |
|
|
(2,007 |
) |
|
|
(6,049 |
) |
|
|
(5,896 |
) |
|
E&P |
|
|
12,363 |
|
|
|
11,007 |
|
|
|
37,516 |
|
|
|
32,832 |
|
|
Midstream |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales |
|
|
2,384 |
|
|
|
1,609 |
|
|
|
6,829 |
|
|
|
5,326 |
|
Intersegment eliminations |
|
|
(95 |
) |
|
|
(76 |
) |
|
|
(380 |
) |
|
|
(263 |
) |
|
Midstream |
|
|
2,289 |
|
|
|
1,533 |
|
|
|
6,449 |
|
|
|
5,063 |
|
|
R&M |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
32,210 |
|
|
|
23,168 |
|
|
|
96,982 |
|
|
|
69,397 |
|
International |
|
|
16,113 |
|
|
|
11,631 |
|
|
|
44,739 |
|
|
|
30,910 |
|
Intersegment eliminationsU.S. |
|
|
(213 |
) |
|
|
(175 |
) |
|
|
(772 |
) |
|
|
(563 |
) |
Intersegment eliminationsinternational |
|
|
(15 |
) |
|
|
(10 |
) |
|
|
(54 |
) |
|
|
(84 |
) |
|
R&M |
|
|
48,095 |
|
|
|
34,614 |
|
|
|
140,895 |
|
|
|
99,660 |
|
|
LUKOIL Investment |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Chemicals |
|
|
3 |
|
|
|
3 |
|
|
|
8 |
|
|
|
8 |
|
|
Emerging Businesses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales |
|
|
214 |
|
|
|
196 |
|
|
|
572 |
|
|
|
590 |
|
Intersegment eliminations |
|
|
(186 |
) |
|
|
(153 |
) |
|
|
(516 |
) |
|
|
(459 |
) |
|
Emerging Businesses |
|
|
28 |
|
|
|
43 |
|
|
|
56 |
|
|
|
131 |
|
|
Corporate and Other |
|
|
6 |
|
|
|
8 |
|
|
|
17 |
|
|
|
21 |
|
|
Consolidated sales and other operating revenues |
|
$ |
62,784 |
|
|
|
47,208 |
|
|
|
184,941 |
|
|
|
137,715 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to ConocoPhillips |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
E&P |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
816 |
|
|
|
563 |
|
|
|
2,496 |
|
|
|
1,856 |
|
International |
|
|
946 |
|
|
|
1,001 |
|
|
|
4,142 |
|
|
|
5,654 |
|
|
Total E&P |
|
|
1,762 |
|
|
|
1,564 |
|
|
|
6,638 |
|
|
|
7,510 |
|
|
Midstream |
|
|
137 |
|
|
|
77 |
|
|
|
340 |
|
|
|
215 |
|
|
R&M |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
789 |
|
|
|
199 |
|
|
|
1,883 |
|
|
|
993 |
|
International |
|
|
- |
|
|
|
69 |
|
|
|
154 |
|
|
|
(1,008 |
) |
|
Total R&M |
|
|
789 |
|
|
|
268 |
|
|
|
2,037 |
|
|
|
(15 |
) |
|
LUKOIL Investment |
|
|
- |
|
|
|
1,310 |
|
|
|
239 |
|
|
|
2,226 |
|
Chemicals |
|
|
197 |
|
|
|
132 |
|
|
|
589 |
|
|
|
380 |
|
Emerging Businesses |
|
|
(2 |
) |
|
|
(20 |
) |
|
|
(23 |
) |
|
|
(24 |
) |
Corporate and Other |
|
|
(267 |
) |
|
|
(276 |
) |
|
|
(774 |
) |
|
|
(975 |
) |
|
Consolidated net income attributable to ConocoPhillips |
|
$ |
2,616 |
|
|
|
3,055 |
|
|
|
9,046 |
|
|
|
9,317 |
|
|
23
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
September 30 |
|
|
December 31 |
|
|
|
2011 |
|
|
2010 |
|
Total Assets |
|
|
|
|
|
|
|
|
E&P |
|
|
|
|
|
|
|
|
United States |
|
$ |
36,378 |
|
|
|
35,607 |
|
International |
|
|
62,892 |
|
|
|
63,086 |
|
|
Total E&P |
|
|
99,270 |
|
|
|
98,693 |
|
|
Midstream |
|
|
2,467 |
|
|
|
2,506 |
|
|
R&M |
|
|
|
|
|
|
|
|
United States |
|
|
27,525 |
|
|
|
26,028 |
|
International |
|
|
9,897 |
|
|
|
8,463 |
|
Goodwill |
|
|
3,606 |
|
|
|
3,633 |
|
|
Total R&M |
|
|
41,028 |
|
|
|
38,124 |
|
|
LUKOIL Investment |
|
|
- |
|
|
|
1,129 |
|
Chemicals |
|
|
2,896 |
|
|
|
2,732 |
|
Emerging Businesses |
|
|
978 |
|
|
|
964 |
|
Corporate and Other |
|
|
8,050 |
|
|
|
12,166 |
|
|
Consolidated total assets |
|
$ |
154,689 |
|
|
|
156,314 |
|
|
Note 20Income Taxes
Our effective tax rate for the third quarter and first nine months of 2011 was 49 percent and 47
percent, respectively, compared with 42 percent and 39 percent for the same two periods of 2010.
The increase in the effective tax rate for the third quarter of 2011, versus the third quarter of
2010, was due primarily to the impact of asset dispositions in both years and the effect of the
2011 United Kingdom tax law change, offset in part by a higher
proportion of income in higher tax jurisdictions in 2010. The change
in the effective tax rate for the first nine months of
2011, compared with the same period of 2010, was due primarily to asset dispositions occurring in
2010 and the 2011 U.K. tax law change, offset in part by the 2010 impairment of our Wilhelmshaven
Refinery and a higher proportion of income in higher tax
jurisdictions in 2010. For periods in which
the effective tax rate was in excess of the domestic federal statutory rate of 35 percent, it was
primarily due to foreign taxes.
In the United Kingdom, legislation was enacted on July 19, 2011, which increases the supplementary
corporate tax rate applicable to U.K. upstream activity from 20 percent to 32 percent,
retroactively effective from March 24, 2011. This results in the overall U.K. upstream corporate
tax rate increasing from 50 percent to 62 percent. The enactment created additional
tax expense during the third quarter of 2011 of $234 million. This is comprised of $106 million
for the revaluation of the U.K. upstream deferred tax liability, in
addition to charges of $75
million to reflect the new rate from March 24, 2011, through
June 30, 2011, and $53 million to reflect the new rate from July
1, 2011, through September 30, 2011.
Note 21New Accounting Standards
In June 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update
(ASU) 2011-5, Comprehensive Income. This ASU amends FASB Accounting Standards Codification Topic
220, Comprehensive Income, and requires the presentation of comprehensive income, the components
of net income, and the components of other comprehensive income either in a single continuous
statement of comprehensive income or in two separate but consecutive statements. This ASU is
effective for fiscal years, and interim periods within those years, beginning after December 15,
2011, with early adoption permitted. We currently plan to use the two consecutive statement
approach upon adoption of this ASU.
24
In September 2011, the FASB issued ASU 2011-8, Intangibles Goodwill and Other. This ASU
provides for the option to first assess qualitative factors to determine whether it is more likely
than not that the fair value of a reporting unit is less than its carrying amount. If the
assessment of qualitative factors determines it is more likely than not the carrying value of a reporting unit is less than fair value, performing the
two-step goodwill impairment analysis would not be necessary. This ASU is effective for fiscal
years, and interim periods within those years, beginning after
December 15, 2011, with early adoption permitted. We are currently
evaluating the impact of this ASU.
Note
22Planned Separation of Downstream Businesses
On July 14, 2011, we announced approval by our Board of Directors to pursue the separation of our
refining, marketing and transportation business into a stand-alone, publicly traded corporation via
a tax-free distribution. We expect the new downstream company will also include most of our
Midstream segment, our Chemicals segment, as well as our power generation and certain technology
operations. The separation is subject to market conditions, customary regulatory approvals, the
receipt of an affirmative Internal Revenue Service private letter ruling, execution of separation
and intercompany agreements and final Board approval, and is expected to be completed in the second
quarter of 2012.
25
Supplementary InformationCondensed Consolidating Financial Information
We have various cross guarantees among ConocoPhillips, ConocoPhillips Company, ConocoPhillips
Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada
Funding Company II, with respect to publicly held debt securities. ConocoPhillips Company is
wholly owned by ConocoPhillips. ConocoPhillips Australia Funding Company, ConocoPhillips Canada
Funding Company I and ConocoPhillips Canada Funding Company II are indirect, wholly owned
subsidiaries of ConocoPhillips Company. ConocoPhillips and ConocoPhillips Company have fully and
unconditionally guaranteed the payment obligations of ConocoPhillips Australia Funding Company,
ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect
to their publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally
guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt
securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the
payment obligations of ConocoPhillips with respect to its publicly held debt securities. All
guarantees are joint and several. The following condensed consolidating financial information
presents the results of operations, financial position and cash flows for:
|
|
|
ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company,
ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II (in
each case, reflecting investments in subsidiaries utilizing the equity method of accounting). |
|
|
|
All other nonguarantor subsidiaries of ConocoPhillips. |
|
|
|
The consolidating adjustments necessary to present ConocoPhillips results on a
consolidated basis. |
This condensed consolidating financial information should be read in conjunction with the
accompanying consolidated financial statements and notes. Certain previously reported amounts
appearing on the 2010 income statement have been reclassified to conform to current-year
presentation.
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Three Months Ended September 30, 2011 |
|
|
|
|
|
|
|
|
|
|
|
ConocoPhillips |
|
|
ConocoPhillips |
|
|
ConocoPhillips |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australia |
|
|
Canada |
|
|
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ConocoPhillips |
|
|
Funding |
|
|
Funding |
|
|
Funding |
|
|
All Other |
|
|
Consolidating |
|
|
Total |
|
Income Statement |
|
ConocoPhillips |
|
|
Company |
|
|
Company |
|
|
Company I |
|
|
Company II |
|
|
Subsidiaries |
|
|
Adjustments |
|
|
Consolidated |
|
Revenues and Other Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues |
|
$ |
- |
|
|
|
38,753 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
24,031 |
|
|
|
- |
|
|
|
62,784 |
|
Equity in earnings of affiliates |
|
|
2,895 |
|
|
|
3,287 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
870 |
|
|
|
(5,754 |
) |
|
|
1,298 |
|
Gain on dispositions |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(480 |
) |
|
|
- |
|
|
|
(480 |
) |
Other income (loss) |
|
|
(1 |
) |
|
|
(63 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
91 |
|
|
|
- |
|
|
|
27 |
|
Intercompany revenues |
|
|
1 |
|
|
|
934 |
|
|
|
11 |
|
|
|
23 |
|
|
|
9 |
|
|
|
9,734 |
|
|
|
(10,712 |
) |
|
|
- |
|
|
Total Revenues and Other Income |
|
|
2,895 |
|
|
|
42,911 |
|
|
|
11 |
|
|
|
23 |
|
|
|
9 |
|
|
|
34,246 |
|
|
|
(16,466 |
) |
|
|
63,629 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased crude oil, natural gas and products |
|
|
- |
|
|
|
35,596 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
22,265 |
|
|
|
(10,264 |
) |
|
|
47,597 |
|
Production and operating expenses |
|
|
- |
|
|
|
1,133 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,678 |
|
|
|
(43 |
) |
|
|
2,768 |
|
Selling, general and administrative expenses |
|
|
2 |
|
|
|
306 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
142 |
|
|
|
16 |
|
|
|
466 |
|
Exploration expenses |
|
|
- |
|
|
|
99 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
167 |
|
|
|
- |
|
|
|
266 |
|
Depreciation, depletion and amortization |
|
|
- |
|
|
|
378 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,492 |
|
|
|
- |
|
|
|
1,870 |
|
Impairments |
|
|
- |
|
|
|
485 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
486 |
|
Taxes other than income taxes |
|
|
- |
|
|
|
1,303 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,276 |
|
|
|
- |
|
|
|
4,579 |
|
Accretion on discounted liabilities |
|
|
- |
|
|
|
17 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
97 |
|
|
|
- |
|
|
|
114 |
|
Interest and debt expense |
|
|
427 |
|
|
|
104 |
|
|
|
10 |
|
|
|
19 |
|
|
|
8 |
|
|
|
88 |
|
|
|
(421 |
) |
|
|
235 |
|
Foreign currency transaction (gains) losses |
|
|
- |
|
|
|
7 |
|
|
|
- |
|
|
|
(106 |
) |
|
|
(101 |
) |
|
|
268 |
|
|
|
- |
|
|
|
68 |
|
|
Total Costs and Expenses |
|
|
429 |
|
|
|
39,428 |
|
|
|
10 |
|
|
|
(87 |
) |
|
|
(93 |
) |
|
|
29,474 |
|
|
|
(10,712 |
) |
|
|
58,449 |
|
|
Income before income taxes |
|
|
2,466 |
|
|
|
3,483 |
|
|
|
1 |
|
|
|
110 |
|
|
|
102 |
|
|
|
4,772 |
|
|
|
(5,754 |
) |
|
|
5,180 |
|
Provision for income taxes |
|
|
(150 |
) |
|
|
588 |
|
|
|
- |
|
|
|
2 |
|
|
|
16 |
|
|
|
2,093 |
|
|
|
- |
|
|
|
2,549 |
|
|
Net income |
|
|
2,616 |
|
|
|
2,895 |
|
|
|
1 |
|
|
|
108 |
|
|
|
86 |
|
|
|
2,679 |
|
|
|
(5,754 |
) |
|
|
2,631 |
|
Less: net income attributable to
noncontrolling interests |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(15 |
) |
|
|
- |
|
|
|
(15 |
) |
|
Net Income Attributable to ConocoPhillips |
|
$ |
2,616 |
|
|
|
2,895 |
|
|
|
1 |
|
|
|
108 |
|
|
|
86 |
|
|
|
2,664 |
|
|
|
(5,754 |
) |
|
|
2,616 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Statement |
|
Three Months Ended September 30, 2010 |
|
Revenues and Other Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues |
|
$ |
- |
|
|
|
28,283 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
18,925 |
|
|
|
- |
|
|
|
47,208 |
|
Equity in earnings of affiliates |
|
|
3,214 |
|
|
|
3,728 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
711 |
|
|
|
(6,649 |
) |
|
|
1,004 |
|
Gain on dispositions |
|
|
- |
|
|
|
7 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,391 |
|
|
|
- |
|
|
|
1,398 |
|
Other income (loss) |
|
|
- |
|
|
|
52 |
|
|
|
- |
|
|
|
- |
|
|
|
(28 |
) |
|
|
(85 |
) |
|
|
- |
|
|
|
(61 |
) |
Intercompany revenues |
|
|
1 |
|
|
|
439 |
|
|
|
11 |
|
|
|
22 |
|
|
|
8 |
|
|
|
6,675 |
|
|
|
(7,156 |
) |
|
|
- |
|
|
Total Revenues and Other Income |
|
|
3,215 |
|
|
|
32,509 |
|
|
|
11 |
|
|
|
22 |
|
|
|
(20 |
) |
|
|
27,617 |
|
|
|
(13,805 |
) |
|
|
49,549 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased crude oil, natural gas and products |
|
|
- |
|
|
|
25,561 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
15,385 |
|
|
|
(6,895 |
) |
|
|
34,051 |
|
Production and operating expenses |
|
|
- |
|
|
|
1,125 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,479 |
|
|
|
(21 |
) |
|
|
2,583 |
|
Selling, general and administrative expenses |
|
|
2 |
|
|
|
332 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
160 |
|
|
|
(1 |
) |
|
|
493 |
|
Exploration expenses |
|
|
- |
|
|
|
91 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
161 |
|
|
|
- |
|
|
|
252 |
|
Depreciation, depletion and amortization |
|
|
- |
|
|
|
388 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,858 |
|
|
|
- |
|
|
|
2,246 |
|
Impairments |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
59 |
|
|
|
- |
|
|
|
59 |
|
Taxes other than income taxes |
|
|
- |
|
|
|
1,328 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,900 |
|
|
|
(1 |
) |
|
|
4,227 |
|
Accretion on discounted liabilities |
|
|
- |
|
|
|
15 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
95 |
|
|
|
- |
|
|
|
110 |
|
Interest and debt expense |
|
|
243 |
|
|
|
111 |
|
|
|
10 |
|
|
|
19 |
|
|
|
10 |
|
|
|
109 |
|
|
|
(238 |
) |
|
|
264 |
|
Foreign currency transaction (gains) losses |
|
|
- |
|
|
|
(22 |
) |
|
|
- |
|
|
|
50 |
|
|
|
47 |
|
|
|
(85 |
) |
|
|
- |
|
|
|
(10 |
) |
|
Total Costs and Expenses |
|
|
245 |
|
|
|
28,929 |
|
|
|
10 |
|
|
|
69 |
|
|
|
57 |
|
|
|
22,121 |
|
|
|
(7,156 |
) |
|
|
44,275 |
|
|
Income (loss) before income taxes |
|
|
2,970 |
|
|
|
3,580 |
|
|
|
1 |
|
|
|
(47 |
) |
|
|
(77 |
) |
|
|
5,496 |
|
|
|
(6,649 |
) |
|
|
5,274 |
|
Provision for income taxes |
|
|
(85 |
) |
|
|
366 |
|
|
|
- |
|
|
|
(2 |
) |
|
|
(15 |
) |
|
|
1,941 |
|
|
|
- |
|
|
|
2,205 |
|
|
Net income (loss) |
|
|
3,055 |
|
|
|
3,214 |
|
|
|
1 |
|
|
|
(45 |
) |
|
|
(62 |
) |
|
|
3,555 |
|
|
|
(6,649 |
) |
|
|
3,069 |
|
Less: net income attributable to
noncontrolling interests |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(14 |
) |
|
|
- |
|
|
|
(14 |
) |
|
Net Income (Loss) Attributable to
ConocoPhillips |
|
$ |
3,055 |
|
|
|
3,214 |
|
|
|
1 |
|
|
|
(45 |
) |
|
|
(62 |
) |
|
|
3,541 |
|
|
|
(6,649 |
) |
|
|
3,055 |
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Nine Months Ended September 30, 2011 |
|
|
|
|
|
|
|
|
|
|
|
ConocoPhillips |
|
|
ConocoPhillips |
|
|
ConocoPhillips |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australia |
|
|
Canada |
|
|
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ConocoPhillips |
|
|
Funding |
|
|
Funding |
|
|
Funding |
|
|
All Other |
|
|
Consolidating |
|
|
Total |
|
Income Statement |
|
ConocoPhillips |
|
|
Company |
|
|
Company |
|
|
Company I |
|
|
Company II |
|
|
Subsidiaries |
|
|
Adjustments |
|
|
Consolidated |
|
Revenues and Other Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues |
|
$ |
- |
|
|
|
114,877 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
70,064 |
|
|
|
- |
|
|
|
184,941 |
|
Equity in earnings of affiliates |
|
|
9,773 |
|
|
|
10,462 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,017 |
|
|
|
(18,777 |
) |
|
|
3,475 |
|
Gain on dispositions |
|
|
- |
|
|
|
311 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(97 |
) |
|
|
- |
|
|
|
214 |
|
Other income (loss) |
|
|
(1 |
) |
|
|
49 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
159 |
|
|
|
- |
|
|
|
207 |
|
Intercompany revenues |
|
|
3 |
|
|
|
3,037 |
|
|
|
34 |
|
|
|
69 |
|
|
|
26 |
|
|
|
28,958 |
|
|
|
(32,127 |
) |
|
|
- |
|
|
Total Revenues and Other Income |
|
|
9,775 |
|
|
|
128,736 |
|
|
|
34 |
|
|
|
69 |
|
|
|
26 |
|
|
|
101,101 |
|
|
|
(50,904 |
) |
|
|
188,837 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased crude oil, natural gas and products |
|
|
- |
|
|
|
106,919 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
64,071 |
|
|
|
(30,884 |
) |
|
|
140,106 |
|
Production and operating expenses |
|
|
- |
|
|
|
3,348 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,815 |
|
|
|
(161 |
) |
|
|
8,002 |
|
Selling, general and administrative expenses |
|
|
11 |
|
|
|
972 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
475 |
|
|
|
21 |
|
|
|
1,479 |
|
Exploration expenses |
|
|
- |
|
|
|
221 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
482 |
|
|
|
3 |
|
|
|
706 |
|
Depreciation, depletion and amortization |
|
|
- |
|
|
|
1,149 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,866 |
|
|
|
- |
|
|
|
6,015 |
|
Impairments |
|
|
- |
|
|
|
486 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2 |
|
|
|
- |
|
|
|
488 |
|
Taxes other than income taxes |
|
|
- |
|
|
|
3,839 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
9,935 |
|
|
|
(1 |
) |
|
|
13,773 |
|
Accretion on discounted liabilities |
|
|
- |
|
|
|
51 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
290 |
|
|
|
- |
|
|
|
341 |
|
Interest and debt expense |
|
|
1,109 |
|
|
|
327 |
|
|
|
31 |
|
|
|
58 |
|
|
|
24 |
|
|
|
300 |
|
|
|
(1,105 |
) |
|
|
744 |
|
Foreign currency transaction (gains) losses |
|
|
- |
|
|
|
(9 |
) |
|
|
- |
|
|
|
(50 |
) |
|
|
(93 |
) |
|
|
167 |
|
|
|
- |
|
|
|
15 |
|
|
Total Costs and Expenses |
|
|
1,120 |
|
|
|
117,303 |
|
|
|
31 |
|
|
|
8 |
|
|
|
(69 |
) |
|
|
85,403 |
|
|
|
(32,127 |
) |
|
|
171,669 |
|
|
Income before income taxes |
|
|
8,655 |
|
|
|
11,433 |
|
|
|
3 |
|
|
|
61 |
|
|
|
95 |
|
|
|
15,698 |
|
|
|
(18,777 |
) |
|
|
17,168 |
|
Provision for income taxes |
|
|
(391 |
) |
|
|
1,660 |
|
|
|
1 |
|
|
|
1 |
|
|
|
24 |
|
|
|
6,781 |
|
|
|
- |
|
|
|
8,076 |
|
|
Net income |
|
|
9,046 |
|
|
|
9,773 |
|
|
|
2 |
|
|
|
60 |
|
|
|
71 |
|
|
|
8,917 |
|
|
|
(18,777 |
) |
|
|
9,092 |
|
Less: net income attributable to
noncontrolling interests |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(46 |
) |
|
|
- |
|
|
|
(46 |
) |
|
Net Income Attributable to ConocoPhillips |
|
$ |
9,046 |
|
|
|
9,773 |
|
|
|
2 |
|
|
|
60 |
|
|
|
71 |
|
|
|
8,871 |
|
|
|
(18,777 |
) |
|
|
9,046 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Statement |
|
Nine Months Ended September 30, 2010 |
|
Revenues and Other Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues |
|
$ |
- |
|
|
|
85,619 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
52,096 |
|
|
|
- |
|
|
|
137,715 |
|
Equity in earnings of affiliates |
|
|
9,751 |
|
|
|
10,916 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,384 |
|
|
|
(20,091 |
) |
|
|
2,960 |
|
Gain on dispositions |
|
|
- |
|
|
|
23 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,648 |
|
|
|
- |
|
|
|
4,671 |
|
Other income (loss) |
|
|
- |
|
|
|
153 |
|
|
|
- |
|
|
|
- |
|
|
|
(28 |
) |
|
|
(33 |
) |
|
|
- |
|
|
|
92 |
|
Intercompany revenues |
|
|
4 |
|
|
|
713 |
|
|
|
34 |
|
|
|
65 |
|
|
|
58 |
|
|
|
19,556 |
|
|
|
(20,430 |
) |
|
|
- |
|
|
Total Revenues and Other Income |
|
|
9,755 |
|
|
|
97,424 |
|
|
|
34 |
|
|
|
65 |
|
|
|
30 |
|
|
|
78,651 |
|
|
|
(40,521 |
) |
|
|
145,438 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased crude oil, natural gas and products |
|
|
- |
|
|
|
76,927 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
40,397 |
|
|
|
(19,664 |
) |
|
|
97,660 |
|
Production and operating expenses |
|
|
- |
|
|
|
3,314 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,487 |
|
|
|
(72 |
) |
|
|
7,729 |
|
Selling, general and administrative expenses |
|
|
9 |
|
|
|
948 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
445 |
|
|
|
(27 |
) |
|
|
1,375 |
|
Exploration expenses |
|
|
- |
|
|
|
188 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
660 |
|
|
|
- |
|
|
|
848 |
|
Depreciation, depletion and amortization |
|
|
- |
|
|
|
1,204 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
5,640 |
|
|
|
- |
|
|
|
6,844 |
|
Impairments |
|
|
- |
|
|
|
17 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,665 |
|
|
|
- |
|
|
|
1,682 |
|
Taxes other than income taxes |
|
|
- |
|
|
|
3,901 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
8,611 |
|
|
|
(1 |
) |
|
|
12,511 |
|
Accretion on discounted liabilities |
|
|
- |
|
|
|
46 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
291 |
|
|
|
- |
|
|
|
337 |
|
Interest and debt expense |
|
|
662 |
|
|
|
359 |
|
|
|
31 |
|
|
|
58 |
|
|
|
37 |
|
|
|
433 |
|
|
|
(666 |
) |
|
|
914 |
|
Foreign currency transaction (gains) losses |
|
|
- |
|
|
|
13 |
|
|
|
- |
|
|
|
(5 |
) |
|
|
(6 |
) |
|
|
78 |
|
|
|
- |
|
|
|
80 |
|
|
Total Costs and Expenses |
|
|
671 |
|
|
|
86,917 |
|
|
|
31 |
|
|
|
53 |
|
|
|
31 |
|
|
|
62,707 |
|
|
|
(20,430 |
) |
|
|
129,980 |
|
|
Income (loss) before income taxes |
|
|
9,084 |
|
|
|
10,507 |
|
|
|
3 |
|
|
|
12 |
|
|
|
(1 |
) |
|
|
15,944 |
|
|
|
(20,091 |
) |
|
|
15,458 |
|
Provision for income taxes |
|
|
(233 |
) |
|
|
756 |
|
|
|
1 |
|
|
|
11 |
|
|
|
5 |
|
|
|
5,554 |
|
|
|
- |
|
|
|
6,094 |
|
|
Net income (loss) |
|
|
9,317 |
|
|
|
9,751 |
|
|
|
2 |
|
|
|
1 |
|
|
|
(6 |
) |
|
|
10,390 |
|
|
|
(20,091 |
) |
|
|
9,364 |
|
Less: net income attributable to
noncontrolling interests |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(47 |
) |
|
|
- |
|
|
|
(47 |
) |
|
Net Income (Loss) Attributable to
ConocoPhillips |
|
$ |
9,317 |
|
|
|
9,751 |
|
|
|
2 |
|
|
|
1 |
|
|
|
(6 |
) |
|
|
10,343 |
|
|
|
(20,091 |
) |
|
|
9,317 |
|
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
September 30, 2011 |
|
|
|
|
|
|
|
|
|
|
|
ConocoPhillips |
|
|
ConocoPhillips |
|
|
ConocoPhillips |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australia |
|
|
Canada |
|
|
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ConocoPhillips |
|
|
Funding |
|
|
Funding |
|
|
Funding |
|
|
All Other |
|
|
Consolidating |
|
|
Total |
|
Balance Sheet |
|
ConocoPhillips |
|
|
Company |
|
|
Company |
|
|
Company I |
|
|
Company II |
|
|
Subsidiaries |
|
|
Adjustments |
|
|
Consolidated |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
- |
|
|
|
162 |
|
|
|
2 |
|
|
|
31 |
|
|
|
2 |
|
|
|
3,661 |
|
|
|
(421 |
) |
|
|
3,437 |
|
Short-term investments |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,589 |
|
|
|
- |
|
|
|
2,589 |
|
Accounts and notes receivable |
|
|
54 |
|
|
|
7,924 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
20,115 |
|
|
|
(11,677 |
) |
|
|
16,416 |
|
Inventories |
|
|
- |
|
|
|
4,048 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,116 |
|
|
|
- |
|
|
|
7,164 |
|
Prepaid expenses and other current assets |
|
|
20 |
|
|
|
1,255 |
|
|
|
- |
|
|
|
1 |
|
|
|
- |
|
|
|
1,509 |
|
|
|
- |
|
|
|
2,785 |
|
|
Total Current Assets |
|
|
74 |
|
|
|
13,389 |
|
|
|
2 |
|
|
|
32 |
|
|
|
2 |
|
|
|
30,990 |
|
|
|
(12,098 |
) |
|
|
32,391 |
|
Investments, loans and long-term receivables* |
|
|
92,670 |
|
|
|
125,521 |
|
|
|
773 |
|
|
|
1,407 |
|
|
|
593 |
|
|
|
54,972 |
|
|
|
(242,090 |
) |
|
|
33,846 |
|
Net properties, plants and equipment |
|
|
- |
|
|
|
19,271 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
63,819 |
|
|
|
- |
|
|
|
83,090 |
|
Goodwill |
|
|
- |
|
|
|
3,606 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,606 |
|
Intangibles |
|
|
- |
|
|
|
738 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
26 |
|
|
|
- |
|
|
|
764 |
|
Other assets |
|
|
65 |
|
|
|
273 |
|
|
|
- |
|
|
|
2 |
|
|
|
3 |
|
|
|
649 |
|
|
|
- |
|
|
|
992 |
|
|
Total Assets |
|
$ |
92,809 |
|
|
|
162,798 |
|
|
|
775 |
|
|
|
1,441 |
|
|
|
598 |
|
|
|
150,456 |
|
|
|
(254,188 |
) |
|
|
154,689 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
- |
|
|
|
17,607 |
|
|
|
- |
|
|
|
3 |
|
|
|
1 |
|
|
|
15,322 |
|
|
|
(12,098 |
) |
|
|
20,835 |
|
Short-term debt |
|
|
(5 |
) |
|
|
26 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
595 |
|
|
|
- |
|
|
|
616 |
|
Accrued income and other taxes |
|
|
- |
|
|
|
514 |
|
|
|
- |
|
|
|
2 |
|
|
|
- |
|
|
|
4,057 |
|
|
|
- |
|
|
|
4,573 |
|
Employee benefit obligations |
|
|
- |
|
|
|
667 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
227 |
|
|
|
- |
|
|
|
894 |
|
Other accruals |
|
|
153 |
|
|
|
513 |
|
|
|
19 |
|
|
|
32 |
|
|
|
14 |
|
|
|
1,287 |
|
|
|
- |
|
|
|
2,018 |
|
|
Total Current Liabilities |
|
|
148 |
|
|
|
19,327 |
|
|
|
19 |
|
|
|
37 |
|
|
|
15 |
|
|
|
21,488 |
|
|
|
(12,098 |
) |
|
|
28,936 |
|
Long-term debt |
|
|
11,849 |
|
|
|
3,619 |
|
|
|
750 |
|
|
|
1,250 |
|
|
|
499 |
|
|
|
4,567 |
|
|
|
- |
|
|
|
22,534 |
|
Asset retirement obligations and accrued
environmental costs |
|
|
- |
|
|
|
1,652 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
7,634 |
|
|
|
- |
|
|
|
9,286 |
|
Joint venture acquisition obligation |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,769 |
|
|
|
- |
|
|
|
3,769 |
|
Deferred income taxes |
|
|
(1 |
) |
|
|
4,020 |
|
|
|
- |
|
|
|
13 |
|
|
|
20 |
|
|
|
13,927 |
|
|
|
- |
|
|
|
17,979 |
|
Employee benefit obligations |
|
|
- |
|
|
|
2,241 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
837 |
|
|
|
- |
|
|
|
3,078 |
|
Other liabilities and deferred credits* |
|
|
21,856 |
|
|
|
34,930 |
|
|
|
- |
|
|
|
62 |
|
|
|
4 |
|
|
|
19,149 |
|
|
|
(73,220 |
) |
|
|
2,781 |
|
|
Total Liabilities |
|
|
33,852 |
|
|
|
65,789 |
|
|
|
769 |
|
|
|
1,362 |
|
|
|
538 |
|
|
|
71,371 |
|
|
|
(85,318 |
) |
|
|
88,363 |
|
Retained earnings |
|
|
40,180 |
|
|
|
31,359 |
|
|
|
4 |
|
|
|
(35 |
) |
|
|
(10 |
) |
|
|
26,178 |
|
|
|
(50,995 |
) |
|
|
46,681 |
|
Other common stockholders equity |
|
|
18,777 |
|
|
|
65,650 |
|
|
|
2 |
|
|
|
114 |
|
|
|
70 |
|
|
|
52,387 |
|
|
|
(117,875 |
) |
|
|
19,125 |
|
Noncontrolling interests |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
520 |
|
|
|
- |
|
|
|
520 |
|
|
Total Liabilities and Stockholders Equity |
|
$ |
92,809 |
|
|
|
162,798 |
|
|
|
775 |
|
|
|
1,441 |
|
|
|
598 |
|
|
|
150,456 |
|
|
|
(254,188 |
) |
|
|
154,689 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet |
|
December 31, 2010 |
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
- |
|
|
|
718 |
|
|
|
- |
|
|
|
29 |
|
|
|
4 |
|
|
|
8,703 |
|
|
|
- |
|
|
|
9,454 |
|
Short-term investments |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
973 |
|
|
|
- |
|
|
|
973 |
|
Accounts and notes receivable |
|
|
36 |
|
|
|
9,126 |
|
|
|
1 |
|
|
|
- |
|
|
|
- |
|
|
|
16,625 |
|
|
|
(9,976 |
) |
|
|
15,812 |
|
Investment in LUKOIL |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,083 |
|
|
|
- |
|
|
|
1,083 |
|
Inventories |
|
|
- |
|
|
|
3,121 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,076 |
|
|
|
- |
|
|
|
5,197 |
|
Prepaid expenses and other current assets |
|
|
23 |
|
|
|
824 |
|
|
|
- |
|
|
|
2 |
|
|
|
- |
|
|
|
1,292 |
|
|
|
- |
|
|
|
2,141 |
|
|
Total Current Assets |
|
|
59 |
|
|
|
13,789 |
|
|
|
1 |
|
|
|
31 |
|
|
|
4 |
|
|
|
30,752 |
|
|
|
(9,976 |
) |
|
|
34,660 |
|
Investments, loans and long-term receivables* |
|
|
84,446 |
|
|
|
111,993 |
|
|
|
762 |
|
|
|
1,445 |
|
|
|
577 |
|
|
|
50,563 |
|
|
|
(216,025 |
) |
|
|
33,761 |
|
Net properties, plants and equipment |
|
|
- |
|
|
|
19,524 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
63,030 |
|
|
|
- |
|
|
|
82,554 |
|
Goodwill |
|
|
- |
|
|
|
3,633 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,633 |
|
Intangibles |
|
|
- |
|
|
|
760 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
41 |
|
|
|
- |
|
|
|
801 |
|
Other assets |
|
|
55 |
|
|
|
254 |
|
|
|
1 |
|
|
|
3 |
|
|
|
3 |
|
|
|
589 |
|
|
|
- |
|
|
|
905 |
|
|
Total Assets |
|
$ |
84,560 |
|
|
|
149,953 |
|
|
|
764 |
|
|
|
1,479 |
|
|
|
584 |
|
|
|
144,975 |
|
|
|
(226,001 |
) |
|
|
156,314 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
- |
|
|
|
14,939 |
|
|
|
- |
|
|
|
2 |
|
|
|
- |
|
|
|
13,434 |
|
|
|
(9,976 |
) |
|
|
18,399 |
|
Short-term debt |
|
|
(5 |
) |
|
|
354 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
587 |
|
|
|
- |
|
|
|
936 |
|
Accrued income and other taxes |
|
|
- |
|
|
|
431 |
|
|
|
- |
|
|
|
- |
|
|
|
6 |
|
|
|
4,437 |
|
|
|
- |
|
|
|
4,874 |
|
Employee benefit obligations |
|
|
- |
|
|
|
773 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
308 |
|
|
|
- |
|
|
|
1,081 |
|
Other accruals |
|
|
242 |
|
|
|
620 |
|
|
|
9 |
|
|
|
15 |
|
|
|
6 |
|
|
|
1,237 |
|
|
|
- |
|
|
|
2,129 |
|
|
Total Current Liabilities |
|
|
237 |
|
|
|
17,117 |
|
|
|
9 |
|
|
|
17 |
|
|
|
12 |
|
|
|
20,003 |
|
|
|
(9,976 |
) |
|
|
27,419 |
|
Long-term debt |
|
|
11,832 |
|
|
|
3,674 |
|
|
|
750 |
|
|
|
1,250 |
|
|
|
499 |
|
|
|
4,651 |
|
|
|
- |
|
|
|
22,656 |
|
Asset retirement obligations and accrued
environmental costs |
|
|
- |
|
|
|
1,686 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
7,513 |
|
|
|
- |
|
|
|
9,199 |
|
Joint venture acquisition obligation |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,314 |
|
|
|
- |
|
|
|
4,314 |
|
Deferred income taxes |
|
|
(1 |
) |
|
|
3,659 |
|
|
|
- |
|
|
|
16 |
|
|
|
(2 |
) |
|
|
13,663 |
|
|
|
- |
|
|
|
17,335 |
|
Employee benefit obligations |
|
|
- |
|
|
|
2,779 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
904 |
|
|
|
- |
|
|
|
3,683 |
|
Other liabilities and deferred credits* |
|
|
10,752 |
|
|
|
32,268 |
|
|
|
- |
|
|
|
114 |
|
|
|
61 |
|
|
|
19,169 |
|
|
|
(59,765 |
) |
|
|
2,599 |
|
|
Total Liabilities |
|
|
22,820 |
|
|
|
61,183 |
|
|
|
759 |
|
|
|
1,397 |
|
|
|
570 |
|
|
|
70,217 |
|
|
|
(69,741 |
) |
|
|
87,205 |
|
Retained earnings |
|
|
33,897 |
|
|
|
21,584 |
|
|
|
3 |
|
|
|
(94 |
) |
|
|
(81 |
) |
|
|
20,162 |
|
|
|
(35,074 |
) |
|
|
40,397 |
|
Other common stockholders equity |
|
|
27,843 |
|
|
|
67,186 |
|
|
|
2 |
|
|
|
176 |
|
|
|
95 |
|
|
|
54,049 |
|
|
|
(121,186 |
) |
|
|
28,165 |
|
Noncontrolling interests |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
547 |
|
|
|
- |
|
|
|
547 |
|
|
Total Liabilities and Stockholders Equity |
|
$ |
84,560 |
|
|
|
149,953 |
|
|
|
764 |
|
|
|
1,479 |
|
|
|
584 |
|
|
|
144,975 |
|
|
|
(226,001 |
) |
|
|
156,314 |
|
|
|
|
|
* Includes intercompany loans. |
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Nine Months Ended September 30, 2011 |
|
|
|
|
|
|
|
|
|
|
|
ConocoPhillips |
|
|
ConocoPhillips |
|
|
ConocoPhillips |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australia |
|
|
Canada |
|
|
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ConocoPhillips |
|
|
Funding |
|
|
Funding |
|
|
Funding |
|
|
All Other |
|
|
Consolidating |
|
|
Total |
|
Statement of Cash Flows |
|
ConocoPhillips |
|
|
Company |
|
|
Company |
|
|
Company I |
|
|
Company II |
|
|
Subsidiaries |
|
|
Adjustments |
|
|
Consolidated |
|
Cash Flows From Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by (Used in) Operating Activities |
|
$ |
10,645 |
|
|
|
(3,268 |
) |
|
|
2 |
|
|
|
6 |
|
|
|
(6 |
) |
|
|
9,732 |
|
|
|
(3,277 |
) |
|
|
13,834 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures and investments |
|
|
- |
|
|
|
(1,563 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(7,831 |
) |
|
|
- |
|
|
|
(9,394 |
) |
Proceeds from asset dispositions |
|
|
- |
|
|
|
428 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,730 |
|
|
|
- |
|
|
|
2,158 |
|
Net purchases of short-term investments |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1,623 |
) |
|
|
- |
|
|
|
(1,623 |
) |
Long-term advances/loansrelated parties |
|
|
- |
|
|
|
(113 |
) |
|
|
- |
|
|
|
(4 |
) |
|
|
- |
|
|
|
(4,562 |
) |
|
|
4,665 |
|
|
|
(14 |
) |
Collection of advances/loansrelated parties |
|
|
(1 |
) |
|
|
1,172 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,504 |
|
|
|
(2,037 |
) |
|
|
638 |
|
Other |
|
|
- |
|
|
|
7 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
89 |
|
|
|
- |
|
|
|
96 |
|
|
Net Cash Provided by (Used in) Investing Activities |
|
|
(1 |
) |
|
|
(69 |
) |
|
|
- |
|
|
|
(4 |
) |
|
|
- |
|
|
|
(10,693 |
) |
|
|
2,628 |
|
|
|
(8,139 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of debt |
|
|
- |
|
|
|
4,558 |
|
|
|
- |
|
|
|
- |
|
|
|
4 |
|
|
|
103 |
|
|
|
(4,665 |
) |
|
|
- |
|
Repayment of debt |
|
|
- |
|
|
|
(1,821 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(656 |
) |
|
|
2,037 |
|
|
|
(440 |
) |
Issuance of company common stock |
|
|
109 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
109 |
|
Repurchase of company common stock |
|
|
(7,984 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(7,984 |
) |
Dividends paid on common stock |
|
|
(2,761 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(2,856 |
) |
|
|
2,856 |
|
|
|
(2,761 |
) |
Other |
|
|
(8 |
) |
|
|
54 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(588 |
) |
|
|
- |
|
|
|
(542 |
) |
|
Net Cash Provided by (Used in) Financing Activities |
|
|
(10,644 |
) |
|
|
2,791 |
|
|
|
- |
|
|
|
- |
|
|
|
4 |
|
|
|
(3,997 |
) |
|
|
228 |
|
|
|
(11,618 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of Exchange Rate Changes
on Cash and Cash Equivalents |
|
|
- |
|
|
|
(10 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(84 |
) |
|
|
- |
|
|
|
(94 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Change in Cash and Cash Equivalents |
|
|
- |
|
|
|
(556 |
) |
|
|
2 |
|
|
|
2 |
|
|
|
(2 |
) |
|
|
(5,042 |
) |
|
|
(421 |
) |
|
|
(6,017 |
) |
Cash and cash equivalents at beginning of period |
|
|
- |
|
|
|
718 |
|
|
|
- |
|
|
|
29 |
|
|
|
4 |
|
|
|
8,703 |
|
|
|
- |
|
|
|
9,454 |
|
|
Cash and Cash Equivalents at End of Period |
|
$ |
- |
|
|
|
162 |
|
|
|
2 |
|
|
|
31 |
|
|
|
2 |
|
|
|
3,661 |
|
|
|
(421 |
) |
|
|
3,437 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Cash Flows |
|
Nine Months Ended September 30, 2010 |
Cash Flows From Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by (Used in) Operating Activities |
|
$ |
4,567 |
|
|
|
2,616 |
|
|
|
- |
|
|
|
5 |
|
|
|
(3 |
) |
|
|
6,288 |
|
|
|
(2,619 |
) |
|
|
10,854 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures and investments |
|
|
- |
|
|
|
(1,207 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(5,487 |
) |
|
|
323 |
|
|
|
(6,371 |
) |
Proceeds from asset dispositions |
|
|
- |
|
|
|
179 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
12,154 |
|
|
|
(100 |
) |
|
|
12,233 |
|
Long-term advances/loansrelated parties |
|
|
- |
|
|
|
(335 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1,408 |
) |
|
|
1,447 |
|
|
|
(296 |
) |
Collection of advances/loansrelated parties |
|
|
- |
|
|
|
79 |
|
|
|
- |
|
|
|
- |
|
|
|
384 |
|
|
|
1,379 |
|
|
|
(1,738 |
) |
|
|
104 |
|
Other |
|
|
- |
|
|
|
14 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
100 |
|
|
|
- |
|
|
|
114 |
|
|
Net Cash Provided by (Used in) Investing Activities |
|
|
- |
|
|
|
(1,270 |
) |
|
|
- |
|
|
|
- |
|
|
|
384 |
|
|
|
6,738 |
|
|
|
(68 |
) |
|
|
5,784 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of debt |
|
|
- |
|
|
|
1,309 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
234 |
|
|
|
(1,447 |
) |
|
|
96 |
|
Repayment of debt |
|
|
(990 |
) |
|
|
(2,645 |
) |
|
|
- |
|
|
|
- |
|
|
|
(378 |
) |
|
|
(3,029 |
) |
|
|
1,738 |
|
|
|
(5,304 |
) |
Issuance of company common stock |
|
|
59 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
59 |
|
Repurchase of company common stock |
|
|
(1,258 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(1,258 |
) |
Dividends paid on common stock |
|
|
(2,376 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(2,575 |
) |
|
|
2,575 |
|
|
|
(2,376 |
) |
Other |
|
|
(2 |
) |
|
|
27 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(346 |
) |
|
|
(223 |
) |
|
|
(544 |
) |
|
Net Cash Used in Financing Activities |
|
|
(4,567 |
) |
|
|
(1,309 |
) |
|
|
- |
|
|
|
- |
|
|
|
(378 |
) |
|
|
(5,716 |
) |
|
|
2,643 |
|
|
|
(9,327 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of Exchange Rate Changes
on Cash and Cash Equivalents |
|
|
- |
|
|
|
15 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
128 |
|
|
|
- |
|
|
|
143 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Change in Cash and Cash Equivalents |
|
|
- |
|
|
|
52 |
|
|
|
- |
|
|
|
5 |
|
|
|
3 |
|
|
|
7,438 |
|
|
|
(44 |
) |
|
|
7,454 |
|
Cash and cash equivalents at beginning of period |
|
|
- |
|
|
|
122 |
|
|
|
- |
|
|
|
18 |
|
|
|
1 |
|
|
|
554 |
|
|
|
(153 |
) |
|
|
542 |
|
|
Cash and Cash Equivalents at End of Period |
|
$ |
- |
|
|
|
174 |
|
|
|
- |
|
|
|
23 |
|
|
|
4 |
|
|
|
7,992 |
|
|
|
(197 |
) |
|
|
7,996 |
|
|
30
Item 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Managements Discussion and Analysis is the companys analysis of its financial performance and of
significant trends that may affect future performance. It should be read in conjunction with the
financial statements and notes. It contains forward-looking statements including, without
limitation, statements relating to the companys plans, strategies, objectives, expectations and
intentions that are made pursuant to the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995. The words anticipate, estimate, believe, budget,
continue, could, intend, may, plan, potential, predict, seek, should, will,
would, expect, objective, projection, forecast, goal, guidance, outlook, effort,
target and similar expressions identify forward-looking statements. The company does not
undertake to update, revise or correct any of the forward-looking information unless required to do
so under the federal securities laws. Readers are cautioned that such forward-looking statements
should be read in conjunction with the companys disclosures under the heading: CAUTIONARY
STATEMENT FOR THE PURPOSES OF THE SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES LITIGATION
REFORM ACT OF 1995, beginning on page 49.
The terms earnings and loss as used in Managements Discussion and Analysis refer to net income
(loss) attributable to ConocoPhillips.
BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW
ConocoPhillips is an international, integrated energy company. We are the third-largest U.S.
integrated energy company, based on market capitalization. At September 30, 2011, we had
approximately 29,700 employees worldwide and total assets of $155 billion.
Earnings of the company depend largely on the profitability of our Exploration and Production (E&P)
and Refining and Marketing (R&M) segments. Crude oil and natural gas prices, along with refining
margins, are the most significant factors in our profitability. Industry crude prices for West
Texas Intermediate (WTI) averaged $89.70 per barrel in the third quarter of 2011, an increase of 18
percent compared with the third quarter of 2010, and a decrease of 12 percent compared with the
second quarter of 2011. Global oil prices eased during the third quarter of 2011, compared with
the second quarter of 2011, as a result of concerns about slowing global economic growth and the
reduction in oil demand growth.
Henry Hub natural gas prices averaged $4.20 per million British thermal units in the third quarter
of 2011, a 4 percent decrease compared with the third quarter of 2010, and a 3 percent decrease
compared with the second quarter of 2011. U.S. natural gas prices decreased slightly during the
third quarter of 2011, as continued strong production outweighed increased demand. The higher
production levels have moved this years storage inventory levels closer to last years record-high
storage levels.
Earnings for our E&P segment generally correlate with industry price levels for crude oil and
natural gas. E&P earnings were $1,762 million in the third quarter of 2011, which accounted for 67
percent of our total company earnings in the quarter. This compares with E&P earnings of $1,564
million in the third quarter of 2010 and $2,524 million in the second quarter of 2011.
Domestic refining margins continued to significantly increase in the third quarter of 2011, and
international refining margins also improved. The U.S. 3:2:1 crack spread, which is primarily
WTI-based, increased 186 percent in the third quarter of 2011, compared with the third quarter of
2010, and 20 percent compared with the second quarter of 2011. These improvements were a result of
increased crude supplies in the Midcontinent area, causing WTI to trade at a deeper discount
relative to waterborne crudes. Refineries capable of processing WTI and crude oils that are
WTI-based continued to benefit from the lower crude oil prices. In contrast, East Coast refining,
which relies primarily on Brent-based crudes, has been under severe market pressure. Product
imports, weakness in motor fuel demand, and costly regulatory requirements are key challenges in
this difficult environment.
31
The N.W. Europe 3:1:2 crack spread increased 33 percent in the third quarter of 2011, compared with
the third quarter of 2010, and 10 percent compared with the second quarter of 2011.
Our R&M segment reported earnings of $789 million in the third quarter of 2011, compared with
earnings of $268 million in the third quarter of 2010 and $766 million in the second quarter of
2011. R&M earnings in the third quarter of 2011 included a $314 million after-tax impairment of
our Trainer Refinery in Pennsylvania and a $77 million after-tax loss on sale of our Wilhelmshaven
Refinery (WRG) in Germany. Consistent with our stated strategic initiatives to improve our
financial position and optimize our asset portfolio, we sold WRG in August 2011. In September
2011, we announced our intention to sell the Trainer Refinery, which has been idled and will
permanently close by the end of the first quarter 2012 if a sales transaction is unsuccessful.
RESULTS OF OPERATIONS
Unless otherwise indicated, discussion of results for the three- and nine-month periods ended
September 30, 2011, is based on a comparison with the corresponding periods of 2010.
Consolidated Results
A summary of net income (loss) attributable to ConocoPhillips by business segment follows:
| |
| |
| |
| |
| |
| |
| |
| |
|
|
|
Millions of Dollars |
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
September 30 |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
E&P |
|
$ |
1,762 |
|
|
|
1,564 |
|
|
|
6,638 |
|
|
|
7,510 |
|
Midstream |
|
|
137 |
|
|
|
77 |
|
|
|
340 |
|
|
|
215 |
|
R&M |
|
|
789 |
|
|
|
268 |
|
|
|
2,037 |
|
|
|
(15 |
) |
LUKOIL Investment |
|
|
- |
|
|
|
1,310 |
|
|
|
239 |
|
|
|
2,226 |
|
Chemicals |
|
|
197 |
|
|
|
132 |
|
|
|
589 |
|
|
|
380 |
|
Emerging Businesses |
|
|
(2 |
) |
|
|
(20 |
) |
|
|
(23 |
) |
|
|
(24 |
) |
Corporate and Other |
|
|
(267 |
) |
|
|
(276 |
) |
|
|
(774 |
) |
|
|
(975 |
) |
|
Net income attributable to ConocoPhillips |
|
$ |
2,616 |
|
|
|
3,055 |
|
|
|
9,046 |
|
|
|
9,317 |
|
|
Earnings for ConocoPhillips decreased 14 percent in the third quarter of 2011, and 3 percent for
the nine-month period ended September 30, 2011. The third quarter and nine-month periods of 2010
included gains of $952 million and $3,877 million after-tax, respectively, from asset dispositions
and LUKOIL share sales. In addition, the nine-month period of 2010 included a $1,103 million
after-tax impairment of WRG. Excluding these items, as well as impacts from 2011 asset
dispositions and the $314 million after-tax impairment of our Trainer Refinery in the third quarter
of 2011, earnings in both periods of 2011 improved primarily as a result of:
| | |
Higher prices in our E&P segment. Commodity price benefits were somewhat offset by
higher taxes. |
|
|
|
Improved results from our R&M operations, reflecting higher U.S. refining margins. |
These items were partially offset by the absence of equity earnings from LUKOIL due to the
divestiture of our interest.
See the Segment Results section for additional information on our segment results.
32
Income Statement Analysis
Sales and other operating revenues for the third quarter and nine-month periods of 2011
increased 33 percent and 34 percent, respectively, while purchased crude oil, natural gas and
products increased 40 percent and 43 percent, respectively. The increases were mainly due to
significantly higher prices for petroleum products, crude oil and natural gas liquids (NGL).
Equity in earnings of affiliates for the third quarter and nine-month periods of 2011
increased 29 percent and 17 percent, respectively. The increases in both periods primarily
resulted from:
| | |
Improved earnings from WRB Refining LP, primarily due to higher refining margins. |
| | |
Earnings from Qatar Liquefied Gas Company Limited (3) (QG3), primarily due to sales of
liquefied natural gas (LNG) following production startup, which occurred in October 2010. |
| | |
Improved earnings from Chevron Phillips Chemical Company LLC (CPChem), mainly due to
higher margins in the olefins and polyolefins business line. |
| | |
Improved earnings from DCP Midstream, LLC, mainly as a result of higher NGL prices. |
| | |
Improved earnings from FCCL Partnership, primarily due to higher commodity prices and
volumes. |
These increases in equity earnings were partially offset by the absence of equity earnings from
LUKOIL due to the divestiture of our interest. The nine-month period of 2011 also included an $85
million before-tax write-off of our investment associated with the cancelation of the Denali gas
pipeline project.
Gain (loss) on dispositions for the third quarter of 2011 was a $480 million loss, compared
with a gain of $1,398 million in the same period of 2010. The gain in the nine-month period of
2011 was $214 million, compared with $4,671 million in the 2010 nine-month period. Both 2010
periods included $1,219 million and $1,318 million, respectively, in gains from the sale of LUKOIL
shares. The nine-month period of 2010 also included a $2,878 million gain on sale of our Syncrude
oil sands mining operation. Losses realized in the third quarter of 2011 were primarily the result
of the dilution of our equity interest in Australia Pacific LNG Pty Ltd (APLNG) from 50 percent to
42.5 percent and the disposition of WRG. Additionally, the nine-month period of 2011 included
gains from the sale of certain E&P assets located in the Lower 48 and the remaining divestiture of
our LUKOIL shares.
Production and operating expenses increased 7 percent in the third quarter of 2011,
primarily as a result of higher operating costs, maintenance and unfavorable foreign currency
impacts.
Exploration expenses decreased 17 percent in the nine-month period of 2011, primarily as a
result of the Shah Project cancelation in the nine-month period of 2010.
Depreciation, depletion and amortization (DD&A) for the third quarter and nine-month
periods of 2011 decreased 17 percent and 12 percent, respectively. The decreases were mostly
associated with our E&P segment, reflecting lower production volumes.
Impairments for the third quarter of 2011 increased $427 million, mainly as a result of the
Trainer Refinery impairment. Impairments in the nine-month period of 2011 decreased $1,194
million, primarily due to the $1,502 million impairment of WRG in the second quarter of 2010,
partially offset by the third quarter 2011 Trainer impairment.
Taxes other than income taxes for the third quarter and nine-month periods of 2011
increased 8 percent and 10 percent, respectively, primarily due to higher production taxes as a
result of higher crude oil prices and higher excise taxes on petroleum product sales.
Interest and debt expense decreased 19 percent in the nine-month period of 2011, primarily
due to lower debt levels.
33
See Note 20Income Taxes in the Notes to Consolidated Financial Statements, for information
regarding our provision for income taxes and effective tax rate.
Segment Results
E&P
| |
| |
| |
| |
| |
| |
| |
| |
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
September 30 |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
Millions of Dollars |
Net Income Attributable to ConocoPhillips |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska |
|
$ |
501 |
|
|
|
361 |
|
|
|
1,540 |
|
|
|
1,259 |
|
Lower 48 |
|
|
315 |
|
|
|
202 |
|
|
|
956 |
|
|
|
597 |
|
|
United States |
|
|
816 |
|
|
|
563 |
|
|
|
2,496 |
|
|
|
1,856 |
|
International |
|
|
946 |
|
|
|
1,001 |
|
|
|
4,142 |
|
|
|
5,654 |
|
|
|
|
$ |
1,762 |
|
|
|
1,564 |
|
|
|
6,638 |
|
|
|
7,510 |
|
|
|
|
|
Dollars Per Unit |
Average Sales Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas liquids (per barrel) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
90.95 |
|
|
|
65.71 |
|
|
|
91.54 |
|
|
|
68.19 |
|
International |
|
|
104.40 |
|
|
|
71.75 |
|
|
|
103.31 |
|
|
|
72.72 |
|
Total consolidated operations |
|
|
97.10 |
|
|
|
69.22 |
|
|
|
97.34 |
|
|
|
70.74 |
|
Equity affiliates |
|
|
99.24 |
|
|
|
72.95 |
|
|
|
99.31 |
|
|
|
72.25 |
|
Total E&P |
|
|
97.24 |
|
|
|
69.45 |
|
|
|
97.47 |
|
|
|
70.83 |
|
Bitumen (per barrel) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International |
|
|
45.79 |
|
|
|
47.96 |
|
|
|
49.79 |
|
|
|
50.65 |
|
Equity affiliates |
|
|
60.65 |
|
|
|
52.38 |
|
|
|
61.50 |
|
|
|
52.82 |
|
Total E&P |
|
|
58.14 |
|
|
|
51.50 |
|
|
|
59.69 |
|
|
|
52.48 |
|
Natural gas (per thousand cubic feet)* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
4.17 |
|
|
|
4.10 |
|
|
|
4.17 |
|
|
|
4.40 |
|
International |
|
|
6.88 |
|
|
|
5.38 |
|
|
|
6.71 |
|
|
|
5.48 |
|
Total consolidated operations |
|
|
5.77 |
|
|
|
4.86 |
|
|
|
5.70 |
|
|
|
5.05 |
|
Equity affliliates |
|
|
2.85 |
|
|
|
2.82 |
|
|
|
2.91 |
|
|
|
2.84 |
|
Total E&P |
|
|
5.45 |
|
|
|
4.80 |
|
|
|
5.39 |
|
|
|
4.99 |
|
|
*Prior periods reclassified to conform to current-year presentation which includes intrasegment transfer pricing. |
|
|
|
Millions of Dollars |
Worldwide Exploration Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General administrative; geological and geophysical; and lease rentals |
|
$ |
115 |
|
|
|
130 |
|
|
|
416 |
|
|
|
521 |
|
Leasehold impairment |
|
|
40 |
|
|
|
96 |
|
|
|
122 |
|
|
|
180 |
|
Dry holes |
|
|
111 |
|
|
|
26 |
|
|
|
168 |
|
|
|
147 |
|
|
|
|
$ |
266 |
|
|
|
252 |
|
|
|
706 |
|
|
|
848 |
|
|
34
| |
| |
| |
| |
| |
| |
| |
| |
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
September 30 |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
Thousands of Barrels Daily |
Operating Statistics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas liquids produced |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska |
|
|
199 |
|
|
|
215 |
|
|
|
212 |
|
|
|
228 |
|
Lower 48 |
|
|
174 |
|
|
|
160 |
|
|
|
161 |
|
|
|
159 |
|
|
United States |
|
|
373 |
|
|
|
375 |
|
|
|
373 |
|
|
|
387 |
|
Canada |
|
|
37 |
|
|
|
40 |
|
|
|
37 |
|
|
|
41 |
|
Europe |
|
|
159 |
|
|
|
207 |
|
|
|
178 |
|
|
|
213 |
|
Asia Pacific/Middle East |
|
|
94 |
|
|
|
144 |
|
|
|
120 |
|
|
|
142 |
|
Africa |
|
|
30 |
|
|
|
80 |
|
|
|
41 |
|
|
|
79 |
|
|
Total consolidated operations |
|
|
693 |
|
|
|
846 |
|
|
|
749 |
|
|
|
862 |
|
Equity affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asia Pacific/Middle East |
|
|
22 |
|
|
|
- |
|
|
|
23 |
|
|
|
- |
|
Russia |
|
|
26 |
|
|
|
51 |
|
|
|
32 |
|
|
|
54 |
|
|
|
|
|
741 |
|
|
|
897 |
|
|
|
804 |
|
|
|
916 |
|
|
|
|
|
Synthetic oil produced |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operationsCanada |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
15 |
|
|
|
|
|
Bitumen produced |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operationsCanada |
|
|
11 |
|
|
|
10 |
|
|
|
10 |
|
|
|
9 |
|
Equity affiliatesCanada |
|
|
53 |
|
|
|
49 |
|
|
|
55 |
|
|
|
50 |
|
|
|
|
|
64 |
|
|
|
59 |
|
|
|
65 |
|
|
|
59 |
|
|
| | |
| | |
| | |
| | |
| | |
| |
|
|
Millions of Cubic Feet Daily |
Natural gas produced* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska |
|
|
56 |
|
|
|
82 |
|
|
|
61 |
|
|
|
86 |
|
Lower 48 |
|
|
1,561 |
|
|
|
1,738 |
|
|
|
1,557 |
|
|
|
1,728 |
|
|
United States |
|
|
1,617 |
|
|
|
1,820 |
|
|
|
1,618 |
|
|
|
1,814 |
|
Canada |
|
|
929 |
|
|
|
974 |
|
|
|
940 |
|
|
|
1,012 |
|
Europe |
|
|
511 |
|
|
|
731 |
|
|
|
616 |
|
|
|
812 |
|
Asia Pacific/Middle East |
|
|
700 |
|
|
|
748 |
|
|
|
705 |
|
|
|
713 |
|
Africa |
|
|
161 |
|
|
|
158 |
|
|
|
157 |
|
|
|
147 |
|
|
Total consolidated operations |
|
|
3,918 |
|
|
|
4,431 |
|
|
|
4,036 |
|
|
|
4,498 |
|
Equity affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asia Pacific/Middle East |
|
|
479 |
|
|
|
134 |
|
|
|
503 |
|
|
|
112 |
|
|
|
|
|
4,397 |
|
|
|
4,565 |
|
|
|
4,539 |
|
|
|
4,610 |
|
|
*Represents quantities available for sale. Excludes gas equivalent of natural gas liquids included above.
35
The E&P segment explores for, produces, transports and markets crude oil, bitumen, natural
gas, LNG and natural gas liquids on a worldwide basis. At September 30, 2011, our E&P production
operations were located in the United States, Norway, the United Kingdom, Canada, Australia,
offshore Timor-Leste in the Timor Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria, Qatar
and Russia. Total E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 1,538,000 BOE
per day in the third quarter of 2011, compared with 1,717,000 BOE per day in the third quarter of
2010. Production for the nine-month period of 2011 averaged 1,626,000 BOE per day, compared with
1,758,000 BOE per day for the same period in 2010.
Our E&P operations reported earnings of $1,762 million in the third quarter of 2011, an increase of
13 percent compared with the third quarter of 2010. E&P earnings for the first nine months of 2011
were $6,638 million, a 12 percent decrease compared with the same period of 2010. See the
Business Environment and Executive Overview section for additional information on industry crude
oil and natural gas prices.
U.S. E&P
Our U.S. E&P operations reported earnings of $816 million in the third quarter of 2011, a 45
percent increase compared with the same period in 2010. U.S. E&P earnings for the nine-month
period of 2011 were $2,496 million, a 34 percent increase compared with the same period in 2010.
The increases for both periods of 2011 were primarily the result of higher crude oil and natural
gas liquids prices, and to a lesser extent, lower DD&A. These increases were partially offset by
higher production taxes, primarily in Alaska, and higher operating expenses. The third quarter of
2011 also benefitted from higher crude sales. In addition, the nine-month period of 2011 included
higher gains from asset sales in the Lower 48, partially offset by lower sales volumes.
U.S. E&P production averaged 643,000 BOE per day in the third quarter of 2011, a decrease of 5
percent from 678,000 BOE per day in the third quarter of 2010. The decrease was mainly due to
field decline and asset dispositions, which were partially offset by new production, primarily from
shale plays in the Lower 48.
International E&P
International E&P earnings were $946 million in the third quarter of 2011, a 5 percent decrease
compared with the third quarter of 2010. International E&P earnings for the first nine months of
2011 were $4,142 million, a 27 percent decrease compared with the same period in 2010. Earnings in
the third quarter and nine-month period of 2011 included a $279 million loss on the dilution of our
equity interest in APLNG from 50 percent to 42.5 percent. In addition, both periods were impacted
by $234 million in additional income tax expense, as a result of legislation enacted in the United
Kingdom in July 2011. This additional tax expense consisted of $106 million for the revaluation of
deferred tax liabilities; $75 million to reflect the higher tax rates from the effective date of
the legislation, March 24, 2011, through June 30, 2011; and $53 million for the impact of the
higher tax rates on third quarter 2011 earnings. Additionally, the nine-month period of 2010
included the $2,679 million after-tax gain on sale of Syncrude. Excluding the impact from these
items, earnings increased in both periods of 2011, primarily due to higher prices, LNG sales from
QG3 and lower DD&A. These increases to earnings were partially offset by lower volumes and higher
taxes.
International E&P production averaged 895,000 BOE per day in the third quarter of 2011, a decrease
of 14 percent from 1,039,000 BOE per day in the third quarter of 2010. The decrease primarily
resulted from suspended operations in Libya and in Bohai Bay, China, asset dispositions and
downtime. Normal field decline was largely offset by new production.
36
Midstream
| | | | | | | | | | | | | | | | |
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
September 30 |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
Millions of Dollars |
|
|
Net Income Attributable to ConocoPhillips* |
|
$ |
137 |
|
|
|
77 |
|
|
|
340 |
|
|
|
215 |
|
|
*Includes DCP Midstream-related earnings: |
|
$ |
83 |
|
|
|
39 |
|
|
|
217 |
|
|
|
123 |
|
| | | | | | | | | | | | | | | | |
|
|
Dollars Per Barrel |
|
Average Sales Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. natural gas liquids* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated |
|
$ |
59.26 |
|
|
|
40.55 |
|
|
|
57.32 |
|
|
|
44.23 |
|
Equity affiliates |
|
|
52.09 |
|
|
|
36.66 |
|
|
|
50.66 |
|
|
|
40.14 |
|
|
*Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by natural gas liquids component and location mix.
| | | | | | | | | | | | | | | | |
|
|
Thousands of Barrels Daily |
|
Operating Statistics* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas liquids extracted |
|
|
204 |
|
|
|
198 |
|
|
|
197 |
|
|
|
192 |
|
Natural gas liquids fractionated** |
|
|
148 |
|
|
|
134 |
|
|
|
144 |
|
|
|
150 |
|
|
*Includes
our share of equity affiliate.
**Excludes DCP Midstream.
The Midstream segment purchases raw natural gas from producers and gathers natural gas
through an extensive network of pipeline gathering systems. The natural gas is then processed to
extract natural gas liquids from the raw gas stream. The remaining residue gas is marketed to
electrical utilities, industrial users, and gas marketing companies. Most of the natural gas
liquids are fractionatedseparated into individual components like ethane, butane and propaneand
marketed as chemical feedstock, fuel or blendstock. The Midstream segment consists of our 50
percent equity investment in DCP Midstream, LLC, as well as our other natural gas gathering and
processing operations, and natural gas liquids fractionation, trading and marketing businesses,
primarily in the United States and Trinidad.
Earnings from the Midstream segment increased 78 percent in the third quarter of 2011 and 58
percent in the first nine months of 2011. The increases in both periods were primarily due to
higher NGL prices.
37
R&M
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
September 30 |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
Millions of Dollars |
|
Net Income (Loss) Attributable to ConocoPhillips |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
789 |
|
|
|
199 |
|
|
|
1,883 |
|
|
|
993 |
|
International |
|
|
- |
|
|
|
69 |
|
|
|
154 |
|
|
|
(1,008 |
) |
|
|
|
$ |
789 |
|
|
|
268 |
|
|
|
2,037 |
|
|
|
(15 |
) |
|
| | | |
| | | |
| | | |
| | | |
|
|
|
Dollars Per Gallon |
|
U.S. Average Wholesale Prices* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline |
|
$ |
3.04 |
|
|
|
2.21 |
|
|
|
2.99 |
|
|
|
2.21 |
|
Distillates |
|
|
3.16 |
|
|
|
2.24 |
|
|
|
3.11 |
|
|
|
2.23 |
|
|
*Excludes excise taxes.
| | |
| | |
| | |
| | |
| | |
| |
|
|
Thousands of Barrels Daily |
|
Operating Statistics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refining operations* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil capacity |
|
|
1,986 |
|
|
|
1,986 |
|
|
|
1,986 |
|
|
|
1,986 |
|
Crude oil runs |
|
|
1,827 |
|
|
|
1,833 |
|
|
|
1,782 |
|
|
|
1,830 |
|
Capacity utilization (percent) |
|
|
92 |
% |
|
|
92 |
|
|
|
90 |
|
|
|
92 |
|
Refinery production |
|
|
1,991 |
|
|
|
1,992 |
|
|
|
1,964 |
|
|
|
1,998 |
|
International |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil capacity |
|
|
426 |
|
|
|
671 |
|
|
|
426 |
|
|
|
671 |
|
Crude oil runs |
|
|
396 |
|
|
|
399 |
|
|
|
406 |
|
|
|
362 |
|
Capacity utilization (percent) |
|
|
93 |
% |
|
|
60 |
|
|
|
95 |
|
|
|
54 |
|
Refinery production |
|
|
407 |
|
|
|
407 |
|
|
|
416 |
|
|
|
370 |
|
Worldwide |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil capacity |
|
|
2,412 |
|
|
|
2,657 |
|
|
|
2,412 |
|
|
|
2,657 |
|
Crude oil runs |
|
|
2,223 |
|
|
|
2,232 |
|
|
|
2,188 |
|
|
|
2,192 |
|
Capacity utilization (percent) |
|
|
92 |
% |
|
|
84 |
|
|
|
91 |
|
|
|
82 |
|
Refinery production |
|
|
2,398 |
|
|
|
2,399 |
|
|
|
2,380 |
|
|
|
2,368 |
|
|
|
Petroleum products sales volumes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasoline |
|
|
1,134 |
|
|
|
1,103 |
|
|
|
1,150 |
|
|
|
1,122 |
|
Distillates |
|
|
907 |
|
|
|
874 |
|
|
|
873 |
|
|
|
868 |
|
Other products |
|
|
402 |
|
|
|
432 |
|
|
|
408 |
|
|
|
395 |
|
|
|
|
|
2,443 |
|
|
|
2,409 |
|
|
|
2,431 |
|
|
|
2,385 |
|
International |
|
|
746 |
|
|
|
697 |
|
|
|
703 |
|
|
|
602 |
|
|
|
|
|
3,189 |
|
|
|
3,106 |
|
|
|
3,134 |
|
|
|
2,987 |
|
|
*Includes our share of equity affiliates.
38
The R&M segment refines crude oil and other feedstocks into petroleum products (such as
gasoline, distillates and aviation fuels); buys, sells and transports crude oil; and buys,
transports, distributes and markets petroleum products. R&M has operations mainly in the United
States, Europe and Asia.
R&M reported earnings of $789 million during the third quarter of 2011, an increase of $521 million
compared with the third quarter of 2010. Earnings for the nine-month period of 2011 were $2,037
million, an increase of $2,052 million compared with the same period in 2010. See the Business
Environment and Executive Overview section for additional information on industry refining
margins.
U.S. R&M
U.S. R&M earnings were $789 million in the third quarter of 2011, an increase of $590 million
compared with the third quarter of 2010. Earnings for the first nine months of 2011 were $1,883
million, an increase of $890 million. Earnings for both periods of 2011 improved primarily due to
significantly higher refining margins, which were partially offset by the $314 million after-tax
impairment and warehouse inventory write-down associated with our Trainer Refinery. Earnings in the third quarter of 2011 also benefitted from
improved marketing margins. Additionally, the nine-month period of 2010 included the $113 million
after-tax gain on sale of our 50 percent interest in CFJ Properties.
Our U.S. refining capacity utilization rate was 92 percent in the third quarter of 2011 and in the
third quarter of 2010. The current year rate primarily reflects higher unplanned downtime and run
reductions due to East Coast market conditions, offset by lower turnaround activity and
maintenance.
International R&M
International R&M broke even in the third quarter of 2011, and earnings were $154 million for the
nine-month period of 2011, compared with earnings of $69 million and a loss of $1,008 million for
the respective periods in 2010. Higher refining and marketing margins in the third quarter of 2011
were offset by the $77 million after-tax loss on sale of WRG and foreign currency losses. Earnings
for the nine-month period of 2011 increased primarily due to the absence of the 2010 WRG impairment
and foreign currency gains in 2011, partially offset by lower refining margins.
Our international refining capacity utilization rate was 93 percent in the third quarter of 2011,
compared with 60 percent in the third quarter of 2010. The increase primarily resulted from the
removal of WRG from our refining capacities effective January 1, 2011, partially offset by higher
turnaround activity and unplanned downtime in the third quarter of 2011.
39
LUKOIL Investment
| | | | | | | | | | | | | | | | |
|
|
Millions of Dollars |
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
September 30 |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Net Income Attributable to ConocoPhillips |
|
$ |
- |
|
|
|
1,310 |
|
|
|
239 |
|
|
|
2,226 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Statistics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil production (thousands of barrels daily) |
|
|
- |
|
|
|
366 |
|
|
|
- |
|
|
|
380 |
|
Natural gas produced (millions of cubic feet daily) |
|
|
- |
|
|
|
338 |
|
|
|
- |
|
|
|
339 |
|
Refinery crude oil processed (thousands of barrels daily) |
|
|
- |
|
|
|
263 |
|
|
|
- |
|
|
|
252 |
|
|
|
This segment represents our former investment in the ordinary shares of OAO LUKOIL, an
international, integrated oil and gas company headquartered in Russia. We sold our remaining
interest in LUKOIL in the first quarter of 2011.
Earnings in the nine-month period of 2011 primarily represented the realized gain on remaining
share sales. Earnings for the three- and nine-month periods of 2010 primarily reflected earnings
from the equity investment in LUKOIL we held at the time, in addition to gains on the partial sale
of our LUKOIL investment.
Chemicals
| | |
| | |
| | |
| | |
| | |
| |
|
|
Millions of Dollars |
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
September 30 |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
Net Income Attributable to ConocoPhillips |
|
$ |
197 |
|
|
|
132 |
|
|
|
589 |
|
|
|
380 |
|
|
|
The Chemicals segment consists of our 50 percent interest in Chevron Phillips Chemical Company LLC
(CPChem), which we account for under the equity method. CPChem uses natural gas liquids and other
feedstocks to produce petrochemicals. These products are then marketed and sold, or used as
feedstocks to produce plastics and commodity chemicals.
Earnings from the Chemicals segment increased 49 percent in the third quarter of 2011 and 55
percent in the nine-month period of 2011, compared with the corresponding periods of 2010. The
increases in both periods of 2011 primarily resulted from higher margins, volumes and equity
earnings in the olefins and polyolefins business line. The specialties, aromatics and styrenics
business line also contributed to the increase in earnings.
40
Emerging Businesses
| | |
| | |
| | |
| | |
| | |
| |
|
|
Millions of Dollars |
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September 30 |
|
|
September 30 |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Net Income (Loss) Attributable to ConocoPhillips |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power
|
|
$ |
32 |
|
|
|
8 |
|
|
|
71 |
|
|
|
54 |
|
Other
|
|
|
(34 |
) |
|
|
(28 |
) |
|
|
(94 |
) |
|
|
(78 |
) |
|
|
|
|
$ |
(2 |
) |
|
|
(20 |
) |
|
|
(23 |
) |
|
|
(24 |
) |
|
|
The Emerging Businesses segment represents our investment in new technologies or businesses outside
our normal scope of operations. Activities within this segment are currently focused on power
generation and innovation of new technologies, such as those related to conventional and
nonconventional hydrocarbon recovery, refining, alternative energy, biofuels and the environment.
Emerging Businesses reported a loss of $2 million in the third quarter of 2011, and a loss of $23
million in the nine-month period of 2011. The increase in Power earnings in the third quarter
and nine-month period of 2011 was primarily due to the absence of 2010 impairment charges related
to a U.S. cogeneration plant, which was sold in December 2010. The earnings increase was partially
offset by lower international power generation results in the nine-month period of 2011. Higher
technology development expenses contributed to the increase in Other losses for both periods in
2011.
Corporate and Other
| | |
| | |
| | |
| | |
| | |
| |
|
|
Millions of Dollars |
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
September 30 |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Net Income (Loss) Attributable to ConocoPhillips |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest |
|
$ |
(166 |
) |
|
|
(285 |
) |
|
|
(512 |
) |
|
|
(761 |
) |
Corporate general and administrative expenses |
|
|
(34 |
) |
|
|
(37 |
) |
|
|
(143 |
) |
|
|
(120 |
) |
Other |
|
|
(67 |
) |
|
|
46 |
|
|
|
(119 |
) |
|
|
(94 |
) |
|
|
|
|
$ |
(267 |
) |
|
|
(276 |
) |
|
|
(774 |
) |
|
|
(975 |
) |
|
|
Net interest consists of interest and financing expense, net of interest income and capitalized
interest, as well as premiums incurred on the early retirement of debt. Net interest decreased 42
percent in the third quarter of 2011 and 33 percent in the first nine months of 2011. The decrease
in both periods of 2011 was primarily due to the absence of a $114 million after-tax premium on
early debt retirement which occurred in the third quarter of 2010. In addition, the nine-month
period of 2011 benefitted from lower interest expense due to lower debt levels and higher interest
income.
Corporate general and administrative expenses increased 19 percent in the nine-month period of
2011, mainly due to costs related to overhead and compensation and benefit plans.
The category Other includes certain foreign currency transaction gains and losses, environmental
costs associated with sites no longer in operation, and other costs not directly associated with an
operating segment. The earnings decrease in the Other category in the third quarter of 2011
primarily reflected foreign currency transaction losses, compared with foreign currency transaction
gains in the corresponding period of 2010. The earnings decrease in the nine-month period of 2011
was mostly due to various tax-related adjustments.
41
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
| | | | | | | | |
|
|
Millions of Dollars |
|
|
|
September 30 |
|
|
December 31 |
|
|
|
2011 |
|
|
2010 |
|
Short-term debt |
|
$ |
616 |
|
|
|
936 |
|
Total debt |
|
$ |
23,150 |
|
|
|
23,592 |
|
Total equity |
|
$ |
66,326 |
|
|
|
69,109 |
|
Percent of total debt to capital* |
|
|
26 |
% |
|
|
25 |
|
Percent of floating-rate debt to total debt** |
|
|
9 |
% |
|
|
10 |
|
|
|
*Capital includes total debt and total equity.
**Includes effect of interest rate swaps.
To meet our short- and long-term liquidity requirements, we look to a variety of funding
sources. Cash generated from operating activities is the primary source of funding. In addition,
during the first nine months of 2011, we received $2,158 million in proceeds from asset sales,
including $1,243 million in cash proceeds from the divestiture of our remaining interest in LUKOIL
in the first quarter of 2011. During the first nine months of 2011, available cash was used to
support our ongoing capital expenditures and investments program, repurchase common stock, make net
purchases of short-term investments, pay dividends and repay debt. Total dividends paid on our
common stock during the first nine months were $2,761 million. During the first nine months of
2011, cash and cash equivalents decreased by $6,017 million to $3,437 million. Of this decrease,
$1,623 million relates to movement of cash and cash equivalents into short-term investments.
In addition to cash flows from operating activities and proceeds from asset sales, we rely on our
commercial paper and credit facility programs and our shelf registration statement to support our
short- and long-term liquidity requirements. We believe current cash and short-term investment
balances and cash generated by operations, together with access to external sources of funds as
described below in the Significant Sources of Capital section, will be sufficient to meet our
funding requirements in the near- and long-term, including our capital spending program, dividend
payments, required debt payments and the funding requirements to FCCL Partnership.
Significant Sources of Capital
Operating Activities
During the first nine months of 2011, cash of $13,834 million was provided by operating activities,
a 27 percent increase from cash from operations of $10,854 million in the corresponding period of
2010. The increase was primarily due to stronger crude oil and natural gas liquids prices,
improved refining margins and higher distributions from equity affiliates.
While the stability of our cash flows from operating activities benefits from geographic diversity,
our short- and long-term operating cash flows are highly dependent upon prices for crude oil,
bitumen, natural gas, LNG and natural gas liquids, as well as refining and marketing margins.
During the first nine months of 2011, crude oil prices were higher than in the same period of 2010.
Prices and margins in our industry are typically volatile and are driven by market conditions
over which we have no control. Absent other mitigating factors, as these prices and margins
fluctuate, we would expect a corresponding change in our operating cash flows.
The level of our production volumes also impacts our cash flows. These production levels are
impacted by such factors as acquisitions and dispositions of fields, field production decline
rates, new technologies, operating efficiency, weather conditions, the addition of proved reserves
through exploratory success, and their
42
timely and cost-effective development. While we actively manage these factors, production levels
can cause variability in cash flows, although historically this variability has not been as
significant as that caused by commodity prices.
In addition, the level and quality of output from our refineries impacts our cash flows. The
output at our refineries is impacted by such factors as operating efficiency, maintenance
turnarounds, market conditions, feedstock availability and weather conditions. We actively manage
the operations of our refineries and, typically, any variability in their operations has not been
as significant to cash flows as that caused by refining margins.
Asset Sales
Proceeds from asset sales during the first nine months of 2011 were $2.2 billion, including $1.2
billion from the sale of our remaining interest in LUKOIL. Other asset sales primarily included
mature North American natural gas assets. This compares with proceeds of $12.2 billion in the
first nine months of 2010, which included $4.6 billion from the sale of our 9.03 percent interest
in the Syncrude Canada Ltd. joint venture. Over the remainder of 2011, and through the end of
2012, we plan to raise an additional $7 billion to $12 billion from sales of non-strategic assets.
Commercial Paper and Credit Facilities
In August 2011, we increased our total revolving credit facilities from $7.85 billion to $8.0
billion. We replaced our $7.35 billion revolving credit facility with a $7.5 billion facility
expiring in August 2016. The terms of the new revolving credit facility are similar to the terms
of the replaced facility. We also have a $500 million facility expiring in July 2012. Our
revolving credit facilities may be used as direct bank borrowings, as support for issuances of
letters of credit totaling up to $750 million, or as support for our commercial paper programs.
The revolving credit facilities do not contain any material adverse change provisions or any
covenants requiring maintenance of specified financial ratios or ratings. The facility agreements
contain a cross-default provision relating to the failure to pay principal or interest on other
debt obligations of $200 million or more by ConocoPhillips, or by any of its consolidated
subsidiaries.
Credit facility borrowings may bear interest at a margin above rates offered by certain designated
banks in the London interbank market or at a margin above the overnight federal funds rate or prime
rates offered by certain designated banks in the United States. The agreements call for commitment
fees on available, but unused, amounts. The agreements also contain early termination rights if
our current directors or their approved successors cease to be a majority of the Board of
Directors.
Our primary funding source for short-term working capital needs is the ConocoPhillips $6.35 billion
commercial paper program. Commercial paper maturities are generally limited to 90 days. We also
have the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, which is used to
fund commitments relating to the QG3 Project. At September 30, 2011, and December 31, 2010, we had
no direct borrowings under the revolving credit facilities, but $40 million in letters of credit
had been issued at both periods. In addition, under the two ConocoPhillips commercial paper
programs, $1,127 million of commercial paper was outstanding at September 30, 2011, compared with
$1,182 million at December 31, 2010. Since we had $1,127 million of commercial paper outstanding
and had issued $40 million of letters of credit, we had access to $6.8 billion in borrowing
capacity under our revolving credit facilities at September 30, 2011.
Shelf Registration
We have a universal shelf registration statement on file with the U.S. Securities and Exchange
Commission (SEC) under which we, as a well-known seasoned issuer, have the ability to issue and
sell an indeterminate amount of various types of debt and equity securities.
43
Off-Balance Sheet Arrangements
As part of our normal ongoing business operations and consistent with normal industry practice, we
enter into numerous agreements with other parties to pursue business opportunities, which share
costs and apportion risks among the parties as governed by the agreements. At September 30, 2010,
we were liable for certain contingent obligations under our agreements with respect to QG3.
We own a 30 percent interest in QG3, an integrated project to produce and liquefy natural gas from
Qatars North Field. The other participants in the project are affiliates of Qatar Petroleum (68.5
percent) and Mitsui & Co., Ltd. (1.5 percent). Our interest is held through a jointly owned
company, Qatar Liquefied Gas Company Limited (3), for which we use the equity method of accounting.
QG3 secured project financing of $4 billion in December 2005, consisting of $1.3 billion of loans
from export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from
ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA
and commercial bank facilities. Prior to project completion certification, all loans, including
the ConocoPhillips loan facilities, are guaranteed by the participants, based on their respective
ownership interests. Accordingly, our maximum exposure to this financing structure is $1.2
billion. Upon completion certification, currently expected later in 2011, all project loan
facilities, including the ConocoPhillips loan facilities, will become nonrecourse to the project
participants. At September 30, 2011, QG3 had approximately $3.9 billion outstanding under all the
loan facilities, including the $1.2 billion from ConocoPhillips.
For additional information about guarantees, see Note 12Guarantees, in the Notes to Consolidated
Financial Statements, which is incorporated herein by reference.
Capital Requirements
For information about our capital expenditures and investments, see the Capital Spending section.
Our debt balance at September 30, 2011, was $23.2 billion, a decrease of $442 million from the
balance at December 31, 2010. In the fourth quarter of 2011, we plan to repay $500 million of 6.5%
Notes when they mature.
We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in
2007, to FCCL. Quarterly principal and interest payments of $237 million began in the second
quarter of 2007 and will continue until the balance is paid. Of the principal obligation amount,
$723 million was short-term and was included in the Accounts payablerelated parties line on our
September 30, 2011, consolidated balance sheet. The principal portion of these payments, which
totaled $518 million in the first nine months of 2011, is included in the Other line in the
financing activities section of our consolidated statement of cash flows. Interest accrues at a
fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly
interest payment is reflected as a capital contribution and is included in the Capital
expenditures and investments line on our consolidated statement of cash flows.
We have provided loan financing to WRB Refining LP, to assist it in meeting its operating and
capital spending requirements. In June 2011, $400 million was repaid to ConocoPhillips and in
September 2011, $150 million was repaid. No outstanding balance remains.
In October 2011, we announced a dividend of 66 cents per share. The dividend will be paid
December 1, 2011, to stockholders of record at the close of business October 17, 2011.
On March 24, 2010, our Board of Directors authorized the purchase of up to $5 billion of our common
stock through 2011. Repurchase of shares under this authorization was completed during the first
quarter of 2011. On February 11, 2011, the Board authorized the purchase of up to an additional
$10 billion of our common stock over the subsequent two years. Under both programs, repurchases
totaled 174 million shares at a cost of $11.8 billion through September 30, 2011. We had cash and
cash equivalents of $3.4 billion and short-term
44
investments of $2.6 billion at September 30, 2011. A portion of those balances is expected to be
used toward the completion of the repurchase program in the fourth quarter of 2011.
Capital Spending
Capital Expenditures and Investments
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
Nine Months Ended |
|
|
|
September 30 |
|
|
|
2011 |
|
|
2010 |
|
E&P |
|
|
|
|
|
|
|
|
United StatesAlaska |
|
$ |
585 |
|
|
|
544 |
|
United StatesLower 48 |
|
|
2,781 |
|
|
|
1,041 |
|
International |
|
|
5,266 |
|
|
|
4,022 |
|
|
|
|
|
8,632 |
|
|
|
5,607 |
|
|
Midstream |
|
|
9 |
|
|
|
1 |
|
|
R&M |
|
|
|
|
|
|
|
|
United States |
|
|
500 |
|
|
|
479 |
|
International |
|
|
128 |
|
|
|
180 |
|
|
|
|
|
628 |
|
|
|
659 |
|
|
LUKOIL Investment |
|
|
- |
|
|
|
- |
|
Chemicals |
|
|
- |
|
|
|
- |
|
Emerging Businesses |
|
|
21 |
|
|
|
7 |
|
Corporate and Other |
|
|
104 |
|
|
|
97 |
|
|
|
|
$ |
9,394 |
|
|
|
6,371 |
|
|
United States |
|
$ |
3,990 |
|
|
|
2,162 |
|
International |
|
|
5,404 |
|
|
|
4,209 |
|
|
|
|
$ |
9,394 |
|
|
|
6,371 |
|
|
E&P
Capital spending for E&P during the first nine months of 2011 totaled $8.6 billion. The
expenditures supported key exploration and development projects including:
|
|
|
Oil and natural gas exploration and development activities in the Lower 48, including
the Eagle Ford, Bakken and North Barnett shale plays, as well as the Permian and San Juan
Basins. Exploration leasing and drilling activities occurred in a number of different
shale plays. |
|
|
|
|
Alaska development activities related to existing producing fields. |
|
|
|
|
Oil sands projects and ongoing natural gas projects in Canada. |
|
|
|
|
Further development of coalbed methane projects associated with the APLNG joint venture
in Australia. |
|
|
|
|
In Asia Pacific, continued development in China, new fields offshore Malaysia and
ongoing exploration and development activity offshore Indonesia. |
|
|
|
|
In the North Sea, development activities in the Greater Ekofisk area, Jasmine and Clair
Ridge, as well as exploration drilling activities. |
|
|
|
|
The Kashagan Field in the Caspian Sea. |
|
|
|
|
Onshore developments in Nigeria and Algeria. |
R&M
Capital spending for R&M during the first nine months of 2011 totaled $628 million and included
projects related to sustaining and improving the existing business with a focus on safety,
regulatory compliance and reliability.
45
Contingencies
A number of lawsuits involving a variety of claims have been made against ConocoPhillips that arise
in the ordinary course of business. We also may be required to remove or mitigate the effects on
the environment of the placement, storage, disposal or release of certain chemical, mineral and
petroleum substances at various active and inactive sites. We regularly assess the need for
accounting recognition or disclosure of these contingencies. In the case of all known
contingencies (other than those related to income taxes), we accrue a liability when the loss is
probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated
and no amount within the range is a better estimate than any other amount, then the minimum of the
range is accrued. We do not reduce these liabilities for potential insurance or third-party
recoveries. If applicable, we accrue receivables for probable insurance or other third-party
recoveries. In the case of income-tax-related contingencies, we use a cumulative
probability-weighted loss accrual in cases where sustaining a tax position is less than certain.
Based on currently available information, we believe it is remote that future costs related to
known contingent liability exposures will exceed current accruals by an amount that would have a
material adverse impact on our consolidated financial statements. As we learn new facts concerning
contingencies, we reassess our position both with respect to accrued liabilities and other
potential exposures. Estimates particularly sensitive to future changes include contingent
liabilities recorded for environmental remediation, tax and legal matters. Estimated future
environmental remediation costs are subject to change due to such factors as the uncertain
magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be
required, and the determination of our liability in proportion to that of other responsible
parties. Estimated future costs related to tax and legal matters are subject to change as events
evolve and as additional information becomes available during the administrative and litigation
processes.
Legal Matters
Our legal organization applies its knowledge, experience and professional judgment to the specific
characteristics of our cases, employing a litigation management process to manage and monitor the
legal proceedings against us. Our process facilitates the early evaluation and quantification of
potential exposures in individual cases. This process also enables us to track those cases that
have been scheduled for trial and/or mediation. Based on professional judgment and experience in
using these litigation management tools and available information about current developments in all
our cases, our legal organization regularly assesses the adequacy of current accruals and
determines if adjustment of existing accruals, or establishment of new accruals, is required.
Environmental
We are subject to the same numerous international, federal, state and local environmental laws and
regulations as other companies in our industry. For a discussion of the most significant of these
environmental laws and regulations, including those with associated remediation obligations, see
the Environmental section in Managements Discussion and Analysis of Financial Condition and
Results of Operations on pages 57, 58 and 59 of our 2010 Annual Report on Form 10-K.
We occasionally receive requests for information or notices of potential liability from the
Environmental Protection Agency (EPA) and state environmental agencies alleging we are a
potentially responsible party under the Federal Comprehensive Environmental Response, Compensation
and Liability Act (CERCLA) or an equivalent state statute. On occasion, we also have been made a
party to cost recovery litigation by those agencies or by private parties. These requests, notices
and lawsuits assert potential liability for remediation costs at various sites that typically are
not owned by us, but allegedly contain wastes attributable to our past operations. As of December
31, 2010, we reported we had been notified of potential liability under CERCLA and comparable state
laws at 73 sites around the United States. As of September 30, 2011, we were notified of six new
sites, settled five sites and closed two sites, resulting in 72 unresolved sites with potential
liability.
At September 30, 2011, our balance sheet included a total environmental accrual of $926 million,
compared with $994 million at December 31, 2010. We expect to incur a substantial amount of these
expenditures within the next 30 years.
46
Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses,
environmental costs and liabilities are inherent concerns in our operations and products, and there
can be no assurance that material costs and liabilities will not be incurred. However, we
currently do not expect any material adverse effect on our results of operations or financial
position as a result of compliance with current environmental laws and regulations.
Climate Change
There has been a broad range of proposed or promulgated state, national and international laws
focusing on greenhouse gas (GHG) reduction. These proposed or promulgated laws apply or could
apply in countries where we have interests or may have interests in the future. Laws in this field
continue to evolve, and while it is not possible to accurately estimate either a timetable for
implementation or our future compliance costs relating to implementation, such laws, if enacted,
could have a material impact on our results of operations and financial condition. Examples of
legislation and precursors for possible regulation that do or could affect our operations include
the EPAs announcement (published as Interpretation of Regulations that Determine Pollutants
Covered by Clean Air Act Permitting Programs, 75 Fed. Reg. 17004 (April 2, 2010)), and the EPAs
and U.S. Department of Transportations joint promulgation of a Final Rule on April 1, 2010, that
triggers regulation of GHGs under the Clean Air Act, may trigger more climate-based claims for
damages, and may result in longer agency review time for development projects to determine the
extent of climate change. Both of the above-referenced announcements are subject to pending legal
challenges, and we continue to monitor these legal proceedings and other legislative and regulatory
actions globally for potential impacts on our operations.
For other examples of legislation or precursors for possible regulation that do or could affect our
operations, see the Climate Change section in Managements Discussion and Analysis of Financial
Condition and Results of Operations on pages 59 and 60 of our 2010 Annual Report on Form 10-K.
NEW ACCOUNTING STANDARDS
In June 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update
(ASU) 2011-5, Comprehensive Income. This ASU amends FASB Accounting Standards Codification Topic
220, Comprehensive Income, and requires the presentation of comprehensive income, the components
of net income, and the components of other comprehensive income either in a single continuous
statement of comprehensive income or in two separate but consecutive statements. This ASU is
effective for fiscal years, and interim periods within those years, beginning after December 15,
2011, with early adoption permitted. We currently plan to use the two consecutive statement
approach upon adoption of this ASU.
In September 2011, the FASB issued ASU 2011-8, Intangibles Goodwill and Other. This ASU
provides for the option to first assess qualitative factors to determine whether it is more likely
than not that the fair value of a reporting unit is less than its carrying amount. If the
assessment of qualitative factors determines it is more likely than not the carrying value of a
reporting unit is less than fair value, performing the two-step goodwill impairment analysis would
not be necessary. This ASU is effective for fiscal years, and interim periods within those years,
beginning after December 15, 2011, with early adoption permitted. We are currently evaluating the
impact of this ASU.
47
OUTLOOK
Planned Separation of Downstream Businesses
On July 14, 2011, we announced approval by our Board of Directors to pursue the separation of our
refining, marketing and transportation business into a stand-alone, publicly traded corporation via
a tax-free distribution. We expect the new downstream company will also include most of our
Midstream segment, our Chemicals segment, as well as our power generation and certain technology
operations, to create an integrated downstream company. The separation would be accomplished by
the pro rata distribution of one share of the new downstream companys stock for every two shares
of ConocoPhillips stock held by ConocoPhillips shareholders on the record date.
During October, we requested a private letter ruling from the U.S. Internal Revenue Service, which
is expected to confirm the distribution will qualify as a tax-free reorganization for U.S. federal
income tax purposes. In addition, we plan to file the new downstream companys initial Form 10
registration statement with the SEC in mid-November.
The separation is subject to market conditions, customary regulatory approvals, the receipt of an
affirmative Internal Revenue Service private letter ruling, execution of separation and
intercompany agreements and final Board approval, and is expected to be completed in the second
quarter of 2012.
Trainer Refinery
On September 27, 2011, we announced our intention to sell our 185,000 barrel-per-day refinery in
Trainer, Pennsylvania, along with the associated pipelines and terminals. We have idled the
facility and plan to permanently close the plant by the end of the first quarter of 2012 if a sales
transaction is unsuccessful.
China Bohai Bay Temporary Shut-in
On July 13, 2011, the State Oceanic Administration (SOA) in the Peoples Republic of China
instructed us to suspend production from Peng Lai Platforms B and C, as a result of two separate
seepage incidents which occurred near the platforms. On September 2, 2011, the SOA ordered us to
halt operations at the Peng Lai 19-3 Field, pending additional cleanup efforts and activities to
ensure any residual seepage has stopped. The SOA also requires implementation of preventative
measures to avoid recurrence, in addition to the filing of an updated environmental impact
assessment and development plan for approval. The incidents resulted in a total release of
approximately 700 barrels of oil into Bohai Bay and approximately 2,600 barrels of mineral
oil-based drilling mud onto the seafloor. The mineral oil-based drilling mud was recovered and
cleaned up from the seafloor. The sources of the seeps have been sealed and containment devices
deployed as a preventative measure to capture any residue. The shut-down, combined with limited development and field
optimization, is expected to reduce fourth quarter production from the field by approximately
40,000 net barrels of oil per day, compared to 2010 production levels. Future impacts on our
business are not known at this time.
Libya
Our production operations in Libya and related oil exports continue to be temporarily suspended,
although certain international sanctions have been lifted. We hold a 16.3 percent interest in the
Waha concessions. For the year 2010, our net oil production averaged 46,000 barrels per day, and
cash flow from operations was approximately $125 million. Future impacts are unknown at this time.
E&P Production
In E&P, we expect our 2011 production to be 1.61 million to 1.62 million BOE per day. Production
in the fourth quarter of 2011 is expected to be 1.56 million to 1.58 million BOE per day.
48
CAUTIONARY STATEMENT FOR THE PURPOSES OF THE SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995
This report 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, estimate, believe, budget, continue,
could, intend, may, plan, potential, predict, seek, should, will, would,
expect, objective, projection, forecast, goal, guidance, outlook, effort, target
and similar expressions.
We based the forward-looking statements on our current expectations, estimates and projections
about ourselves and the industries in which we operate in general. We caution you these statements
are not guarantees of future performance as they involve assumptions that, while made in good
faith, may prove to be incorrect, and involve risks and uncertainties 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 outcomes and results may differ materially
from what we have expressed or forecast in the forward-looking statements. Any differences could
result from a variety of factors, including the following:
|
|
|
Fluctuations in crude oil, bitumen, natural gas, LNG and natural gas liquids prices,
refining and marketing margins and margins for our chemicals business. |
|
|
|
|
Potential failures or delays in achieving expected reserve or production levels from
existing and future oil and gas development projects due to operating hazards, drilling
risks and the inherent uncertainties in predicting reserves and reservoir performance. |
|
|
|
|
Unsuccessful exploratory drilling activities or the inability to obtain access to
exploratory acreage. |
|
|
|
|
Failure of new products and services to achieve market acceptance. |
|
|
|
|
Unexpected changes in costs or technical requirements for constructing, modifying or
operating facilities for exploration and production, manufacturing, refining or
transportation projects. |
|
|
|
|
Unexpected technological or commercial difficulties in manufacturing, refining or
transporting our products, including chemicals products. |
|
|
|
|
Lack of, or disruptions in, adequate and reliable transportation for our crude oil,
natural gas, natural gas liquids, bitumen, LNG and refined products. |
|
|
|
|
Inability to timely obtain or maintain permits, including those necessary for
construction of LNG terminals or regasification facilities, or refinery projects; comply
with government regulations; or make capital expenditures required to maintain compliance. |
|
|
|
|
Failure to complete definitive agreements and feasibility studies for, and to timely
complete construction of, announced and future exploration and production, LNG, refinery
and transportation projects. |
|
|
|
|
Potential disruption or interruption of our operations due to accidents, extraordinary
weather events, civil unrest, political events, terrorism or cyber attacks. |
|
|
|
|
International monetary conditions and exchange controls. |
|
|
|
|
Substantial investment or reduced demand for products as a result of existing or future
environmental rules and regulations. |
|
|
|
|
Liability for remedial actions, including removal and reclamation obligations, under
environmental regulations. |
|
|
|
|
Liability resulting from litigation. |
|
|
|
|
General domestic and international economic and political developments, including armed
hostilities; expropriation of assets; changes in governmental policies relating to crude
oil, bitumen, natural gas, LNG, natural gas liquids or refined product pricing, regulation
or taxation; other political, economic or diplomatic developments; and international
monetary fluctuations. |
49
|
|
|
Changes in tax and other laws, regulations (including alternative energy mandates), or
royalty rules applicable to our business. |
|
|
|
|
Limited access to capital or significantly higher cost of capital related to illiquidity
or uncertainty in the domestic or international financial markets. |
|
|
|
|
Delays in, or our inability to implement, our asset disposition plan. |
|
|
|
|
Inability to obtain economical financing for projects, construction or modification of
facilities and general corporate purposes. |
|
|
|
|
The operation and financing of our midstream and chemicals joint ventures. |
|
|
|
|
The effect of restructuring or reorganization of business components. |
|
|
|
|
The factors generally described in Item 1ARisk Factors in our 2010 Annual Report on
Form 10-K and Item 1A-Risk Factors in this Quarterly Report on Form 10-Q. |
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information about market risks for the nine months ended September 30, 2011, does not differ
materially from that discussed under Item 7A in our 2010 Annual Report on Form 10-K.
Item 4. CONTROLS AND PROCEDURES
As of September 30, 2011, with the participation of our management, our Chairman and Chief
Executive Officer (principal executive officer) and our Senior Vice President, Finance and Chief
Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule
13a-15(b) of the Securities Exchange Act of 1934, as amended (the Act), of ConocoPhillips
disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that
evaluation, our Chairman and Chief Executive Officer and our Senior Vice President, Finance and
Chief Financial Officer concluded that our disclosure controls and procedures were operating
effectively as of September 30, 2011.
There have been no changes in our internal control over financial reporting, as defined in Rule
13a-15(f) of the Act, in the period covered by this report that have materially affected, or are
reasonably likely to materially affect, our internal control over financial reporting.
50
PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
The following is a description of reportable legal proceedings including those involving
governmental authorities under federal, state and local laws regulating the discharge of materials
into the environment for this reporting period. The following proceedings include material
developments with respect to matters previously reported in ConocoPhillips 2010 Annual Report on
Form 10-K or first- or second-quarter 2011 Quarterly Report on Form 10-Q. We did not have any new
matters that arose during the third quarter of 2011 to report. While it is not possible to
accurately predict the final outcome of these pending proceedings, if any one or more of such
proceedings was decided adversely to ConocoPhillips, we expect there would be no material effect on
our consolidated financial position. Nevertheless, such proceedings are reported pursuant to the
U.S. Securities and Exchange Commissions (SEC) regulations.
Our U.S. refineries are implementing two separate consent decrees regarding alleged violations of
the Federal Clean Air Act with the U.S. Environmental Protection Agency (EPA), six states and one
local air pollution agency. Some of the requirements and limitations contained in the decrees
provide for stipulated penalties for violations. Stipulated penalties under the decrees are not
automatic, but must be requested by one of the agency signatories. As part of periodic reports
under the decrees or other reports required by permits or regulations, we occasionally report
matters that could be subject to a request for stipulated penalties. If a specific request for
stipulated penalties meeting the reporting threshold set forth in SEC rules is made pursuant to
these decrees based on a given reported exceedance, we will separately report that matter and the
amount of the proposed penalty.
Matters Previously Reported
In February 2011, we reported to the EPA two instances of potential non-compliance with federal air
regulations at the companys Ute Compressor Station in Southwest Colorado. This matter was
resolved with a penalty payment of $198,000.
51
Item 1A. RISK FACTORS
You should carefully consider the following risk factor, in addition to the risk factors disclosed
in Item 1A of our 2010 Annual Report on Form 10-K.
The proposed separation of our downstream businesses is contingent upon the satisfaction of a
number of conditions, which may not be consummated on the terms or timeline currently contemplated
or may not achieve the intended results.
We expect the separation will be effective in the second quarter of 2012. Our ability to timely
effect the separation is subject to several conditions, including, among others, the receipt of a
favorable private letter ruling from the IRS, an independent tax opinion that the separation will
qualify as tax-free for U.S. federal income tax purposes, and the SEC declaring effective a
registration statement relating to the securities of the separated entity. We cannot assure that
we will be able to complete the separation in a timely fashion, if at all. For these and other
reasons, the separation may not be completed on the terms or timeline contemplated. Further, if
the separation is completed, it may not achieve the intended results. Any such difficulties could
adversely affect our business, results of operations or financial condition.
There have been no other material changes from the risk factors disclosed in Item 1A of our 2010
Annual Report on Form 10-K.
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Issuer Purchases of Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars |
|
|
|
|
|
|
|
|
|
|
|
Total Number of |
|
|
Approximate Dollar |
|
|
|
|
|
|
|
|
|
|
|
Shares Purchased |
|
|
Value of Shares |
|
|
|
|
|
|
|
|
|
|
|
as Part of Publicly |
|
|
that May Yet Be |
|
|
|
Total Number of |
|
|
Average Price Paid |
|
|
Announced Plans |
|
|
Purchased Under the |
|
Period |
|
Shares Purchased* |
|
|
per Share |
|
|
or Programs** |
|
|
Plans or Programs |
|
|
July 1-31, 2011 |
|
|
13,272,242 |
|
|
$ |
75.30 |
|
|
|
13,271,248 |
|
|
$ |
5,350 |
|
August 1-31, 2011 |
|
|
17,170,822 |
|
|
|
66.96 |
|
|
|
17,168,893 |
|
|
|
4,200 |
|
September 1-30, 2011 |
|
|
15,976,999 |
|
|
|
65.71 |
|
|
|
15,976,550 |
|
|
|
3,150 |
|
|
Total |
|
|
46,420,063 |
|
|
$ |
68.92 |
|
|
|
46,416,691 |
|
|
|
|
|
|
*
Includes the repurchase of common shares from company employees in connection with the companys broad-based employee incentive plans.
** On March 24, 2010, we announced plans to repurchase up to $5 billion of our common stock through 2011. Repurchase of shares under this authorization was completed during
the first quarter of 2011. On February 11, 2011, we announced plans to repurchase up to $10 billion of our common stock over the subsequent two years. Acquisitions for the
share repurchase program are made at managements discretion, at prevailing prices, subject to market conditions and other factors. Repurchases may be increased, decreased or
discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares.
52
Item 6. EXHIBITS
|
|
|
12*
|
|
Computation of Ratio of Earnings to Fixed Charges. |
|
|
|
31.1*
|
|
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934. |
|
|
|
31.2*
|
|
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934. |
|
|
|
32*
|
|
Certifications pursuant to 18 U.S.C. Section 1350. |
|
|
|
101.INS*
|
|
XBRL Instance Document. |
|
|
|
101.SCH*
|
|
XBRL Schema Document. |
|
|
|
101.CAL*
|
|
XBRL Calculation Linkbase Document. |
|
|
|
101.LAB*
|
|
XBRL Labels Linkbase Document. |
|
|
|
101.PRE*
|
|
XBRL Presentation Linkbase Document. |
|
|
|
101.DEF*
|
|
XBRL Definition Linkbase Document. |
53
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.
|
|
|
|
|
|
|
CONOCOPHILLIPS
|
|
|
|
|
|
|
|
|
|
/s/ Glenda M. Schwarz |
|
|
|
|
|
|
|
|
|
Glenda M. Schwarz |
|
|
|
|
Vice President and Controller |
|
|
|
|
(Chief Accounting and Duly Authorized Officer) |
|
|
November 1, 2011
54