e10vq
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
             
[X]   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
   
 
           
For the quarterly period ended             September 30, 2008  
 
     
 
   
                                      or
   
 
           
[  ]   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)
     
Delaware   01-0562944
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)
600 North Dairy Ashford, Houston, TX 77079
(Address of principal executive offices)          (Zip Code)
281-293-1000
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes   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.
Large accelerated filer [X]   Accelerated filer [ ]   Non-accelerated filer [ ]   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 1,490,817,631 shares of common stock, $.01 par value, outstanding at September 30, 2008.
 
 

 


 

CONOCOPHILLIPS
TABLE OF CONTENTS
         
    Page
       
 
       
       
    1  
    2  
    3  
    4  
    24  
 
       
    33  
 
       
    55  
 
       
    55  
 
       
       
 
       
    56  
 
       
    57  
 
       
    58  
 
       
    59  
 
       
    59  
 
       
    60  
 EX-12
 EX-31.1
 EX-31.2
 EX-32

 


Table of Contents

PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
     
 
Consolidated Income Statement   ConocoPhillips
                                 
    Millions of Dollars  
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2008     2007     2008     2007  
Revenues and Other Income
                               
Sales and other operating revenues*
  $ 70,044       46,062       196,338       134,752  
Equity in earnings of affiliates
    1,214       1,314       4,385       3,749  
Other income
    115       557       555       1,696  
   
Total Revenues and Other Income
    71,373       47,933       201,278       140,197  
   
 
                               
Costs and Expenses
                               
Purchased crude oil, natural gas and products
    49,608       30,862       138,642       88,397  
Production and operating expenses
    3,059       2,620       8,861       7,669  
Selling, general and administrative expenses
    513       569       1,668       1,700  
Exploration expenses
    267       218       864       739  
Depreciation, depletion and amortization
    2,361       2,052       6,748       6,092  
Impairment—expropriated assets
    -       -       -       4,588  
Impairments
    57       188       82       285  
Taxes other than income taxes*
    5,619       4,583       16,570       13,654  
Accretion on discounted liabilities
    114       81       314       241  
Interest and debt expense
    239       391       656       1,017  
Foreign currency transaction losses (gains)
    54       (20 )     11       (198 )
Minority interests
    15       25       51       65  
   
Total Costs and Expenses
    61,906       41,569       174,467       124,249  
   
Income before income taxes
    9,467       6,364       26,811       15,948  
Provision for income taxes
    4,279       2,691       12,045       8,428  
   
Net Income
  $ 5,188       3,673       14,766       7,520  
   
 
                               
Net Income Per Share of Common Stock (dollars)
                               
Basic
  $ 3.43       2.26       9.61       4.60  
Diluted
    3.39       2.23       9.50       4.54  
   
 
                               
Dividends Paid Per Share of Common Stock (dollars)
  $ .47       .41       1.41       1.23  
   
 
                               
Average Common Shares Outstanding (in thousands)
                               
Basic
    1,510,897       1,622,456       1,535,932       1,635,128  
Diluted
    1,528,187       1,644,267       1,554,952       1,657,244  
   
*Includes excise taxes on petroleum products sales:
  $ 4,022       3,954       11,970       11,864  
See Notes to Consolidated Financial Statements.

1


Table of Contents

     
 
Consolidated Balance Sheet   ConocoPhillips
                 
    Millions of Dollars  
    September 30     December 31  
    2008     2007  
Assets
               
Cash and cash equivalents
  $ 1,116       1,456  
Accounts and notes receivable (net of allowance of $83 million in 2008 and $58 million in 2007)
    14,514       14,687  
Accounts and notes receivable—related parties
    2,472       1,667  
Inventories
    6,741       4,223  
Prepaid expenses and other current assets
    3,483       2,702  
   
Total Current Assets
    28,326       24,735  
Investments and long-term receivables
    34,344       31,457  
Loans and advances—related parties
    2,053       1,871  
Net properties, plants and equipment
    89,259       89,003  
Goodwill
    29,224       29,336  
Intangibles
    861       896  
Other assets
    540       459  
   
Total Assets
  $ 184,607       177,757  
   
 
               
Liabilities
               
Accounts payable
  $ 17,364       16,591  
Accounts payable—related parties
    1,873       1,270  
Short-term debt
    387       1,398  
Accrued income and other taxes
    6,369       4,814  
Employee benefit obligations
    758       920  
Other accruals
    2,759       1,889  
   
Total Current Liabilities
    29,510       26,882  
Long-term debt
    21,713       20,289  
Asset retirement obligations and accrued environmental costs
    7,713       7,261  
Joint venture acquisition obligation—related party
    5,828       6,294  
Deferred income taxes
    20,408       21,018  
Employee benefit obligations
    2,813       3,191  
Other liabilities and deferred credits
    2,619       2,666  
   
Total Liabilities
    90,604       87,601  
   
 
               
Minority Interests
    1,127       1,173  
   
 
               
Common Stockholders’ Equity
               
Common stock (2,500,000,000 shares authorized at $.01 par value)
               
Issued (2008—1,728,185,223 shares; 2007—1,718,448,829 shares)
               
Par value
    17       17  
Capital in excess of par
    43,308       42,724  
Grantor trusts (at cost: 2008—41,599,027 shares; 2007—42,411,331 shares)
    (716 )     (731 )
Treasury stock (at cost: 2008—195,768,565 shares; 2007—104,607,149 shares)
    (15,469 )     (7,969 )
Accumulated other comprehensive income
    2,742       4,560  
Unearned employee compensation
    (109 )     (128 )
Retained earnings
    63,103       50,510  
   
Total Common Stockholders’ Equity
    92,876       88,983  
   
Total
  $ 184,607       177,757  
   
See Notes to Consolidated Financial Statements.

2


Table of Contents

     
 
Consolidated Statement of Cash Flows   ConocoPhillips
                 
    Millions of Dollars  
    Nine Months Ended  
    September 30  
    2008     2007  
Cash Flows From Operating Activities
               
Net income
  $ 14,766       7,520  
Adjustments to reconcile net income to net cash provided by operating activities
               
Depreciation, depletion and amortization
    6,748       6,092  
Impairment—expropriated assets
    -       4,588  
Impairments
    82       285  
Dry hole costs and leasehold impairments
    399       355  
Accretion on discounted liabilities
    314       241  
Deferred taxes
    59       55  
Undistributed equity earnings
    (2,530 )     (1,472 )
Gain on asset dispositions
    (346 )     (1,316 )
Other
    (134 )     28  
Working capital adjustments*
               
Decrease (increase) in accounts and notes receivable
    (243 )     411  
Increase in inventories
    (2,709 )     (334 )
Decrease (increase) in prepaid expenses and other current assets
    (689 )     430  
Increase in accounts payable
    1,633       1,052  
Increase (decrease) in taxes and other accruals
    2,186       (305 )
   
Net Cash Provided by Operating Activities
    19,536       17,630  
   
 
               
Cash Flows From Investing Activities
               
Capital expenditures and investments
    (10,535 )     (7,907 )
Proceeds from asset dispositions
    729       3,057  
Long-term advances/loans—related parties
    (181 )     (449 )
Collection of advances/loans—related parties
    15       66  
Other
    (186 )     24  
   
Net Cash Used in Investing Activities
    (10,158 )     (5,209 )
   
 
               
Cash Flows From Financing Activities
               
Issuance of debt
    2,264       824  
Repayment of debt
    (1,857 )     (6,141 )
Issuance of company common stock
    182       251  
Repurchase of company common stock
    (7,500 )     (4,501 )
Dividends paid on company common stock
    (2,159 )     (2,009 )
Other
    (426 )     (289 )
   
Net Cash Used in Financing Activities
    (9,496 )     (11,865 )
   
 
               
Effect of Exchange Rate Changes on Cash and Cash Equivalents
    (222 )     6  
   
 
               
Net Change in Cash and Cash Equivalents
    (340 )     562  
Cash and cash equivalents at beginning of period
    1,456       817  
   
Cash and Cash Equivalents at End of Period
  $ 1,116       1,379  
   
*Net of acquisition and disposition of businesses.
See Notes to Consolidated Financial Statements.

3


Table of Contents

     
 
Notes to Consolidated Financial Statements   ConocoPhillips
Note 1—Interim 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 2007 Annual Report on Form 10-K.
Note 2—Changes in Accounting Principles
SFAS No. 157
Effective January 1, 2008, we implemented Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for its measurement and expands disclosures about fair value measurements. We elected to implement this Statement with the one-year deferral permitted by FASB Staff Position (FSP) 157-2 for nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis (at least annually). The deferral applies to nonfinancial assets and liabilities measured at fair value in a business combination; impaired properties, plants and equipment; intangible assets and goodwill; and initial recognition of asset retirement obligations and restructuring costs for which we use fair value. We do not expect any significant impact to our consolidated financial statements when we implement SFAS No. 157 for these assets and liabilities.
Due to our election under FSP 157-2, for 2008, SFAS No. 157 applies to commodity and foreign currency derivative contracts and certain nonqualified deferred compensation and retirement plan assets that are measured at fair value on a recurring basis in periods subsequent to initial recognition. The implementation of SFAS No. 157 did not cause a change in the method of calculating fair value of assets or liabilities, with the exception of incorporating the impact of our nonperformance risk on derivative liabilities—which was not material. The primary impact from adoption was additional disclosures.
SFAS No. 157 requires disclosures that categorize assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or our assumptions about pricing by market participants.
We value our exchange-cleared derivatives using unadjusted closing prices provided by the exchange as of the balance sheet date, and these are classified as Level 1 in the fair value hierarchy. Over the counter (OTC) financial swaps and physical commodity purchase and sale contracts are generally valued using quotations provided by brokers and price index developers such as Platts and Oil Price Information Service. These 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 sale contracts are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3.
Exchange-cleared financial options are valued using exchange closing prices and are classified as 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

4


Table of Contents

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 option is classified as Level 2 or 3.
As permitted under SFAS No. 157, we use a mid-market pricing convention (the mid-point price 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 financial assets and liabilities accounted for at fair value on a recurring basis at September 30, 2008, was:
                                 
    Millions of Dollars  
    Level 1     Level 2     Level 3     Total  
Assets
                               
Commodity derivatives
  $ 5,868       2,874       20       8,762  
Foreign exchange derivatives
    -       101       -       101  
Nonqualified benefit plans
    365       -       -       365  
   
Total assets
    6,233       2,975       20       9,228  
   
 
                               
Liabilities
                               
Commodity derivatives
    (5,628 )     (2,670 )     (8 )     (8,306 )
Foreign exchange derivatives
    -       (182 )     -       (182 )
   
Total liabilities
    (5,628 )     (2,852 )     (8 )     (8,488 )
   
Net assets
  $ 605       123       12       740  
   
The derivative values above are based on analysis of each contract as the fundamental unit of account as required by SFAS No. 157; therefore, derivative assets and liabilities with the same counterparty are not netted where the legal right of offset exists, which is different than the net presentation basis in Note 13—Financial Instruments and Derivative Contracts. 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.

5


Table of Contents

Changes in the fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy during the three- and nine-month periods ended September 30, 2008, were:
                 
    Millions of Dollars  
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
               
Beginning balance
  $ (56 )     (34 )
Total gains (losses), realized and unrealized
               
Included in earnings
    45       (8 )
Included in other comprehensive income
    -       -  
Purchases, issuances and settlements
    20       44  
Transfers in and/or out of Level 3
    3       10  
   
Balance at September 30, 2008
  $ 12       12  
   
The amount of total gains (losses) for the three- and nine-month periods included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at September 30, 2008, were:
                 
    Millions of Dollars  
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
Related to assets
  $ 16       8  
Related to liabilities
    (16 )     (9 )
   
Gains and losses, realized and unrealized, included in earnings for the three- and nine-month periods ended September 30, 2008, were:
                                                 
    Millions of Dollars  
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
            Purchased                     Purchased        
    Other     Crude Oil,             Other     Crude Oil,        
    Operating     Natural Gas             Operating     Natural Gas        
    Revenues     and Products     Total     Revenues     and Products     Total  
Total gains (losses) included in earnings
  $ 55       (10 )     45       (3 )     (5 )     (8 )
   
 
                                               
Change in unrealized gains (losses) relating to assets held at September 30, 2008
  $ 16       -       16       8       -       8  
   
 
                                               
Change in unrealized gains (losses) relating to liabilities held at September 30, 2008
  $ (9 )     (7 )     (16 )     (4 )     (5 )     (9 )
   

6


Table of Contents

SFAS No. 159
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115.” This Statement permits the election to carry financial instruments and certain other items similar to financial instruments at fair value on the balance sheet, with all changes in fair value reported in earnings. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair value hedge without having to comply with complex hedge accounting rules. We adopted this Statement effective January 1, 2008, but did not make a fair value election at that time or during the first nine months of 2008 for any financial instruments not already carried at fair value in accordance with other accounting standards. Accordingly, the adoption of SFAS No. 159 did not impact our consolidated financial statements.
Note 3—Variable Interest Entities (VIEs)
We have a 24 percent interest in West2East Pipeline LLC (West2East), a company holding a 100 percent interest in Rockies Express Pipeline LLC (Rockies Express). West2East is a VIE, but we are not the primary beneficiary. We use the equity method of accounting for our investment. In 2007, we issued a guarantee for 24 percent of the $2 billion in credit facilities of Rockies Express. In addition, we have a guarantee for 24 percent of $600 million of Floating Rate Notes due 2009 issued by Rockies Express. At September 30, 2008, the book value of our investment in West2East was $246 million. See Note 11—Guarantees, for additional information.
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 related party, OAO LUKOIL, have disproportionate interests. We are not the primary beneficiary of the VIE and we use the equity method of accounting for this investment. At September 30, 2008, the book value of our investment in the venture was $1,995 million.
Note 4—Inventories
Inventories consisted of the following:
                 
    Millions of Dollars  
    September 30     December 31  
    2008     2007  
                 
Crude oil and petroleum products
  $ 5,827       3,373  
Materials, supplies and other
    914       850  
   
 
  $ 6,741       4,223  
   
Inventories valued on the last-in, first-out (LIFO) basis totaled $5,497 million and $2,974 million at September 30, 2008, and December 31, 2007, respectively. The remaining inventories were valued under various methods, including first-in, first-out and weighted average. The excess of current replacement cost over LIFO cost of inventories amounted to $7,022 million and $6,668 million at September 30, 2008, and December 31, 2007, respectively.

7


Table of Contents

Note 5—Assets Held for Sale
Noncurrent assets and noncurrent liabilities classified as current assets and current liabilities under the “held for sale” provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” totaled $1,092 million and $159 million, respectively, at December 31, 2007. During the first nine months of 2008, a portion of these held-for-sale assets were sold, and additional assets met the held-for-sale criteria. As a result, at September 30, 2008, we classified $1,039 million of noncurrent assets as “Prepaid expenses and other current assets” on our consolidated balance sheet and we classified $272 million of noncurrent liabilities as current liabilities, consisting of $145 million in “Accrued income and other taxes” and $127 million in “Other accruals.” Contingent upon necessary regulatory approvals and negotiation of final contract terms, we expect the majority of these assets to be sold by the end of 2008, with the remainder to be sold in 2009.
The major classes of noncurrent assets and noncurrent liabilities held for sale and classified as current were:
                 
    Millions of Dollars  
    September 30     December 31  
    2008     2007  
Assets
               
Investments and long-term receivables
  $ 7       48  
Net properties, plants and equipment
    865       946  
Goodwill
    164       89  
Intangibles
    2       2  
Other assets
    1       7  
   
Total assets
  $ 1,039       1,092  
   
Exploration and Production
  $ 283       189  
Refining and Marketing
    756       903  
   
 
  $ 1,039       1,092  
   
 
               
Liabilities
               
Asset retirement obligations and accrued environmental costs
  $ 120       23  
Deferred income taxes
    145       133  
Other liabilities and deferred credits
    7       3  
   
Total liabilities
  $ 272       159  
   
Exploration and Production
  $ 158       35  
Refining and Marketing
    114       124  
   
 
  $ 272       159  
   

8


Table of Contents

Note 6—Investments, Loans and Long-Term Receivables
LUKOIL
Our ownership interest in LUKOIL was 20 percent at September 30, 2008, based on 851 million shares authorized and issued. For financial reporting under U.S. generally accepted accounting principles, treasury shares held by LUKOIL are not considered outstanding for determining our equity-method ownership interest in LUKOIL. Our ownership interest, based on estimated shares outstanding, was also 20 percent at September 30, 2008, compared with 20.6 percent at December 31, 2007.
At September 30, 2008, the book value of our ordinary share investment in LUKOIL was $12,864 million. Our share of the net assets of LUKOIL was estimated to be $10,393 million. The majority of this basis difference of $2,471 million is being amortized on a unit-of-production basis.
At September 30, 2008, the closing price of LUKOIL shares (ADRs) on the London Stock Exchange was $58.80 per share, down $39.80 per share, or 40 percent, from June 30, 2008. The aggregate market value of our LUKOIL investment at September 30 was, therefore, $10,003 million, or $2,861 million below the $12,864 million book value of our LUKOIL investment. Book value includes $7.5 billion of share acquisition costs, along with undistributed equity earnings and basis difference amortization. We evaluated the decrease in market value below book value of our LUKOIL investment and concluded the decline did not meet the other-than-temporary impairment recognition guidance of Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” In reaching this conclusion, we considered: 1) the lack of deterioration in LUKOIL’s financial condition and near-term prospects during the quarter; 2) general oil and gas industry downward stock price trends during the quarter, as well as the historical volatility of oil and gas commodity prices, which often create short-term volatility in energy industry stock prices; 3) the intent and ability of ConocoPhillips to retain its investment in LUKOIL; 4) the short length of time book value has been less than market value; and 5) non-energy-related factors impacting the U.S. and Russian financial markets during the quarter.
At October 29, 2008, the closing price of LUKOIL shares on the London Stock Exchange was $33.01 per share, 44 percent lower than at September 30, 2008. We will continue to closely monitor the relationship between the carrying value and market value of our LUKOIL investment. Should we determine in the future there has been a loss in the carrying value of our investment that is other than temporary, we would record a noncash impairment of our investment, calculated as the total difference between carrying value and market value as of the end of the reporting period.
Loans to Related Parties
As part of our normal ongoing business operations and consistent with industry practice, we invest and 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. Included in such activity are loans made to certain affiliated companies. The long-term portion of these loans are included in the “Loans and advances—related parties” balance sheet line item, while the short-term portion is included in “Accounts and notes receivable—related parties.” Significant loans to affiliated companies at September 30, 2008, included the following:
    $768 million in loan financing to Freeport LNG Development, L.P. This loan was provided for the construction of a liquefied natural gas (LNG) facility which became operational late in the second quarter of 2008. The loan was converted from a construction loan to term loan in August 2008 and Freeport started making repayments in September 2008. At the time of the loan conversion in August, it consisted of $650 million of principal and $124 million of accrued interest.
 
    $330 million in loan financing and an additional $43 million of accrued interest to Varandey Terminal Company associated with the costs of a terminal expansion. The terminal construction was completed in late second-quarter 2008, and the final loan amount was $330 million at current exchange rates, excluding accrued interest. Although repayments are not required to start until May 2010, Varandey used available cash to repay $7 million of interest in third-quarter 2008.

9


Table of Contents

    $817 million of project financing and an additional $67 million of accrued interest to Qatargas 3, an integrated project to produce and liquefy natural gas from Qatar’s North field. Our maximum exposure to this financing structure is $1.2 billion.
 
    $197 million in short-term loan financing and an additional $1 million of accrued interest to TransCanada Keystone Pipeline LP, which is expected to be repaid before year end.
Note 7—Properties, Plants and Equipment
The company’s investment in properties, plants and equipment (PP&E), with accumulated depreciation, depletion and amortization (Accum. DD&A), was:
                                                 
    Millions of Dollars  
    September 30, 2008     December 31, 2007  
    Gross     Accum.     Net     Gross     Accum.     Net  
    PP&E     DD&A     PP&E     PP&E     DD&A     PP&E  
 
                                               
E&P
  $ 107,175       35,391       71,784       102,550       30,701       71,849  
Midstream
    115       68       47       267       103       164  
R&M
    20,792       5,217       15,575       19,926       4,733       15,193  
LUKOIL Investment
    -       -       -       -       -       -  
Chemicals
    -       -       -       -       -       -  
Emerging Businesses
    1,219       152       1,067       1,204       138       1,066  
Corporate and Other
    1,517       731       786       1,414       683       731  
   
 
  $ 130,818       41,559       89,259       125,361       36,358       89,003  
   
Suspended Wells
The company’s capitalized cost of suspended wells at September 30, 2008, was $685 million, an increase of $96 million from $589 million at year-end 2007. For the category of exploratory well costs capitalized for a period greater than one year as of December 31, 2007, $12 million was charged to dry hole expense during the first nine months of 2008.

10


Table of Contents

Note 8—Impairments
Expropriated Assets
In the second quarter of 2007, we recorded a noncash impairment, including allocable goodwill, of $4,588 million before-tax ($4,512 million after-tax) related to our investments in the Petrozuata and Hamaca heavy-oil ventures and the offshore Corocoro oil development project in Venezuela. See Note 13—Impairments, in our 2007 Annual Report on Form 10-K, for additional information.
Other Impairments
We recognized the following net impairments:
                                 
    Millions of Dollars  
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2008     2007     2008     2007  
E&P
                               
United States
  $ -       -       -       1  
International
    56       151       59       326  
R&M
                               
United States
    1       1       23       48  
International
    -       30       -       30  
Increase in fair value of previously impaired assets
    -       (2 )     -       (128 )
Corporate
    -       8       -       8  
   
 
  $ 57       188       82       285  
   
During the third quarter and nine-month period of 2008, property impairments were primarily associated with changes in asset retirement obligations for properties at the end of their economic life. In addition, the nine-month period also includes amounts related to planned asset dispositions.
During the third quarter and nine-month period of 2007, we recorded property impairments for:
    The write-down of held-for-sale assets to fair value, less cost to sell.
 
    Changes in asset retirement obligations for properties at the end of their economic life.
 
    The write-down of abandoned properties or projects.
In addition and in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the nine-month period of 2007 included a $128 million gain for the subsequent increase in the fair value of certain assets impaired in the prior year to reflect finalized sales agreements. This gain was netted with write-downs into the “Impairments” line of the consolidated income statement.
Note 9—Debt
In January 2008, we reduced our Floating Rate Five-Year Term Note due 2011 from $3 billion to $2 billion, with a subsequent reduction in June 2008 to $1.5 billion. In March 2008, we redeemed our $300 million 7.125% Debentures due 2028 at a premium of $8 million, plus accrued interest.
In May 2008, we issued notes consisting of $400 million of 4.40% Notes due 2013, $500 million of 5.20% Notes due 2018 and $600 million of 5.90% Notes due 2038. The proceeds from the offering were used to reduce commercial paper and for general corporate purposes.

11


Table of Contents

At September 30, 2008, we had a $7.35 billion revolving credit facility, which expires in September 2012. The facility was reduced from $7.5 billion due to the bankruptcy of Lehman Commercial Paper Inc., one of the revolver participants. The facility may be used as direct bank borrowings, as support for the ConocoPhillips $7.35 billion commercial paper program, as support for the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, or as support for issuances of letters of credit totaling up to $750 million. At September 30, 2008, and December 31, 2007, we had no outstanding borrowings under the credit facility, but $40 million and $41 million, respectively, in letters of credit had been issued. Under the combined commercial paper programs, $1,519 million of commercial paper was outstanding at September 30, 2008, compared with $725 million at December 31, 2007.
Also at September 30, 2008, we classified $2,469 million of short-term debt as long-term debt, based on our ability and intent to refinance the obligations on a long-term basis under our revolving credit facility.
On October 1, 2008, we entered into a $2.5 billion 364-day bank facility to provide additional support to temporarily expand our commercial paper program to $9.85 billion. We expanded our commercial paper program to ensure adequate liquidity after the initial funding of our transaction with Origin Energy. For additional information, see Note 21—Joint Venture with Origin Energy.
Note 10—Joint Venture Acquisition Obligation
On January 3, 2007, we closed on a business venture with EnCana Corporation. As part of this transaction, we are obligated to contribute $7.5 billion, plus interest, over a ten-year period, which began in 2007, to the upstream business venture, FCCL Oil Sands Partnership, which was formed as a result of the transaction.
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, approximately $617 million is short-term and is included in the “Accounts payable—related parties” line on our September 30, 2008, consolidated balance sheet. The principal portion of these payments, which totaled $442 million in the first nine months of 2008, 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.
Note 11—Guarantees
At September 30, 2008, 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.
Construction Completion Guarantees
    In December 2005, we issued a construction completion guarantee for 30 percent of the $4.0 billion in loan facilities of Qatargas 3, which will be used to construct an LNG train in Qatar. Of the $4.0 billion in loan facilities, ConocoPhillips has 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 Qatargas 3 project is

12


Table of Contents

      not achieved. The project financing will be nonrecourse to ConocoPhillips upon certified completion, currently expected in 2010. At September 30, 2008, the carrying value of the guarantee to the third-party lenders was $11 million. For additional information, see Note 6—Investments, Loans and Long-Term Receivables.
Guarantees of Joint-Venture Debt
    In June 2006, we issued a guarantee for 24 percent of the $2 billion in credit facilities of Rockies Express Pipeline LLC (Rockies Express), which will be used to construct a natural gas pipeline across a portion of the United States. At September 30, 2008, Rockies Express had $854 million outstanding under the credit facilities, with our 24 percent guarantee equaling $205 million. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $480 million, which could become payable if the credit facilities are fully utilized and Rockies Express fails to meet its obligations under the credit agreement. In addition, we also have a guarantee for 24 percent of $600 million of Floating Rate Notes due 2009 issued by Rockies Express in September 2007. It is anticipated final construction completion will be achieved in 2009, and refinancing will take place at that time, making the debt nonrecourse to ConocoPhillips. At September 30, 2008, the total carrying value of these guarantees to third-party lenders was $12 million. See Note 3—Variable Interest Entities (VIEs), for additional information.
 
    At September 30, 2008, we had other guarantees outstanding for our portion of joint-venture debt obligations, which have terms of up to 17 years. The maximum potential amount of future payments under the guarantees is approximately $80 million. Payment would be required if a joint venture defaults on its debt obligations.
Other Guarantees
    The Merey Sweeny, L.P. (MSLP) joint-venture project agreement requires the partners in the venture to pay cash calls to cover operating expenses in the event the venture does not have enough cash to cover operating expenses after setting aside the amount required for debt service over the next 16 years. Although there is no maximum limit stated in the agreement, the intent is to cover short-term cash deficiencies should they occur. Our maximum potential future payments under the agreement are currently estimated to be $100 million, assuming such a shortfall exists at some point in the future due to an extended operational disruption.
 
    In February 2003, we entered into two agreements establishing separate guarantee facilities of $50 million each for two LNG ships. Subject to the terms of each such facility, we will be required to make payments should the charter revenue generated by the respective ship fall below certain specified minimum thresholds, and we will receive payments to the extent that such revenues exceed those thresholds. The net maximum future payments that we may have to make over the 20-year terms of the two agreements could be up to $100 million in total. To the extent we receive any such payments, our actual gross payments over the 20 years could exceed that amount. In the event either ship is sold or a total loss occurs, we also may have recourse to the sales or insurance proceeds to recoup payments made under the guarantee facilities.
 
    We have guarantees of the residual value of leased corporate aircraft. The maximum potential payment under these guarantees at September 30, 2008, was $170 million.
 
    In December 2007, we acquired a 50 percent equity interest in the Keystone Oil Pipeline (Keystone) to form a 50/50 joint venture with TransCanada Corporation. Keystone plans to construct a crude oil pipeline originating in Hardisty, Alberta, with delivery points at Wood River and Patoka, Illinois, and Cushing, Oklahoma. In connection with certain planning and construction activities, agreements were put in place with third parties to guarantee the payments due. Our maximum potential amount of future payments under those agreements is estimated to be $400 million, which could become payable if Keystone fails to meet its obligations under the agreements noted above and the obligation cannot otherwise be mitigated. Payments under the guarantees are contingent upon the partners not making

13


Table of Contents

      necessary equity contributions into Keystone; therefore, it is considered unlikely that payments would be required. All but $15 million of the guarantees will terminate after construction is completed, currently estimated to occur in 2010.
      In addition to the above guarantee, in order to obtain long-term shipping commitments that would enable a pipeline expansion starting at Hardisty, Alberta, and extending to near Port Arthur, Texas, the Keystone owners entered into a 20-year guarantee in July 2008 to ship volumes for certain shippers to the Gulf Coast. Our maximum potential amount of future payments, or cost of volume delivery, under this guarantee is estimated to be $550 million, which could become payable if Keystone fails to meet its obligations under the agreements noted above and cannot otherwise be mitigated. This is considered unlikely as payment, or cost of volume delivery, is contingent upon the partners defaulting on their obligation to construct and operate in accordance with the terms of the agreement. In October 2008, we elected to exercise an option to reduce our equity interest from 50 percent to 20.01 percent. The change in equity will occur through a dilution mechanism, which is expected to gradually lower our ownership interest, as well as our guarantee obligation, until reaching 20.01 percent by the third quarter of 2009.
 
    We have other guarantees with maximum future potential payment amounts totaling $200 million, which consist primarily of dealer and jobber loan guarantees to support our marketing business, guarantees to fund the short-term cash liquidity deficits of certain joint ventures, one small construction completion guarantee, guarantees relating to the startup of a refining joint venture, and guarantees of the lease payment obligations of a joint venture. These guarantees generally extend up to 10 years or life of the venture and payment would be required only if the dealer, jobber or lessee goes into default, if the joint ventures have cash liquidity issues, if a construction project is not completed, or if a guaranteed party defaults on lease payments.
Indemnifications
Over the years, we have entered into various agreements to sell ownership interests in certain corporations and joint ventures and have sold several assets, including downstream and midstream assets, certain exploration and production assets, and downstream retail and wholesale sites 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, 2008, was $454 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 carrying amount recorded were $253 million of environmental accruals for known contamination that is included in asset retirement obligations and accrued environmental costs at September 30, 2008. For additional information about environmental liabilities, see Note 12—Contingencies and Commitments.
Note 12—Contingencies and Commitments
In the case of all known non-income-tax-related contingencies, 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 adopted FIN 48, effective January 1, 2007. FIN 48 requires a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.

14


Table of Contents

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 that are 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 federal, state and local environmental laws and regulations. These may result in obligations 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 sites. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s 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 that 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 of the cleanup costs related to any site at which we have been designated as a potentially responsible party. If we were solely responsible, the costs, in some cases, could be material to our, or one of our segments’, results of operations, capital resources or liquidity. However, settlements and costs incurred in matters that previously have been resolved have not been material to our results of operations or financial condition. 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 have not recorded accruals for any potential contingent liabilities that we expect to be funded by the prior owners under these indemnifications.
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 for 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 that future costs will be incurred and these costs can be reasonably estimated. At September 30, 2008, our balance sheet included a total environmental accrual of $1,028 million, compared with $1,089 million at December 31, 2007. We expect to incur the majority 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.

15


Table of Contents

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 which have been scheduled for trial, as well as the pace of settlement discussions in individual matters. 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 believes there is a remote likelihood 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.
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, 2008, we had performance obligations secured by letters of credit of $2,213 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) and various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.
Note 13—Financial Instruments and Derivative Contracts
Derivative assets and liabilities were:
                 
    Millions of Dollars  
    September 30     December 31  
    2008     2007  
Derivative Assets
               
Current
  $ 1,173       453  
Long-term
    141       89  
   
 
  $ 1,314       542  
   
Derivative Liabilities
               
Current
  $ 969       493  
Long-term
    162       67  
   
 
  $ 1,131       560  
   
In the preceding table, the 2008 derivative assets appear net of $224 million of obligations to return cash collateral, and the 2008 derivative liabilities appear net of $32 million of rights to reclaim cash collateral. These derivative assets and liabilities appear as prepaid expenses and other current assets, other assets, other accruals, or other liabilities and deferred credits on the balance sheet.

16


Table of Contents

Note 14—Comprehensive Income
ConocoPhillips’ comprehensive income was as follows:
                                 
    Millions of Dollars  
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2008     2007     2008     2007  
 
                               
Net income
  $ 5,188       3,673       14,766       7,520  
After-tax changes in:
                               
Defined benefit pension plans
                               
Net prior service cost
    7       5       (3 )     15  
Net actuarial loss
    10       8       17       38  
Nonsponsored plans
    4       -       8       (3 )
Foreign currency translation adjustments
    (1,584 )     1,320       (1,841 )     2,596  
Hedging activities
    1       (2 )     1       (5 )
   
Comprehensive income
  $ 3,626       5,004       12,948       10,161  
   
Accumulated other comprehensive income in the equity section of the balance sheet included:
                 
    Millions of Dollars  
    September 30     December 31  
    2008     2007  
 
               
Defined benefit pension plans
  $ (443 )     (465 )
Foreign currency translation adjustments
    3,192       5,033  
Deferred net hedging loss
    (7 )     (8 )
   
Accumulated other comprehensive income
  $ 2,742       4,560  
   
Note 15—Cash Flow Information
                 
    Millions of Dollars  
    Nine Months Ended  
    September 30  
    2008     2007  
Noncash Investing and Financing Activities
               
Investment in an upstream business venture through issuance of an acquisition obligation
  $ -       7,313  
Investment in a downstream business venture through contribution of noncash assets and liabilities
    -       2,415  
   
Cash Payments
               
Interest
  $ 475       650  
Income taxes
    10,250       7,969  
   

17


Table of Contents

Note 16—Employee Benefit Plans
Pension and Postretirement Plans
                                                 
    Millions of Dollars  
    Pension Benefits     Other Benefits  
    September 30     September 30  
Components of Net Periodic Benefit Cost   2008     2007     2008     2007  
    U.S.     Int’l.     U.S.     Int’l.                  
Three Months Ended
                                               
Service cost
  $ 46       24       44       25       2       3  
Interest cost
    61       44       57       41       8       12  
Expected return on plan assets
    (55 )     (45 )     (51 )     (37 )     -       -  
Amortization of prior service cost
    4       -       3       1       3       3  
Recognized net actuarial loss (gain)
    15       3       15       12       (3 )     (5 )
   
Net periodic benefit costs
  $ 71       26       68       42       10       13  
   
 
                                               
Nine Months Ended
                                               
Service cost
  $ 140       71       132       73       9       10  
Interest cost
    185       134       171       120       36       34  
Expected return on plan assets
    (167 )     (134 )     (153 )     (109 )     -       -  
Amortization of prior service cost
    8       -       8       5       8       10  
Recognized net actuarial loss (gain)
    48       9       46       35       (13 )     (15 )
   
Net periodic benefit costs
  $ 214       80       204       124       40       39  
   
During the first nine months of 2008, we contributed $357 million to our domestic qualified and nonqualified plans and $123 million to our international benefit plans. We currently expect to contribute a total of $470 million to our domestic plans and $182 million to our international plans in 2008.

18


Table of Contents

Note 17—Related Party Transactions
Significant transactions with related parties were:
                                 
    Millions of Dollars  
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2008     2007     2008     2007  
 
                               
Operating revenues (a)
  $ 3,944       2,465       11,115       7,967  
Purchases (b)
    6,038       4,156       16,129       11,455  
Operating expenses and selling, general and administrative expenses (c)
    142       103       385       309  
Net interest income (d)
    15       25       55       80  
   
(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), gas oil and hydrogen feedstocks were sold to Excel Paralubes and refined products were sold primarily to CFJ Properties and LUKOIL. Natural gas, crude oil, blendstock and other intermediate products were sold to WRB Refining LLC. In addition, we charged several of our affiliates including CPChem, Merey Sweeny L.P. (MSLP) and Hamaca Holding LLC (until expropriation on June 26, 2007) for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.
 
(b)   We purchased refined products from WRB Refining. 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. We purchased crude oil from LUKOIL, upgraded crude oil from Petrozuata C.A. (as a related party until expropriation on June 26, 2007) and refined products from MRC. We also paid fees to various pipeline equity companies for transporting finished refined products and natural gas, and a price upgrade to MSLP for heavy crude oil processing. We purchased base oils and fuel products from Excel Paralubes for use in our refinery and specialty businesses.
 
(c)   We paid processing fees to various affiliates. Additionally, we paid crude oil transportation fees to pipeline equity companies.
 
(d)   We paid and/or received interest to/from various affiliates, including FCCL Oil Sands Partnership. See Note 6—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

19


Table of Contents

Note 18—Segment 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&P—This segment primarily explores for, produces, transports and markets crude oil, natural gas and natural gas liquids on a worldwide basis.
 
  2)   Midstream—This 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&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia Pacific.
 
  4)   LUKOIL Investment—This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia. At September 30, 2008, our ownership interest was 20 percent based on both authorized and issued shares and estimated shares outstanding.
 
  5)   Chemicals—This 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 Businesses—This segment represents our investment in new technologies or businesses outside our normal scope of operations.
Corporate and Other includes general corporate overhead, most interest income and expense, restructuring charges, and various other corporate activities. Corporate assets include all cash and cash equivalents. We evaluate performance and allocate resources based on net income. Intersegment sales are at prices that approximate market.

20


Table of Contents

Analysis of Results by Operating Segment
                                 
    Millions of Dollars  
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2008     2007     2008     2007  
Sales and Other Operating Revenues
                               
E&P
                               
United States
  $ 15,320       9,416       42,831       27,153  
International
    10,333       5,559       27,245       17,052  
Intersegment eliminations—U.S.
    (2,263 )     (1,612 )     (6,900 )     (4,264 )
Intersegment eliminations—international
    (3,005 )     (1,927 )     (8,852 )     (4,844 )
   
E&P
    20,385       11,436       54,324       35,097  
   
Midstream
                               
Total sales
    2,112       1,182       5,854       3,396  
Intersegment eliminations
    (52 )     (39 )     (171 )     (143 )
   
Midstream
    2,060       1,143       5,683       3,253  
   
R&M
                               
United States
    33,778       24,369       97,989       69,022  
International
    14,065       9,178       38,960       27,606  
Intersegment eliminations—U.S.
    (293 )     (113 )     (797 )     (376 )
Intersegment eliminations—international
    (17 )     (2 )     (37 )     (7 )
   
R&M
    47,533       33,432       136,115       96,245  
   
LUKOIL Investment
    -       -       -       -  
Chemicals
    2       2       8       8  
   
Emerging Businesses
                               
Total sales
    303       150       791       450  
Intersegment eliminations
    (244 )     (105 )     (600 )     (310 )
   
Emerging Businesses
    59       45       191       140  
   
Corporate and Other
    5       4       17       9  
   
Consolidated sales and other operating revenues
  $ 70,044       46,062       196,338       134,752  
   
 
                               
 
                               
Net Income (Loss)
                               
E&P
                               
United States
  $ 1,606       1,225       4,807       3,196  
International
    2,322       857       6,007       (1,189 )
   
Total E&P
    3,928       2,082       10,814       2,007  
   
Midstream
    173       104       472       291  
   
R&M
                               
United States
    524       873       1,546       3,648  
International
    325       434       487       1,153  
   
Total R&M
    849       1,307       2,033       4,801  
   
LUKOIL Investment
    438       387       1,922       1,169  
Chemicals
    46       110       116       260  
Emerging Businesses
    35       3       55       (10 )
Corporate and Other
    (281 )     (320 )     (646 )     (998 )
   
Consolidated net income
  $ 5,188       3,673       14,766       7,520  
   

21


Table of Contents

                 
    Millions of Dollars  
    September 30     December 31  
    2008     2007  
Total Assets
               
E&P
               
United States
  $ 37,606       35,160  
International
    58,522       59,412  
Goodwill
    25,457       25,569  
   
Total E&P
    121,585       120,141  
   
Midstream
    1,905       2,016  
   
R&M
               
United States
    27,440       24,336  
International
    10,494       9,766  
Goodwill
    3,767       3,767  
   
Total R&M
    41,701       37,869  
   
LUKOIL Investment
    13,038       11,164  
Chemicals
    2,312       2,225  
Emerging Businesses
    1,239       1,230  
Corporate and Other
    2,827       3,112  
   
Consolidated total assets
  $ 184,607       177,757  
   
Note 19—Income Taxes
Our effective tax rate for both the third quarter and first nine months of 2008 was 45 percent, compared with 42 percent and 53 percent for the same two periods of 2007. The change in the effective tax rate for the third quarter of 2008, versus the third quarter of 2007, was primarily due to a tax rate decrease enacted in Germany in the third quarter of 2007. The change in the effective tax rate for the nine months of 2008, compared with the same period of 2007, was primarily due to the impact of the expropriation of our oil interests in Venezuela on 2007 results (see the “Expropriated Assets” section of Note 13—Impairments, in our 2007 Annual Report on Form 10-K, for additional information), partially offset by the impact of a higher proportion of income in higher tax-rate jurisdictions in 2008. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to the impact of foreign taxes.
Note 20—New Accounting Standards
In December 2007, the FASB issued SFAS No. 141 (Revised), “Business Combinations” (SFAS No. 141(R)). This Statement will apply to all transactions in which an entity obtains control of one or more other businesses. In general, SFAS No. 141(R) requires the acquiring entity in a business combination to recognize the fair value of all the assets acquired and liabilities assumed in the transaction; establishes the acquisition date as the fair value measurement point; and modifies the disclosure requirements. This Statement applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. However, starting January 1, 2009, accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for prior business combinations will impact tax expense instead of impacting goodwill. We are currently evaluating the changes provided for in this Statement.
Also in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51,” which changes the classification of noncontrolling interests, sometimes called minority interests, in the consolidated financial statements. Additionally, this Statement establishes a single method of accounting for changes in a parent company’s ownership interest that do not result in deconsolidation and requires a parent company to recognize a gain or loss when a subsidiary is deconsolidated. This Statement is effective January 1, 2009, and will be applied prospectively with the

22


Table of Contents

exception of the presentation and disclosure requirements, which must be applied retrospectively for all periods presented. We are currently evaluating the impact of this Statement on our consolidated financial statements.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB No. 133.” This Statement expands the annual and interim disclosure requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” for derivative instruments within the scope of that Statement. We must adopt SFAS No. 161 no later than January 1, 2009, but it will not have any impact on our consolidated financial statements, other than the additional disclosures.
Note 21—Joint Venture with Origin Energy
In October 2008, we closed on a transaction with Origin Energy (Origin), an integrated Australian energy company, to create a long-term Australasian natural gas business. The 50/50 joint venture will focus on coalbed methane production from the Bowen and Surat basins in Queensland, Australia, and liquefied natural gas (LNG) processing and export sales.
With this transaction, we have gained access to a leading coalbed methane resource in Australia and will enhance our LNG position with the expected creation of an additional LNG hub serving the Asia Pacific markets.
Under the terms of the transaction, we paid US$5 billion at closing. In addition, we will carry Origin for AU$1.15 billion related to their initial share of joint venture funding requirements, when incurred. We have committed to make up to four additional payments of US$500 million each, expected within the next decade, when each of four expected LNG trains are approved by the joint venture for development, for a total possible cash acquisition investment of approximately US$8 billion at current exchange rates. We funded our initial upfront payment by issuing approximately $4.9 billion of commercial paper and with cash on hand.

23


Table of Contents

Supplementary Information—Condensed 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 is an indirect, wholly owned subsidiary of ConocoPhillips Company. ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding Company II are indirect, wholly owned subsidiaries of ConocoPhillips. 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 2007 income statements have been reclassified to conform to the current year presentation.

24


Table of Contents

                                                                 
    Millions of Dollars  
    Three Months Ended September 30, 2008  
                    ConocoPhillips                                
                    Australia     ConocoPhillips     ConocoPhillips                    
            ConocoPhillips     Funding     Canada Funding     Canada 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
  $ -       45,549       -       -       -       24,495       -       70,044  
Equity in earnings of affiliates
    5,256       3,856       -       -       -       1,181       (9,079 )     1,214  
Other income (loss)
    (1 )     135       -       -       -       (19 )     -       115  
Intercompany revenues
    1       1,166       20       22       14       9,720       (10,943 )     -  
   
Total Revenues and Other Income
    5,256       50,706       20       22       14       35,377       (20,022 )     71,373  
   
 
                                                               
Costs and Expenses
                                                               
Purchased crude oil, natural gas and products
    -       41,990       -       -       -       18,180       (10,562 )     49,608  
Production and operating expenses
    -       1,243       -       -       -       1,841       (25 )     3,059  
Selling, general and administrative expenses
    7       339       -       -       -       180       (13 )     513  
Exploration expenses
    -       31       -       -       -       236       -       267  
Depreciation, depletion and amortization
    -       393       -       -       -       1,968       -       2,361  
Impairments
    -       -       -       -       -       57       -       57  
Taxes other than income taxes
    -       1,280       -       -       -       4,396       (57 )     5,619  
Accretion on discounted liabilities
    -       14       -       -       -       100       -       114  
Interest and debt expense
    97       132       17       19       14       246       (286 )     239  
Foreign currency transaction losses (gains)
    -       18       -       (71 )     (99 )     206       -       54  
Minority interests
    -       -       -       -       -       15       -       15  
   
Total Costs and Expenses
    104       45,440       17       (52 )     (85 )     27,425       (10,943 )     61,906  
   
Income before income taxes
    5,152       5,266       3       74       99       7,952       (9,079 )     9,467  
Provision for income taxes
    (36 )     618       1       7       17       3,672       -       4,279  
   
Net Income
  $ 5,188       4,648       2       67       82       4,280       (9,079 )     5,188  
   

25


Table of Contents

                                                                 
    Millions of Dollars  
    Three Months Ended September 30, 2007  
                    ConocoPhillips                                
                    Australia     ConocoPhillips     ConocoPhillips                    
            ConocoPhillips     Funding     Canada Funding     Canada 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
  $ -       30,130       -       -       -       15,932       -       46,062  
Equity in earnings of affiliates
    3,731       3,227       -       -       -       602       (6,246 )     1,314  
Other income
    -       121       -       -       -       436       -       557  
Intercompany revenues
    1       814       30       21       13       4,648       (5,527 )     -  
   
Total Revenues and Other Income
    3,732       34,292       30       21       13       21,618       (11,773 )     47,933  
   
 
                                                               
Costs and Expenses
                                                               
Purchased crude oil, natural gas and products
    -       26,477       -       -       -       9,211       (4,826 )     30,862  
Production and operating expenses
    -       1,054       -       -       -       1,588       (22 )     2,620  
Selling, general and administrative expenses
    4       365       -       -       -       212       (12 )     569  
Exploration expenses
    -       29       -       -       -       189       -       218  
Depreciation, depletion and amortization
    -       388       -       -       -       1,664       -       2,052  
Impairments
    -       16       -       -       -       172       -       188  
Taxes other than income taxes
    -       1,363       -       -       -       3,291       (71 )     4,583  
Accretion on discounted liabilities
    -       12       -       -       -       69       -       81  
Interest and debt expense
    85       431       28       20       14       409       (596 )     391  
Foreign currency transaction losses (gains)
    -       6       -       83       44       (153 )     -       (20 )
Minority interests
    -       -       -       -       -       25       -       25  
   
Total Costs and Expenses
    89       30,141       28       103       58       16,677       (5,527 )     41,569  
   
Income (loss) before income taxes
    3,643       4,151       2       (82 )     (45 )     4,941       (6,246 )     6,364  
Provision for income taxes
    (30 )     581       -       11       6       2,123       -       2,691  
   
Net Income (Loss)
  $ 3,673       3,570       2       (93 )     (51 )     2,818       (6,246 )     3,673  
   

26


Table of Contents

                                                                 
    Millions of Dollars  
    Nine Months Ended September 30, 2008  
                    ConocoPhillips                                
                    Australia     ConocoPhillips     ConocoPhillips                    
            ConocoPhillips     Funding     Canada Funding     Canada 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
  $ -       128,145       -       -       -       68,193       -       196,338  
Equity in earnings of affiliates
    14,907       10,713       -       -       -       3,935       (25,170 )     4,385  
Other income (loss)
    (2 )     622       -       -       -       (65 )     -       555  
Intercompany revenues
    25       2,798       63       67       41       25,463       (28,457 )     -  
   
Total Revenues and Other Income
    14,930       142,278       63       67       41       97,526       (53,627 )     201,278  
   
 
                                                               
Costs and Expenses
                                                               
Purchased crude oil, natural gas and products
    -       117,520       -       -       -       48,363       (27,241 )     138,642  
Production and operating expenses
    -       3,690       -       -       -       5,266       (95 )     8,861  
Selling, general and administrative expenses
    14       1,124       -       -       -       576       (46 )     1,668  
Exploration expenses
    -       131       -       -       -       733       -       864  
Depreciation, depletion and amortization
    -       1,144       -       -       -       5,604       -       6,748  
Impairments
    -       21       -       -       -       61       -       82  
Taxes other than income taxes
    -       3,819       -       -       -       12,927       (176 )     16,570  
Accretion on discounted liabilities
    -       43       -       -       -       271       -       314  
Interest and debt expense
    225       457       57       58       40       718       (899 )     656  
Foreign currency transaction losses (gains)
    -       16       -       (85 )     (106 )     186       -       11  
Minority interests
    -       -       -       -       -       51       -       51  
   
Total Costs and Expenses
    239       127,965       57       (27 )     (66 )     74,756       (28,457 )     174,467  
   
Income before income taxes
    14,691       14,313       6       94       107       22,770       (25,170 )     26,811  
Provision for income taxes
    (75 )     1,605       2       (6 )     4       10,515       -       12,045  
   
Net Income
  $ 14,766       12,708       4       100       103       12,255       (25,170 )     14,766  
   

27


Table of Contents

                                                                 
    Millions of Dollars  
    Nine Months Ended September 30, 2007  
                    ConocoPhillips                                
                    Australia     ConocoPhillips     ConocoPhillips                    
            ConocoPhillips     Funding     Canada Funding     Canada 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
  $ -       87,022       -       -       -       47,730       -       134,752  
Equity in earnings of affiliates
    7,623       6,881       -       -       -       1,927       (12,682 )     3,749  
Other income
    4       263       -       -       -       1,429       -       1,696  
Intercompany revenues
    148       2,303       90       60       37       13,215       (15,853 )     -  
   
Total Revenues and Other Income
    7,775       96,469       90       60       37       64,301       (28,535 )     140,197  
   
 
                                                               
Costs and Expenses
                                                               
Purchased crude oil, natural gas and products
    -       74,279       -       -       -       27,831       (13,713 )     88,397  
Production and operating expenses
    -       3,249       -       -       -       4,484       (64 )     7,669  
Selling, general and administrative expenses
    13       1,053       -       -       -       676       (42 )     1,700  
Exploration expenses
    -       75       -       -       -       664       -       739  
Depreciation, depletion and amortization
    -       1,111       -       -       -       4,981       -       6,092  
Impairment—expropriated assets
    -       1,925       -       -       -       2,663       -       4,588  
Impairments
    -       (8 )     -       -       -       293       -       285  
Taxes other than income taxes
    -       4,161       -       -       -       9,701       (208 )     13,654  
Accretion on discounted liabilities
    -       40       -       -       -       201       -       241  
Interest and debt expense
    296       1,399       84       58       40       966       (1,826 )     1,017  
Foreign currency transaction losses (gains)
    -       16       -       181       121       (516 )     -       (198 )
Minority interests
    -       -       -       -       -       65       -       65  
   
Total Costs and Expenses
    309       87,300       84       239         161       52,009       (15,853 )     124,249  
   
Income (loss) before income taxes
    7,466         9,169         6       (179 )     (124 )     12,292       (12,682 )     15,948  
Provision for income taxes
    (54 )     2,255         2       9       4       6,212       -       8,428  
   
Net Income (Loss)
  $ 7,520         6,914         4       (188 )     (128 )     6,080       (12,682 )     7,520  
   

28


Table of Contents

                                                                 
    Millions of Dollars  
    At September 30, 2008  
                    ConocoPhillips                                
                    Australia     ConocoPhillips     ConocoPhillips                    
            ConocoPhillips     Funding     Canada Funding     Canada Funding     All Other     Consolidating     Total  
Balance Sheet   ConocoPhillips     Company     Company     Company I     Company II     Subsidiaries     Adjustments     Consolidated  
 
                                                               
Assets
                                                               
Cash and cash equivalents
  $ -       244       -       6       1       1,110       (245 )     1,116  
Accounts and notes receivable
    49       13,230       19       1       -       22,889       (19,202 )     16,986  
Inventories
    -       4,334       -       -       -       2,516       (109 )     6,741  
Prepaid expenses and other current assets
    3       887       -       4       3       2,586       -       3,483  
   
Total Current Assets
    52       18,695       19       11       4       29,101       (19,556 )     28,326  
Investments, loans and long-term receivables*
    97,446       105,372       1,700       1,396       945       40,520       (210,982 )     36,397  
Net properties, plants and equipment
    -       19,541       -       -       -       69,716       2       89,259  
Goodwill
    -       12,711       -       -       -       16,513       -       29,224  
Intangibles
    -       789       -       -       -       72       -       861  
Other assets
    14       176       2       4       27       413       (96 )     540  
   
Total Assets
  $ 97,512       157,284       1,721       1,411       976       156,335       (230,632 )     184,607  
   
 
                                                               
Liabilities and Stockholders’ Equity
                                                               
Accounts payable
  $ 26       20,942       -       3       4       17,464       (19,202 )     19,237  
Short-term debt
    -       301       950       -       -       86       (950 )     387  
Accrued income and other taxes
    -       9       -       1       (1 )     6,360       -       6,369  
Employee benefit obligations
    -       461       -       -       -       295       2       758  
Other accruals
    63       894       25       32       22       1,729       (6 )     2,759  
   
Total Current Liabilities
    89       22,607       975       36       25       25,934       (20,156 )     29,510  
Long-term debt
    5,048       5,377       749       1,250       848       7,491       950       21,713  
Asset retirement obligations and accrued environmental costs
    -       1,111       -       -       -       6,602       -       7,713  
Joint venture acquisition obligation
    -       -       -       -       -       5,828       -       5,828  
Deferred income taxes
    (3 )     3,421       -       15       18       16,973       (16 )     20,408  
Employee benefit obligations
    -       2,076       -       -       -       737       -       2,813  
Other liabilities and deferred credits*
    6,174       21,104       -       51       23       12,982       (37,715 )     2,619  
   
Total Liabilities
    11,308       55,696       1,724       1,352       914       76,547       (56,937 )     90,604  
Minority interests
    -       (12 )     -       -       -       1,139       -       1,127  
Retained earnings (deficit)
    56,590       36,660       (3 )     (47 )     (4 )     29,849       (59,942 )     63,103  
Other stockholders’ equity
    29,614       64,940       -       106       66       48,800       (113,753 )     29,773  
   
Total
  $ 97,512       157,284       1,721       1,411       976       156,335       (230,632 )     184,607  
   
*Includes intercompany loans.

29


Table of Contents

                                                                 
    Millions of Dollars  
    At December 31, 2007  
                    ConocoPhillips                                
                    Australia     ConocoPhillips     ConocoPhillips                    
            ConocoPhillips     Funding     Canada Funding     Canada Funding     All Other     Consolidating     Total  
Balance Sheet   ConocoPhillips     Company     Company     Company I     Company II     Subsidiaries     Adjustments     Consolidated  
 
                                                               
Assets
                                                               
Cash and cash equivalents
  $ -       195       -       7       1       1,626       (373 )     1,456  
Accounts and notes receivable
    40       12,421       15       12       4       19,548       (15,686 )     16,354  
Inventories
    -       2,043       -       -       -       2,190       (10 )     4,223  
Prepaid expenses and other current assets
    9       578       -       1       -       2,114       -       2,702  
   
Total Current Assets
    49       15,237       15       20       5       25,478       (16,069 )     24,735  
Investments, loans and long-term receivables*
    86,942       57,936       1,700       1,470       997       18,972       (134,689 )     33,328  
Net properties, plants and equipment
    -       17,677       -       -       -       71,317       9       89,003  
Goodwill
    -       12,746       -       -       -       16,590       -       29,336  
Intangibles
    -       808       -       -       -       88       -       896  
Other assets
    8       153       3       5       4       520       (234 )     459  
   
Total Assets
  $ 86,999       104,557       1,718       1,495       1,006       132,965       (150,983 )     177,757  
   
 
                                                               
Liabilities and Stockholders’ Equity
                                                               
Accounts payable
  $ 6       18,792       -       10       4       15,108       (16,059 )     17,861  
Short-term debt
    1,000       309       -       -       -       89       -       1,398  
Accrued income and other taxes
    -       601       -       -       (1 )     4,117       97       4,814  
Employee benefit obligations
    -       509       -       -       -       411       -       920  
Other accruals
    21       594       20       16       11       1,230       (3 )     1,889  
   
Total Current Liabilities
    1,027       20,805       20       26       14       20,955       (15,965 )     26,882  
Long-term debt
    3,402       5,694       1,699       1,250       848       7,396       -       20,289  
Asset retirement obligations and accrued environmental costs
    -       1,167       -       -       -       6,094       -       7,261  
Joint venture acquisition obligation
    -       -       -       -       -       6,294       -       6,294  
Deferred income taxes
    (3 )     3,050       -       32       18       17,907       14       21,018  
Employee benefit obligations
    -       2,292       -       -       -       899       -       3,191  
Other liabilities and deferred credits*
    42       16,447       -       132       102       15,489       (29,546 )     2,666  
   
Total Liabilities
    4,468       49,455       1,719       1,440       982       75,034       (45,497 )     87,601  
Minority interests
    -       (19 )     -       -       -       1,194       (2 )     1,173  
Retained earnings (deficit)
    43,988       23,952       (1 )     (147 )     (107 )     20,738       (37,913 )     50,510  
Other stockholders’ equity
    38,543       31,169       -       202       131       35,999       (67,571 )     38,473  
   
Total
  $ 86,999       104,557       1,718       1,495       1,006       132,965       (150,983 )     177,757  
   
*Includes intercompany loans.

30


Table of Contents

                                                                 
    Millions of Dollars  
    Nine Months Ended September 30, 2008  
                    ConocoPhillips                                
                    Australia     ConocoPhillips     ConocoPhillips                    
            ConocoPhillips     Funding     Canada Funding     Canada Funding     All Other     Consolidating     Total  
Statement of Cash Flows   ConocoPhillips     Company     Company     Company I     Company II     Subsidiaries     Adjustments     Consolidated  
 
                                                               
Net Cash Provided by (Used in) Operating Activities
  $ 8,852       1,769       6       (1 )     -       11,922       (3,012 )     19,536  
   
 
                                                               
Cash Flows From Investing Activities
                                                               
Capital expenditures and investments
    -       (3,901 )     -       -       -       (7,341 )     707       (10,535 )
Proceeds from asset dispositions
    -       251       -       -       -       658       (180 )     729  
Long-term advances/loans—related parties
    -       (400 )     -       -       -       (2,812 )     3,031       (181 )
Collection of advances/loans—related parties
    -       224       -       -       -       12       (221 )     15  
Other
    -       (183 )     -       -       -       (3 )     -       (186 )
   
Net Cash Used in Investing Activities
    -       (4,009 )     -       -       -       (9,486 )     3,337       (10,158 )
   
 
                                                               
Cash Flows From Financing Activities
                                                               
Issuance of debt
    2,136       2,671       -       -       -       488       (3,031 )     2,264  
Repayment of debt
    (1,500 )     (350 )     -       -       -       (228 )     221       (1,857 )
Issuance of company common stock
    182       -       -       -       -       -       -       182  
Repurchase of company common stock
    (7,500 )     -       -       -       -       -       -       (7,500 )
Dividends paid on common stock
    (2,159 )     -       (6 )     -       -       (3,134 )     3,140       (2,159 )
Other
    (11 )     126       -       -       -       (14 )     (527 )     (426 )
   
Net Cash Provided by (Used in) Financing Activities
    (8,852 )     2,447       (6 )     -       -       (2,888 )     (197 )     (9,496 )
   
 
                                                               
Effect of Exchange Rate Changes on Cash and Cash Equivalents
    -       (158 )     -       -       -       (64 )     -       (222 )
   
 
                                                               
Net Change in Cash and Cash Equivalents
    -       49       -       (1 )     -       (516 )     128       (340 )
Cash and cash equivalents at beginning of period
    -       195       -       7       1       1,626       (373 )     1,456  
   
Cash and Cash Equivalents at End of Period
  $ -       244       -       6       1       1,110       (245 )     1,116  
   

31


Table of Contents

                                                                 
    Millions of Dollars  
    Nine Months Ended September 30, 2007  
                    ConocoPhillips                                
                    Australia     ConocoPhillips     ConocoPhillips                    
            ConocoPhillips     Funding     Canada Funding     Canada Funding     All Other     Consolidating     Total  
Statement of Cash Flows   ConocoPhillips     Company     Company     Company I     Company II     Subsidiaries     Adjustments     Consolidated  
 
                                                               
Net Cash Provided by (Used in) Operating Activities
  $ 11,862       (2,048 )     7       -       -       8,473       (664 )     17,630  
   
 
                                                               
Cash Flows From Investing Activities
                                                               
Capital expenditures and investments
    -       (1,821 )     -       -       -       (6,288 )     202       (7,907 )
Proceeds from asset dispositions
    -       1,299       -       -       -       2,604       (846 )     3,057  
Long-term advances/loans —related parties
    -       (143 )     -       -       -       (2,486 )     2,180       (449 )
Collection of advances/loans—related parties
    -       954       -       -       -       1       (889 )     66  
Other
    1       22       -       -       -       1       -       24  
   
Net Cash Provided by (Used in) Investing Activities
    1       311       -       -       -       (6,168 )     647       (5,209 )
   
 
                                                               
Cash Flows From Financing Activities
                                                               
Issuance of debt
    (36 )     2,179       -       -       -       861       (2,180 )     824  
Repayment of debt
    (5,564 )     (561 )     -       -       -       (905 )     889       (6,141 )
Issuance of company common stock
    251       -       -       -       -       -       -       251  
Repurchase of company common stock
    (4,501 )     -       -       -       -       -       -       (4,501 )
Dividends paid on common stock
    (2,009 )     -       (7 )     -       -       (626 )     633       (2,009 )
Other
    (4 )     76       -       -       -       (1,005 )     644       (289 )
   
Net Cash Provided by (Used in) Financing Activities
    (11,863 )     1,694       (7 )     -       -       (1,675 )     (14 )     (11,865 )
   
 
                                                               
Effect of Exchange Rate Changes on Cash and Cash Equivalents
    -       -       -       -       -       6       -       6  
   
 
                                                               
Net Change in Cash and Cash Equivalents
    -       (43 )     -       -       -       636       (31 )     562  
Cash and cash equivalents at beginning of period
    -       116       -       -       1       1,042       (342 )     817  
   
Cash and Cash Equivalents at End of Period
  $ -       73       -       -       1       1,678       (373 )     1,379  
   

32


Table of Contents

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis contains forward-looking statements including, without limitation, statements relating to our 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 “intends,” “believes,” “expects,” “plans,” “scheduled,” “should,” “anticipates,” “estimates,” and similar expressions identify forward-looking statements. We do not undertake to update, revise or correct any of the forward-looking information. Readers are cautioned that such forward-looking statements should be read in conjunction with the 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 54.
BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW
Our Exploration and Production (E&P) segment had net income of $3,928 million in the third quarter of 2008, which accounted for 76 percent of our total net income in the quarter. This compares with E&P net income of $3,999 million in the second quarter of 2008, and $2,082 million in the third quarter of 2007.
E&P net income in the third quarter of 2008 was impacted by a decrease in commodity prices. Industry crude oil prices for West Texas Intermediate averaged $117.83 per barrel in the third quarter of 2008, or $6.15 per barrel lower than the second quarter of 2008, but $42.35 higher than in the same period a year earlier. Crude oil prices were influenced, among other factors, by growing concerns about financial markets and the slowing worldwide economy’s expected adverse impact on oil demand growth.
Industry natural gas prices for Henry Hub decreased during the third quarter of 2008 to $10.25 per million British thermal units (MMBTU), down $0.69 per MMBTU from the second quarter of 2008 but $4.09 higher than in the same period a year earlier. Natural gas prices trended lower during the third quarter due to rising domestic unconventional gas production in the face of slowing natural gas demand growth due to the weakening U.S. economy. Although production fell in September due to hurricane outages, natural gas storage still moved above the five year average, further influencing the downward move in the natural gas price.
Our Refining and Marketing (R&M) segment had net income of $849 million in the third quarter of 2008, compared with $664 million in the second quarter of 2008, and $1,307 million in the third quarter of 2007. The increase in net income from the previous quarter was primarily due to improved global realized marketing margins and lower turnaround costs, which were partially offset by lower refining volumes. The decrease in net income from the third quarter of 2007 reflects a lower net benefit from the company’s asset rationalization efforts, the absence of a third-quarter 2007 German tax legislation benefit and lower refining volumes. These items were partially offset by improved global realized marketing margins.

33


Table of Contents

RESULTS OF OPERATIONS
Unless otherwise indicated, discussion of results for the three- and nine-month periods ending September 30, 2008, is based on a comparison with the corresponding periods of 2007.
Consolidated Results
A summary of net income (loss) by business segment follows:
                                 
    Millions of Dollars  
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2008     2007     2008     2007  
 
                               
Exploration and Production (E&P)
  $ 3,928       2,082       10,814       2,007  
Midstream
    173       104       472       291  
Refining and Marketing (R&M)
    849       1,307       2,033       4,801  
LUKOIL Investment
    438       387       1,922       1,169  
Chemicals
    46       110       116       260  
Emerging Businesses
    35       3       55       (10 )
Corporate and Other
    (281 )     (320 )     (646 )     (998 )
   
Net income
  $ 5,188       3,673       14,766       7,520  
   
Net income was $5,188 million in the third quarter of 2008, compared with $3,673 million in the third quarter of 2007. For the nine-month periods ended September 30, 2008 and 2007, net income was $14,766 million and $7,520 million, respectively. The nine-month period in 2007 included a complete impairment ($4,512 million after-tax) of our oil interests in Venezuela, resulting from their expropriation on June 26, 2007.
The results in both 2008 periods were enhanced by significantly higher crude oil, natural gas and natural gas liquids prices, benefiting our E&P, Midstream and LUKOIL Investment segments. These increases were partially offset by a decrease in net income from our R&M segment.
See the “Segment Results” section for additional information on our segment results.
Income Statement Analysis
Sales and other operating revenues increased 52 percent in the third quarter of 2008 and 46 percent in the nine-month period, while purchased crude oil, natural gas and products increased 61 percent and 57 percent, respectively. These increases were mainly the result of higher petroleum product prices, and higher prices for crude oil, natural gas and natural gas liquids.
Equity in earnings of affiliates decreased 8 percent in the third quarter of 2008, mainly due to lower earnings from WRB Refining LLC and Chevron Phillips Chemical Company LLC (CPChem), partially offset by increased earnings from FCCL Oil Sands Partnership, DCP Midstream, LLC and LUKOIL. Equity in earnings of affiliates increased 17 percent in the nine-month period, reflecting improved results from LUKOIL, FCCL and DCP Midstream, partially offset by lower results from WRB and CPChem, as well as the absence of earnings from Hamaca and Petrozuata, our heavy-oil joint ventures expropriated by Venezuela in the second quarter of 2007.

34


Table of Contents

Other income decreased 79 percent and 67 percent during the third quarter and first nine months of 2008, respectively. The decrease was primarily due to higher 2007 net gains on asset dispositions associated with asset rationalization efforts. In addition, the 2007 periods included a net benefit from the Alaska Quality Bank settlements.
Production and operating costs increased 17 percent and 16 percent during the third quarter and first nine months of 2008, respectively. Contributing to the increase were higher maintenance and well workover costs, as well as unfavorable foreign currency exchange impacts in E&P and higher turnaround and utility costs in R&M.
Depreciation, depletion and amortization increased 15 percent during the third quarter and 11 percent during the first nine months of 2008. The increases were mostly associated with our E&P segment, reflecting startup of new developments, foreign currency exchange impacts and changes in asset retirement obligations.
Impairment—expropriated assets reflects a second-quarter 2007 noncash impairment of $4,588 million before-tax related to the expropriation of our oil interests in Venezuela. For additional information, see the “Expropriated Assets” section of Note 13—Impairments, in our 2007 Annual Report on Form 10-K.
Taxes other than income taxes increased 23 percent and 21 percent during the third quarter and first nine months of 2008, respectively, primarily due to increased production taxes in our E&P segment, a significant portion of which relates to Alaska.
Interest and debt expense decreased 39 percent and 35 percent during both periods of 2008, respectively, primarily due to lower average interest rates, as well as impacts related to the Alaska Quality Bank settlements, which occurred in the third quarter of 2007. In addition, the decrease in the nine-month period was also affected by a lower average debt level.

35


Table of Contents

Segment Results
E&P
                                 
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2008     2007     2008     2007  
       
    Millions of Dollars  
Net Income (Loss)
                               
Alaska
  $ 556       765       1,859       1,807  
Lower 48
    1,050       460       2,948       1,389  
   
United States
    1,606       1,225       4,807       3,196  
International
    2,322       857       6,007       (1,189 )
   
 
  $ 3,928       2,082       10,814       2,007  
   
                                 
    Dollars Per Unit  
Average Sales Prices
                               
Crude oil (per barrel)
                               
United States
  $ 118.90       72.00       110.26       62.70  
International
    110.84       74.03       108.94       65.19  
Total consolidated
    114.20       73.01       109.53       63.99  
Equity affiliates*
    88.32       44.60       81.74       44.30  
Worldwide E&P
    112.19       71.34       107.84       61.80  
Natural gas (per thousand cubic feet)
                               
United States
    8.64       5.36       8.66       6.01  
International
    9.13       5.75       9.14       6.24  
Total consolidated
    8.91       5.56       8.93       6.13  
Equity affiliates*
    -       -       -       .30  
Worldwide E&P
    8.91       5.56       8.93       6.13  
Natural gas liquids (per barrel)
                               
United States
    68.84       47.73       64.53       43.34  
International
    68.78       48.63       67.46       44.21  
Total consolidated
    68.81       48.09       65.85       43.71  
Equity affiliates*
    -       -       -       -  
Worldwide E&P
    68.81       48.09       65.85       43.71  
                                 
    Millions of Dollars  
Worldwide Exploration Expenses
                               
General and administrative; geological and geophysical; and lease rentals
  $ 149       144       465       384  
Leasehold impairment
    60       51       179       196  
Dry holes
    58       23       220       159  
   
 
  $ 267       218       864       739  
   
*Excludes our equity share of LUKOIL, which is reported in the LUKOIL Investment segment.

36


Table of Contents

                                 
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2008     2007     2008     2007  
     
    Thousands of Barrels Daily  
Operating Statistics
                               
Crude oil produced
                               
Alaska
    218       241       239       261  
Lower 48
    85       103       92       104  
   
United States
    303       344       331       365  
Europe
    221       203       205       210  
Asia Pacific
    87       83       88       91  
Canada
    25       17       24       19  
Middle East and Africa
    73       73       78       80  
Other areas
    9       10       9       10  
   
Total consolidated
    718       730       735       775  
Equity affiliates*
                               
Canada
    32       29       29       27  
Russia and Caspian
    31       15       21       15  
Venezuela
    -       -       -       56  
   
 
    781       774       785       873  
   
 
                               
Natural gas liquids produced
   
Alaska
    13       15       16       18  
Lower 48
    74       73       73       71  
   
United States
    87       88       89       89  
Europe
    15       11       19       12  
Asia Pacific
    19       13       17       13  
Canada
    24       26       25       29  
Middle East and Africa
    3       1       3       2  
   
 
    148       139       153       145  
   
 
                               
    Millions of Cubic Feet Daily
       
Natural gas produced**
                               
Alaska
    102       116       100       113  
Lower 48
    1,971       2,219       1,989       2,210  
   
United States
    2,073       2,335       2,089       2,323  
Europe
    847       793       918       932  
Asia Pacific
    648       575       617       592  
Canada
    1,061       1,069       1,072       1,118  
Middle East and Africa
    122       124       114       130  
Other areas
    18       20       19       21  
   
Total consolidated
    4,769       4,916       4,829       5,116  
Equity affiliates*
                               
Venezuela
    -       -       -       6  
   
 
    4,769       4,916       4,829       5,122  
   
 
                               
    Thousands of Barrels Daily
       
Mining operations
                               
Syncrude produced
    24       27       21       24  
   
* Excludes our equity share of LUKOIL, which is reported in the LUKOIL Investment segment. 
** Represents quantities available for sale. Excludes gas equivalent of natural gas liquids shown above. 

37


Table of Contents

The E&P segment explores for, produces, transports and markets crude oil, natural gas and natural gas liquids on a worldwide basis. It also mines deposits of oil sands in Canada to extract the bitumen and upgrade it into a synthetic crude oil. At September 30, 2008, our E&P operations were producing in the United States, Norway, the United Kingdom, the Netherlands, Canada, Nigeria, Ecuador, offshore Timor-Leste in the Timor Sea, Australia, China, Indonesia, Algeria, Libya, Vietnam, and Russia.
The E&P segment reported net income of $3,928 million in the third quarter of 2008, compared with $2,082 million in the third quarter of 2007. Results for the third quarter of 2008 reflected higher crude oil, natural gas and natural gas liquids prices, partially offset by higher production taxes, higher operating costs, and lower volumes.
Net income for the E&P segment for the first nine months of 2008 was $10,814 million, compared with $2,007 million for the corresponding period of 2007. The nine-month 2007 period results included a noncash impairment of $4,588 million before-tax ($4,512 million after-tax) related to the expropriation of our oil interests in Venezuela. For additional information, see the “Expropriated Assets” section of Note 13—Impairments, in our 2007 Annual Report on Form 10-K. The increase in net income was attributed to the impact of the Venezuela impairment on our prior-year results and higher crude oil, natural gas and natural gas liquids prices. The increase was partially offset by higher production taxes, lower volumes, higher operating costs and a reduced net benefit from asset rationalization efforts. See the “Business Environment and Executive Overview” section for additional information on industry crude oil and natural gas prices.
U.S. E&P
Net income from our U.S. E&P operations increased 31 percent and 50 percent in the third quarter and first nine months of 2008, respectively, primarily due to higher crude oil, natural gas and natural gas liquids prices. The increases were partially offset by higher production taxes (mainly in Alaska), lower crude oil and natural gas volumes, higher operating costs and the absence of a net benefit from the Alaska Quality Bank settlements recorded in the third quarter of 2007.
U.S. E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 736,000 BOE per day in the third quarter of 2008, a decrease of 10 percent from 821,000 BOE per day in the third quarter of 2007. The production decrease was primarily due to normal field decline, unplanned downtime mostly related to hurricane disruptions, and planned maintenance activities in Alaska.
International E&P
Net income from our international E&P operations was $2,322 million in the third quarter of 2008, compared with $857 million in the third quarter of 2007. The increase was primarily attributed to higher crude oil, natural gas and natural gas liquids prices, as well as increased volumes. This was partially offset by higher depreciation expense.
Net income from our international E&P operations was $6,007 million in the first nine months of 2008, compared with a net loss of $1,189 million in the corresponding period of 2007. The increase in net income was attributed to the impact of the Venezuela impairment on our prior-year results and higher crude oil, natural gas and natural gas liquids prices. The increase was partially offset by higher depreciation expense, increased operating costs, lower volumes primarily due to the expropriation of our oil interests in Venezuela, and a lower net benefit from asset rationalization efforts.
International E&P production averaged 988,000 BOE per day in the third quarter of 2008, an increase of 8 percent from 911,000 BOE per day in the third quarter of 2007, primarily due to production from new developments in the United Kingdom, Russia, Indonesia, Norway and Canada, as well as less planned and unplanned downtime. This increase was partially offset by normal field decline and the impact of higher commodity prices on production sharing contracts.

38


Table of Contents

Our Syncrude mining operations produced 24,000 barrels per day in the third quarter of 2008, compared with 27,000 barrels per day in the third quarter of 2007.
Midstream
                                 
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2008     2007     2008     2007  
     
    Millions of Dollars  
 
Net Income*
  $ 173       104       472       291  
   
*Includes DCP Midstream-related net income:
  $ 153       90       408       216  
 
                               
    Dollars Per Barrel  
       
Average Sales Prices
                               
U.S. natural gas liquids*
                               
Consolidated
  $ 67.39       48.62       65.23       43.85  
Equity affiliates
    60.46       47.73       59.82       42.86  
   
*Prices are 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*
    176       216       190       208  
Natural gas liquids fractionated**
    181       168       166       173  
   
* Includes our share of equity affiliates, except LUKOIL, which is included in the LUKOIL Investment segment.
** 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 fractionated—separated into individual components like ethane, butane and propane—and 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 and marketing businesses, primarily in the United States and Trinidad.
Net income from the Midstream segment increased 66 percent and 62 percent in the third quarter and first nine months of 2008. The increase in both periods was primarily due to higher realized natural gas liquids prices, partially offset by higher costs, including increased fuel costs and repairs and maintenance work. In addition, the third quarter was negatively impacted by lower volumes, primarily related to hurricane impacts.

39


Table of Contents

R&M
                                 
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2008     2007     2008     2007  
     
    Millions of Dollars  
Net Income
                               
United States
  $ 524       873       1,546       3,648  
International
    325       434       487       1,153  
   
 
  $ 849       1,307       2,033       4,801  
   
 
                               
    Dollars Per Gallon  
       
U.S. Average Sales Prices*
                               
Gasoline
                               
Wholesale
  $ 3.21       2.32       3.00       2.23  
Retail
    3.42       2.43       3.14       2.38  
Distillates—wholesale
    3.56       2.36       3.41       2.18  
   
*Excludes excise taxes.
                               
 
                               
    Thousands of Barrels Daily  
       
Operating Statistics
                               
Refining operations*
                               
United States
                               
Crude oil capacity**
    2,008       2,037       2,008       2,034  
Crude oil runs
    1,813       1,980       1,837       1,938  
Capacity utilization (percent)
    90 %     97       91       95  
Refinery production
    1,975       2,177       2,020       2,139  
International
                               
Crude oil capacity**
    670       687       670       693  
Crude oil runs
    505       574       557       616  
Capacity utilization (percent)
    75 %     84       83       89  
Refinery production
    523       593       562       634  
Worldwide
                               
Crude oil capacity**
    2,678       2,724       2,678       2,727  
Crude oil runs
    2,318       2,554       2,394       2,554  
Capacity utilization (percent)
    87 %     94       89       94  
Refinery production
    2,498       2,770       2,582       2,773  
   
* Includes our share of equity affiliates, except for our share of LUKOIL, which is reported in the LUKOIL Investment segment.
** Weighted-average crude oil capacity for the three- and nine-month periods of 2007. Actual capacity at September 30, 2007, was 2,037,000, 669,000 and 2,706,000 barrels per day, respectively, for our U.S. refineries, our international refineries and worldwide.
                                 
Petroleum products sales volumes
                               
United States
                               
Gasoline
    1,089       1,212       1,095       1,256  
Distillates
    858       869       880       853  
Other products
    365       439       384       473  
   
 
    2,312       2,520       2,359       2,582  
International
    634       629       645       694  
   
 
    2,946       3,149       3,004       3,276  
   

40


Table of Contents

The R&M segment’s operations encompass refining crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels); buying, selling and transporting crude oil; and buying, selling, transporting, distributing and marketing petroleum products. R&M has operations mainly in the United States, Europe and Asia Pacific.
Net income from the R&M segment decreased 35 percent during the third quarter of 2008 and 58 percent in the first nine months of 2008. The results in both periods were lower due to decreased refining volumes, the absence of a $141 million third-quarter 2007 German tax legislation benefit and a reduced benefit from asset rationalization efforts. Additionally, the first nine months were impacted by significantly lower U.S. realized refining margins and higher operating costs, while higher global realized marketing margins partially offset these negative impacts.
U.S. R&M
Net income from our U.S. R&M operations decreased 40 percent in the third quarter of 2008 and 58 percent in the first nine months of 2008. The decrease in both periods was primarily the result of lower refining margins and volumes and higher turnaround and utility costs. Higher marketing margins partially offset the decrease during both periods.
Our U.S. refining capacity utilization rate was 90 percent in the third quarter of 2008, compared with 97 percent in the third quarter of 2007. The decline in the current year rate resulted mainly from downtime associated with hurricanes.
In September 2008, WRB, our refining business venture with EnCana, received final government approval on a key permit associated with the expansion of the Wood River refinery.
International R&M
Net income from our international R&M operations decreased 25 percent in the third quarter of 2008 and 58 percent for the first nine months of 2008. Contributing to the decrease in both periods were negative foreign currency exchange impacts, the absence of a third-quarter 2007 German tax legislation benefit, and a reduced net benefit from asset rationalization efforts. Higher international refining and marketing margins partially offset these decreases. Additionally, the first nine months were impacted by decreased refining and marketing volumes.
Our international refining capacity utilization rate was 75 percent in the third quarter of 2008, compared with 84 percent in the same quarter of 2007. The utilization rate was primarily impacted in both periods by reduced crude throughput at our Wilhelmshaven refinery due to economic conditions.

41


Table of Contents

LUKOIL Investment
                                 
    Millions of Dollars  
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2008     2007     2008     2007  
 
                               
Net Income
  $ 438       387       1,922       1,169  
   
 
                               
Operating Statistics*
                               
Net crude oil production (thousands of barrels daily)
    371       390       384       404  
Net natural gas production (millions of cubic feet daily)
    303       249       356       278  
Net refinery crude oil processed (thousands of barrels daily)
    228       226       222       210  
   
*Represents our net share of our estimate of LUKOIL’s production and processing.
The LUKOIL Investment segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia, which we account for under the equity method. As of September 30, 2008, our ownership interest in LUKOIL was 20 percent based on authorized and issued shares. Our ownership interest based on estimated shares outstanding, used for equity-method accounting, was also 20 percent at September 30, 2008. Since LUKOIL’s accounting cycle close and preparation of U.S. generally accepted accounting principles financial statements occur subsequent to our reporting deadline, our equity earnings and statistics for our LUKOIL investment are estimated based on current market indicators, publicly available LUKOIL operating results and other objective data. Once the difference between actual and estimated results is known, an adjustment is recorded. This estimate-to-actual adjustment will be a recurring component of future period results. The adjustment to second-quarter 2008 estimates, recorded in the third quarter of 2008, reduced net income $101 million. This compares with a reduction to net income of $85 million recorded in the third quarter of 2007.
In addition to our estimated equity share of LUKOIL’s earnings, this segment reflects the amortization of the basis difference between our equity interest in the net assets of LUKOIL and the book value of our investment. The segment also includes the costs associated with our employees seconded to LUKOIL.
Net income from the LUKOIL Investment segment increased 13 percent in the third quarter of 2008 and 64 percent in the first nine months of 2008. The increase in both periods was primarily due to higher estimated realized prices, partially offset by higher estimated taxes and operating costs, as well as a decrease in estimated volumes.
At September 30, 2008, the closing price of LUKOIL shares (ADRs) on the London Stock Exchange was $58.80 per share, down $39.80 per share, or 40 percent, from June 30, 2008. The aggregate market value of our LUKOIL investment at September 30 was, therefore, $10,003 million, or $2,861 million below the $12,864 million book value of our LUKOIL investment. Book value includes $7.5 billion of share acquisition costs, along with undistributed equity earnings and basis difference amortization. We evaluated the decrease in market value below book value of our LUKOIL investment and concluded the decline did not meet the other-than-temporary impairment recognition guidance of Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” In reaching this conclusion, we considered: 1) the lack of deterioration in LUKOIL’s financial condition and near-term prospects during the quarter; 2) general oil and gas industry downward stock price trends during the quarter, as well as the historical volatility of oil and gas commodity prices, which often create short-term volatility in energy industry stock prices; 3) the intent and ability of ConocoPhillips to retain its investment in LUKOIL; 4) the short length of time book value has been less than market value; and 5) non-energy-related factors impacting the U.S. and Russian financial markets during the quarter.

42


Table of Contents

At October 29, 2008, the closing price of LUKOIL shares on the London Stock Exchange was $33.01 per share, 44 percent lower than at September 30, 2008. We will continue to closely monitor the relationship between the carrying value and market value of our LUKOIL investment. Should we determine in the future there has been a loss in the carrying value of our investment that is other than temporary, we would record a noncash impairment of our investment, calculated as the total difference between carrying value and market value as of the end of the reporting period.
Chemicals
                                 
    Millions of Dollars  
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2008     2007     2008     2007  
 
                               
Net Income
  $ 46       110       116       260  
   
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.
Net income from the Chemicals segment decreased 58 percent and 55 percent in the third quarter and first nine months of 2008, respectively. The decrease in both periods was due to lower aromatics and styrenics margins, as well as higher utility and turnaround costs. Both periods also had increased olefin and polyolefin margins. Business conditions in the chemicals and plastics industry are expected to remain challenging in the near term.
Emerging Businesses
                                 
    Millions of Dollars  
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2008     2007     2008     2007  
Net Income (Loss)
                               
Power
  $ 53       21       106       33  
Other
    (18 )     (18 )     (51 )     (43 )
   
 
  $ 35       3       55       (10 )
   
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 unconventional hydrocarbon recovery (including heavy oil), refining, alternative energy, biofuels, and the environment.
The Emerging Businesses segment reported net income of $35 million in the third quarter of 2008, compared with $3 million in the same quarter of 2007. Net income for the first nine months of 2008 was $55 million, compared with a net loss of $10 million for the same period a year ago. The improvement for both periods primarily reflects improved international power generation results, partially offset by lower domestic power results.

43


Table of Contents

Corporate and Other
                                 
    Millions of Dollars  
    Three Months Ended     Nine Months Ended  
    September 30     September 30  
    2008     2007     2008     2007  
Net Loss
                               
Net interest
  $ (149 )     (195 )     (376 )     (663 )
Corporate general and administrative expenses
    (41 )     (49 )     (153 )     (126 )
Acquisition/merger-related costs
    -       (11 )     -       (40 )
Other
    (91 )     (65 )     (117 )     (169 )
   
 
  $ (281 )     (320 )     (646 )     (998 )
   
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. In 2008, net interest decreased 24 percent in the third quarter and 43 percent in the first nine months. The decrease in both periods was affected by lower average interest rates, while the decrease in the first nine months was also affected by a lower average debt level.
Corporate general and administrative expenses decreased 16 percent in the third quarter, primarily due to lower benefit-related expenses, partially offset by higher charitable contributions and advertising costs. Corporate general and administrative expenses increased 21 percent in the first nine months of 2008, as higher charitable contributions and advertising costs were only partially offset by lower benefit-related expenses.
Acquisition-related costs in 2007 included transition costs associated with the Burlington Resources acquisition.
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. Increased expenses for the third quarter of 2008 mainly related to higher foreign currency losses. Improved results from Other in the first nine months of 2008 included lower foreign currency losses.

44


Table of Contents

CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
                 
    Millions of Dollars  
    At September 30
2008
    At December 31
2007
 
       
 
               
Short-term debt
  $ 387       1,398  
Total debt*
  $ 22,100       21,687  
Minority interests
  $ 1,127       1,173  
Common stockholders’ equity
  $ 92,876       88,983  
Percent of total debt to capital**
    19 %     19  
Percent of floating-rate debt to total debt
    21 %     25  
   
* Total debt includes short-term and long-term debt, as shown on our consolidated balance sheet.
** Capital includes total debt, minority interests and common stockholders’ equity.
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 2008, we raised $729 million in proceeds from asset dispositions. During the first nine months, available cash was used to support our ongoing capital expenditures and investments program, repurchase shares of our common stock, provide loan financing to certain equity affiliates, pay dividends, and meet the funding requirements to FCCL Oil Sands Partnership. Total dividends paid on our common stock during the first nine months were $2,159 million. During the first nine months of 2008, cash and cash equivalents decreased $340 million to $1,116 million.
In addition to cash flows from operating activities and proceeds from asset sales, we rely on our cash balance, commercial paper and credit facility programs, and our shelf registration statements to support our short- and long-term liquidity requirements. The credit markets, including the commercial paper markets in the United States, have recently experienced adverse conditions. Although we have not been materially impacted by these conditions, continuing volatility in the credit markets may increase costs associated with issuing commercial paper or other debt instruments due to increased spreads over relevant interest rate benchmarks, or affect our, or third parties we seek to do business with, ability to access those markets. Notwithstanding these adverse market conditions, 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. Share repurchase levels for the remainder of 2008 will depend on market conditions and capital commitments.
Significant Sources of Capital
Operating Activities
During the first nine months of 2008, cash of $19,536 million was provided by operating activities, an 11 percent increase from cash from operations of $17,630 million in the corresponding period of 2007. Contributing to the increase were higher commodity prices in our E&P segment, partially offset by lower U.S. refining margins.
While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, natural gas and natural gas liquids, as well as refining and marketing margins. During the first nine months of 2008 and 2007, we benefited from favorable crude oil and natural gas

45


Table of Contents

prices. Prices and margins 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 of crude oil, natural gas and natural gas liquids 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 the timely and cost-effective development of those proved reserves. 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 experienced with 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, 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 experienced with refining margins.
Asset Sales
Proceeds from asset sales during the first nine months of 2008 were $729 million, compared with $3,057 million in the same period of 2007. Proceeds for both periods primarily reflect our ongoing efforts to dispose of assets that no longer fit into our strategic plans or those that could bring more value by being monetized in the near term.
Commercial Paper and Credit Facilities
At September 30, 2008, we had a $7.35 billion revolving credit facility, which expires in September 2012. The facility was reduced from $7.5 billion due to the bankruptcy of Lehman Commercial Paper Inc., one of the revolver participants. This facility may be used as direct bank borrowings, as support for the ConocoPhillips $7.35 billion commercial paper program, as support for the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, or as support for issuances of letters of credit totaling up to $750 million. The facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The credit agreement contains 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. At September 30, 2008 and December 31, 2007, we had no outstanding borrowings under the credit facility, but $40 million and $41 million, respectively, in letters of credit had been issued. Under the combined commercial paper programs, $1,519 million of commercial paper was outstanding at September 30, 2008, compared with $725 million at December 31, 2007.
At September 30, 2008, our primary funding source for short-term working capital needs was the ConocoPhillips $7.35 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. The ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program is used to fund commitments relating to the Qatargas 3 project. Since we had $1,519 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $5.8 billion in borrowing capacity under our revolving credit facility at September 30, 2008.
On October 1, 2008, we entered into a $2.5 billion 364-day bank facility to provide additional support to temporarily expand our commercial paper program to $9.85 billion. We expanded our commercial paper program to ensure adequate liquidity after the initial funding of our transaction with Origin Energy. See Note 21—Joint Venture with Origin Energy, in the Notes to Consolidated Financial Statements, for additional information.

46


Table of Contents

Shelf Registrations
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. Under this shelf, in May 2008 we issued notes consisting of $400 million of 4.40% Notes due 2013, $500 million of 5.20% Notes due 2018 and $600 million of 5.90% Notes due 2038. The proceeds from the offering were used to reduce commercial paper and for general corporate purposes.
We also have on file with the SEC a shelf registration statement under which ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding Company II, both wholly owned subsidiaries, could issue an indeterminate amount of senior debt securities, fully and unconditionally guaranteed by ConocoPhillips and ConocoPhillips Company.
Minority Interests
At September 30, 2008, we had outstanding $1,127 million of equity in less than wholly owned consolidated subsidiaries held by minority interest owners, including a minority interest of $505 million in Ashford Energy Capital S.A. The remaining minority interest amounts are primarily related to operating joint ventures we control. The largest of these, $602 million, was related to the Darwin LNG project located in northern Australia.
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, 2008, we were liable for certain contingent obligations under the following contractual arrangements:
    Qatargas 3: We own a 30 percent interest in Qatargas 3, an integrated project to produce and liquefy natural gas from Qatar’s North field. Our interest is held through a jointly owned company, Qatar Liquefied Gas Company Limited (3), for which we use the equity method of accounting. Qatargas 3 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 in 2010, all project loan facilities, including the ConocoPhillips loan facilities, will become nonrecourse to the project participants. At September 30, 2008, Qatargas 3 had $2.9 billion outstanding under all the loan facilities, of which ConocoPhillips provided $817 million, and an additional $67 million of accrued interest.
 
    Rockies Express Pipeline LLC: In June 2006, we issued a guarantee for 24 percent of $2.0 billion in credit facilities issued to Rockies Express Pipeline LLC (Rockies Express). Rockies Express intends to construct a natural gas pipeline across a portion of the United States. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $480 million, which could become payable if the credit facilities are fully utilized and Rockies Express fails to meet its obligations under the credit agreement. At September 30, 2008, Rockies Express had $854 million outstanding under the credit facilities, with our 24 percent guarantee equaling $205 million. In addition, we have a 24 percent guarantee on $600 million of Floating Rate Notes due 2009. It is anticipated that construction completion will be achieved in 2009, and refinancing will take place at that time, making the debt nonrecourse.

47


Table of Contents

    Keystone Oil Pipeline: We own a 50 percent equity interest in the Keystone Oil Pipeline (Keystone), a joint venture with TransCanada Corporation. Keystone plans to construct a crude oil pipeline originating in Alberta, with delivery points in Illinois and Oklahoma. In connection with certain planning and construction activities, agreements were put in place with third parties to guarantee the payments due under those agreements. Our maximum potential amount of future payments under those agreements is estimated to be $400 million, which could become payable if Keystone fails to meet its obligations under the agreements noted above and the obligations cannot otherwise be mitigated. Payments under the guarantees are contingent upon the partners not making necessary equity contributions into Keystone; therefore, it is considered unlikely that payments would be required. All but $15 million of the guarantees will terminate after construction is completed, currently estimated to occur in 2010.
 
      In addition to the above guarantee, in order to obtain long-term shipping commitments that would enable a pipeline expansion starting at Hardisty, Alberta, and extending to near Port Arthur, Texas, the Keystone owners entered into a 20-year guarantee in July 2008 to ship volumes for certain shippers to the Gulf Coast. Our maximum potential amount of future payments, or cost of volume delivery, under this guarantee is estimated to be $550 million, which could become payable if Keystone fails to meet its obligations under the agreements noted above and cannot otherwise be mitigated. This is considered unlikely as payment, or cost of volume delivery, is contingent upon the partners defaulting on their obligation to construct and operate in accordance with the terms of the agreement. In October 2008, we elected to exercise an option to reduce our equity interest from 50 percent to 20.01 percent. The change in equity will occur through a dilution mechanism, which is expected to gradually lower our ownership interest, as well as our guaranty obligation, until reaching 20.01 percent by the third quarter of 2009.
For additional information about guarantees, see Note 11—Guarantees, 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, 2008, was $22.1 billion, a slight increase from the balance at December 31, 2007.
In January 2008, we reduced our Floating Rate Five-Year Term Note due 2011 from $3 billion to $2 billion, with a subsequent reduction in June 2008 to $1.5 billion. In March 2008, we redeemed our $300 million 7.125% Debentures due 2028 at a premium of $8 million, plus accrued interest.
On January 3, 2007, we closed on a business venture with EnCana. As part of this transaction, we are obligated to contribute $7.5 billion, plus interest, over a ten-year period, which began in 2007, to the upstream business venture, FCCL, formed as a result of the transaction. 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, approximately $617 million is short-term and is included in the “Accounts payable—related parties” line on our September 30, 2008, consolidated balance sheet. The principal portion of these payments, which totaled $442 million in the first nine months of 2008, 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.

48


Table of Contents

At year-end 2007, approximately $10.1 billion remained authorized for share repurchases in 2008 for our share repurchase programs announced in 2007. During the first nine months of 2008, we repurchased 91.2 million shares of our common stock at a cost of $7.5 billion. Share repurchases have continued into the fourth quarter. Through the end of October we will have purchased approximately $8 billion in 2008 under our previously announced program. Share repurchase levels for the balance of the year will depend on market conditions and capital commitments.
In December 2005, we entered into a credit agreement with Qatargas 3, whereby we will provide loan financing of approximately $1.2 billion for the construction of a liquefied natural gas (LNG) train in Qatar. This financing will represent 30 percent of the project’s total debt financing. Through September 30, 2008, we had provided $817 million in loan financing, and an additional $67 million of accrued interest. See the “Off-Balance Sheet Arrangements” section for additional information on Qatargas 3.
In 2004, we finalized our transaction with Freeport LNG Development, L.P. (Freeport) to participate in a proposed LNG receiving terminal in Quintana, Texas. We entered into a credit agreement with Freeport to provide loan financing for the construction of the facility. The terminal became operational late in the second quarter of 2008 and in August 2008, when the loan was converted from a construction loan to a term loan, it consisted of $650 million in loan financing and $124 million of accrued interest. Freeport began making repayments in September 2008, and the loan balance outstanding at September 30, 2008, was $768 million.
In the fall of 2004, ConocoPhillips and LUKOIL agreed to the expansion of the Varandey terminal as part of our investment in the OOO Naryanmarneftegaz (NMNG) joint venture. We have an obligation to provide loan financing to Varandey Terminal Company for 30 percent of the costs of the terminal expansion, but we have no governance or ownership interest in the terminal. The terminal construction was completed in late second-quarter 2008, and the final loan amount was $330 million at current exchange rates, excluding accrued interest. Although repayments are not required to start until May 2010, Varandey used available cash to repay $7 million of interest in third-quarter 2008. The outstanding accrued interest at September 30, 2008, was $43 million at current exchange rates.
The long-term portion of our loans to Qatargas 3, Freeport and Varandey Terminal Company are included in the “Loans and advances—related parties” line on the balance sheet, while the short-term portion is in “Accounts and notes receivable—related parties.”

49


Table of Contents

Capital Spending
Capital Expenditures and Investments
                 
    Millions of Dollars  
    Nine Months Ended  
    September 30  
    2008     2007  
E&P
               
United States—Alaska
  $ 1,083       471  
United States—Lower 48
    2,887       2,085  
International
    4,733       4,339  
   
 
    8,703       6,895  
   
Midstream
    -       2  
   
R&M
               
United States
    1,092       617  
International
    455       135  
   
 
    1,547       752  
   
LUKOIL Investment
    -       -  
Chemicals
    -       -  
Emerging Businesses
    137       127  
Corporate and Other
    148       131  
   
 
  $ 10,535       7,907  
   
United States
  $ 5,210       3,306  
International
    5,325       4,601  
   
 
  $ 10,535       7,907  
   
E&P
Capital expenditures and investments for E&P during the first nine months of 2008 totaled $8.7 billion. The expenditures supported key exploration and development projects including:
    Significant U.S. lease acquisitions in the federal waters of the Chukchi Sea, offshore Alaska, as well as in the deepwater Gulf of Mexico.
 
    Alaska activities related to development drilling in the Greater Kuparuk Area, including West Sak; the Greater Prudhoe Bay Area; the Alpine field, including satellite field prospects; and the Cook Inlet Area; as well as exploration activities.
 
    Oil and natural gas developments in the Lower 48, including New Mexico, Texas, Louisiana, Oklahoma, Montana, North Dakota, Colorado, Wyoming, and offshore in the Gulf of Mexico.
 
    Investment in the West2East Pipeline LLC (West2East), a company holding a 100 percent interest in Rockies Express Pipeline LLC (Rockies Express).
 
    The development of the Surmont heavy-oil project, investments related to FCCL, and development of conventional oil and gas reserves, all in Canada.
 
    Development drilling and facilities projects in the Greater Ekofisk Area located in the Norwegian North Sea.
 
    The Britannia satellite developments in the U.K. North Sea.
 
    An integrated project to produce and liquefy natural gas from Qatar’s North field.
 
    The Kashagan field in the Caspian Sea, offshore Kazakhstan.
 
    Development of the Yuzhno Khylchuyu (YK) field in the northern part of Russia’s Timan-Pechora province through the NMNG joint venture with LUKOIL.
 
    The Peng Lai 19-3 development in China’s Bohai Bay.

50


Table of Contents

    The Gumusut-Kakap development offshore Sabah, Malaysia.
 
    Projects offshore Block B and onshore South Sumatra in Indonesia.
In July 2008, we announced the signing of an interim agreement with the Abu Dhabi National Oil Company (ADNOC) to develop the Shah gas field in Abu Dhabi. Final project agreements are targeted for year-end 2008. ADNOC will have a 60 percent interest and we will have a 40 percent interest in the project.
In October 2008, we closed on a transaction with Origin Energy, an integrated Australian energy company, to create a long-term Australasian natural gas business. We paid $5 billion at closing. See Note 21—Joint Venture with Origin Energy, in the Notes to Consolidated Financial Statements, for additional information.
R&M
Capital spending for R&M during the first nine months of 2008 totaled $1.5 billion and included projects to meet environmental standards and improve the operating integrity, safety and energy efficiency of processing units. Capital also was spent on pipeline development and refinery upgrade projects to increase crude oil capacity, expand conversion capability and increase clean product yield.
Major project activities in progress include:
    Expansion of a hydrocracker at the Rodeo facility of our San Francisco refinery.
 
    Investment in the Keystone Oil Pipeline.
 
    U.S. programs aimed at air emission reductions.

51


Table of Contents

Contingencies
Legal and Tax Matters
We accrue for non-income-tax-related contingencies when a loss is probable and the amounts can be reasonably estimated. 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. In the case of income-tax-related contingencies, we adopted Financial Accounting Standards Board (FASB) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48), effective January 1, 2007. FIN 48 requires 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.
Environmental
We are subject to the same numerous international, federal, state, and local environmental laws and regulations as other companies in the petroleum exploration and production, refining and crude oil and refined product marketing and transportation businesses. For a discussion of the most significant of these environmental laws and regulations, including those with associated remediation obligations, see the “Environmental” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 81 through 84 of our 2007 Annual Report on Form 10-K.
We, from time to time, receive requests for information or notices of potential liability from the Environmental Protection Agency and state environmental agencies alleging that 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, 2007, we reported we had been notified of potential liability under CERCLA and comparable state laws at 68 sites around the United States. At September 30, 2008, we reopened two sites and closed one of those two sites, resolved and closed four sites, and received two new notices of potential liability, leaving 67 unresolved sites where we have been notified of potential liability.
At September 30, 2008, our balance sheet included a total environmental accrual of $1,028 million, compared with $1,089 million at December 31, 2007. We expect to incur the majority of these expenditures within the next 30 years.
Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent 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 environmental laws and regulations.
NEW ACCOUNTING STANDARDS
In December 2007, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 141 (Revised), “Business Combinations” (SFAS No. 141(R)). This Statement will apply to all transactions in which an entity obtains control of one or more other businesses. In general, SFAS No. 141(R) requires the acquiring entity in a business combination to recognize the fair value of all the assets acquired and liabilities assumed in the transaction; establishes the acquisition date as the fair value measurement point; and modifies the disclosure requirements. This Statement applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. However, starting January 1, 2009, accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for prior business

52


Table of Contents

combinations will impact tax expense instead of impacting goodwill. We are currently evaluating the changes provided for in this Statement.
Also in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51,” which changes the classification of noncontrolling interests, sometimes called minority interests, in the consolidated financial statements. Additionally, this Statement establishes a single method of accounting for changes in a parent company’s ownership interest that do not result in deconsolidation and requires a parent company to recognize a gain or loss when a subsidiary is deconsolidated. This Statement is effective January 1, 2009, and will be applied prospectively with the exception of the presentation and disclosure requirements, which must be applied retrospectively for all periods presented. We are currently evaluating the impact of this Statement on our consolidated financial statements.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB No. 133.” This Statement expands the annual and interim disclosure requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” for derivative instruments within the scope of that Statement. We must adopt SFAS No. 161 no later than January 1, 2009, but it will not have any impact on our consolidated financial statements, other than the additional disclosures.
OUTLOOK
In E&P, we expect our fourth-quarter 2008 production to be higher than the third quarter of 2008. We anticipate full-year 2008 production to be slightly below 1.8 million BOE per day due to the impact of higher prices on production-sharing contracts and lost production associated with Hurricanes Gustav and Ike.
In R&M, we expect our crude oil capacity utilization rate in the fourth quarter of 2008 to be in the mid-90-percent range.

53


Table of Contents

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,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “should,” “will,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions.
We based the forward-looking statements relating to our operations on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you that these statements are not guarantees of future performance and involve risks, uncertainties and assumptions 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, natural gas and natural gas liquids prices, refining and marketing margins and margins for our chemicals business.
 
    Potential failure 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 oil and gas reserves and oil and gas 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 synthetic crude oil and chemicals products.
 
    Lack of, or disruptions in, adequate and reliable transportation for our crude oil, natural gas, natural gas liquids, 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 or terrorism.
 
    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, natural gas, natural gas liquids or refined product pricing, regulation, or taxation; other political, economic or diplomatic developments; and international monetary fluctuations.
 
    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.

54


Table of Contents

    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 factors set forth under the heading “Risk Factors” on pages 34 through 39 of our 2007 Annual Report on Form 10-K.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information about market risks for the nine months ended September 30, 2008, does not differ materially from that discussed under Item 7A in our 2007 Annual Report on Form 10-K.
Item 4. CONTROLS AND PROCEDURES
As of September 30, 2008, 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 the effectiveness of the design and operation 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, 2008.
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.

55


Table of Contents

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 those matters that arose during the third quarter of 2008 and any material developments with respect to matters previously reported in our 2007 Annual Report on Form 10-K or first and second 2008 Quarterly Reports on Form 10-Q.  While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were 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 Commission’s 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 and/or other reports required by permits or regulations, we occasionally report matters which could be subject to a request for stipulated penalties. If a specific request for stipulated penalties meeting the reporting threshold set forth in U.S. Securities and Exchange Commission 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.
New Matters
The South Coast Air Quality Management District (SCAQMD) conducted an audit of the Los Angeles refinery to assess compliance with applicable local, state, and federal regulations related to fugitive emissions. As a result of the audit, on August 28, 2008, SCAQMD issued five Notices of Violations (NOVs) alleging noncompliance. SCAQMD has not yet specified a penalty for these alleged violations. We are currently assessing the allegations and expect to work with SCAQMD toward a resolution of these NOVs.
Matters Previously Reported
On June 19, 2008, the Trainer refinery received a demand for stipulated penalties under the Refinery Enforcement Initiative Consent Decree in the amount of $110,000 for alleged violations associated with its leak detection and repair program. The penalty was paid in the third quarter of 2008.
In the fall of 2006, the Wood River refinery experienced two incidents where coker oil mist was released from the Distilling West coker. In a letter dated February 9, 2007, the state of Illinois demanded $50,000 for each release. During March 2008, we reached agreement with the state of Illinois to settle this matter for a cash penalty of $25,000 and performance of two local recycling events. The penalty was paid in the third quarter of 2008 and the recycling events have been completed.
On March 27, 2008, the Trainer refinery received a proposed Consent Assessment of Civil Penalty from the Pennsylvania Department of Environmental Protection (PADEP) for alleged air quality violations that occurred from 2002 to 2007. The assessment covers several categories of alleged air quality violations including emission events, air emissions inventory reporting, and violation of permit conditions. The proposed penalty is $129,424, and we are working with the PADEP to resolve this matter.
On December 16, 2005, the Bayway refinery experienced a hydrocarbon spill to the Rahway River and Arthur Kill. As a result of this spill, we signed an Order on Consent (Order) with the state of New York, and are also negotiating similar settlements with the state of New Jersey and the federal government. Under the final New York Order, we paid a penalty of $50,000 and conducted a beach cleanup. The proposed natural resources

56


Table of Contents

damages have been assessed at $70,000, with an additional $40,000 in federal and state oversight costs. We are working to resolve this matter.
On March 27, 2008, the Sweeny refinery received a Notice of Enforcement (NOE) from the Texas Commission on Environmental Quality (TCEQ) for an emissions event related to flaring that occurred on January 28, 2008. A penalty of $32,000 was submitted to the TCEQ in September 2008. This matter is subject to formal approval by the TCEQ Commissioners. We expect consideration of approval to occur in fourth quarter of 2008.
Item 1A. RISK FACTORS
Except for the risk factor set forth below, there have been no material changes to the risk factors disclosed in Item 1A of Part I in our Form 10-K for the year ended December 31, 2007 (Form 10-K). The risk factor set forth below was disclosed in our Form 10-K, but has been updated to provide additional information.
Worldwide political and economic developments could damage our operations and materially reduce our profitability and cash flows.
Local political and economic factors in international markets could have a material adverse effect on us. Approximately 63 percent of our crude oil, natural gas and natural gas liquids production in 2007 was derived from production outside the United States, and 59 percent of our proved reserves, as of December 31, 2007, were located outside the United States.
There are many risks associated with operations in international markets, including changes in foreign governmental policies relating to crude oil, natural gas, natural gas liquids or refined product pricing and taxation, other political, economic or diplomatic developments, changing political conditions and international monetary fluctuations. These risks include, among others:
    Political and economic instability, war, acts of terrorism and civil disturbances.
 
    The possibility that a foreign government may seize our property, with or without compensation, may attempt to renegotiate or revoke existing contractual arrangements and concessions, or may impose additional taxes or royalties.
 
    Fluctuating currency values, hard currency shortages and currency controls.
Continued hostilities and turmoil in the world and the occurrence or threat of future terrorist attacks could affect the economies of the United States and other developed countries. A lower level of economic activity could result in a decline in energy consumption, which could cause our revenues and margins to decline and limit our future growth prospects. More specifically, our energy-related assets may be at greater risk of future terrorist attacks than other possible targets. A direct attack on our assets, or assets used by us, could have a material adverse effect on our operations, financial condition, results of operations and prospects. These risks could lead to increased volatility in prices for crude oil, natural gas, natural gas liquids and refined products and could increase instability in the financial and insurance markets, making it more difficult for us to access capital and to obtain the insurance coverage that we consider adequate.
Actions of the U.S., state and local governments through tax and other legislation, executive order and commercial restrictions could reduce our operating profitability both in the United States and abroad. The U.S. government can prevent or restrict us from doing business in foreign countries. These restrictions and those of foreign governments have in the past limited our ability to operate in, or gain access to, opportunities in various countries. Actions by both the United States and host governments have affected operations significantly in the past and will continue to do so in the future.

57


Table of Contents

We also are exposed to fluctuations in foreign currency exchange rates. We do not comprehensively hedge our exposure to currency rate changes, although we may choose to selectively hedge certain working capital balances, firm commitments, cash returns from affiliates and/or tax payments. These efforts may not be successful.
Recent disruptions in the credit markets and concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices, both of which have contributed to a decline in our stock price and corresponding market capitalization. Further stock price or commodity price decreases in the fourth quarter could result in noncash impairments of long-lived assets and goodwill, as well as other-than-temporary noncash impairments of equity method investments. At December 31, 2007, we had $29.3 billion of goodwill recorded in conjunction with past business combinations and $731 million of intangible assets determined to have indefinite useful lives. Decreased returns on pension fund assets may also materially increase our pension funding requirements.
Likewise, the capital and credit markets have become increasingly volatile as a result of adverse conditions. If the capital and credit markets continue to experience volatility and the availability of funds remains limited, we, and third parties with whom we do business, may incur increased costs associated with issuing commercial paper and/or other debt instruments and this, in turn, could adversely affect our ability to advance our strategic plans as currently contemplated. In this context, changes in our debt rating could have a material adverse effect on our interest costs and financing sources. Our debt rating can be materially influenced by a number of factors including, but not limited to, acquisitions, investment decisions, and capital management activities.
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 as     Value of Shares  
            Average Price     Part of Publicly     that May Yet Be  
    Total Number of     Paid per Total     Announced Plans or     Purchased Under the  
Period   Shares Purchased *   Shares Purchased     Programs **   Plans or Programs **
 
                               
July 1-31, 2008
    9,747,673     $ 87.40       9,745,778     $ 4,236  
August 1-31, 2008
    10,133,449       80.84       10,129,914       3,417  
September 1-30, 2008
    10,885,253       75.39       10,883,073       2,597  
   
Total
    30,766,375     $ 80.99       30,758,765          
   
* Includes the repurchase of common shares from company employees in connection with the company’s broad-based employee incentive plans.
** On January 12, 2007, we announced a stock repurchase program that provided for the repurchase of up to $1 billion of the company’s common stock. On February 9, 2007, we announced plans to repurchase $4 billion of our common stock in 2007, including the $1 billion announced on January 12, 2007. On July 9, 2007, we announced plans to repurchase up to $15 billion of the company’s common stock through the end of 2008, which included the $2 billion remaining under the previously announced $4 billion program. Acquisitions for the share repurchase programs are made at management’s 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 plans are held as treasury shares.

58


Table of Contents

Item 5. OTHER INFORMATION
On October 29, 2008, following receipt of approval from Australia’s Foreign Investment Review Board, we closed on a transaction with Origin Energy to create a long-term Australasian natural gas business. The 50/50 joint venture will focus on coalbed methane production from the Bowen and Surat basins in Queensland, Australia, and liquefied natural gas processing and export sales. Under the terms of the transaction, we paid $5 billion at closing.
Our initial payment was funded through cash on hand as well as the issuance of approximately $4.9 billion in commercial paper borrowings under our commercial paper program as described in Management’s Discussion and Analysis of Financial Condition and Results of Operations under the section entitled “Liquidity and Capital Resources – Significant Sources of Capital – Commercial Paper and Credit Facilities” on page 46, which is incorporated herein by reference. Interest rates on commercial paper borrowings are subject to conditions of the short-term money markets.
Item 6. EXHIBITS
     
Exhibits    
 
   
3.1
  By-Laws of ConocoPhillips, as amended and restated on October 1, 2008 (incorporated by reference to Exhibit 99.2 to the Current Report of ConocoPhillips on Form 8-K filed on October 1, 2008; File No. 001-32395).
 
   
10.1
  Letter Agreement between ConocoPhillips and John E. Lowe, dated October 1, 2008 (incorporated by reference to Exhibit 99.1 to the Current Report of ConocoPhillips on Form 8-K filed on October 1, 2008; File No. 001-32395).
 
   
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.

59


Table of Contents

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/ Rand C. Berney
     
    Rand C. Berney
    Vice President and Controller
    (Chief Accounting and Duly Authorized Officer)
October 29, 2008

60