e10vq
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
     
þ
  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2005
OR
     
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                                          to                                                            
Commission file number 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 þ No o
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes þ No o
The registrant had 1,391,961,391 shares of common stock, $.01 par value, outstanding at June 30, 2005.
 
 

 


CONOCOPHILLIPS
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 Computation of Ratio of Earnings to Fixed Charges
 Certification of CEO pursuant to Rule 13a-14a
 Certification of CFO pursuant to Rule 13a-14a
 Certifications pursuant to Section 1350

 


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PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
     
 
Consolidated Income Statement
  ConocoPhillips
                                 
    Millions of Dollars  
    Three Months Ended     Six Months Ended  
    June 30     June 30  
    2005     2004*     2005     2004*  
Revenues
                               
Sales and other operating revenues(1)(2)
  $ 41,808       31,528       79,439       61,341  
Equity in earnings of affiliates
    701       322       1,754       591  
Other income
    105       36       339       171  
   
Total Revenues
    42,614       31,886       81,532       62,103  
   
 
                               
Costs and Expenses
                               
Purchased crude oil, natural gas and products(3)
    28,523       20,363       54,095       40,098  
Production and operating expenses
    2,147       1,840       4,099       3,505  
Selling, general and administrative expenses
    539       516       1,078       984  
Exploration expenses
    121       163       292       306  
Depreciation, depletion and amortization
    985       912       2,026       1,830  
Property impairments
    9       20       31       51  
Taxes other than income taxes(1)
    4,664       4,428       9,152       8,542  
Accretion on discounted liabilities
    41       41       89       77  
Interest and debt expense
    127       159       265       304  
Foreign currency transaction losses (gains)
    21       (33 )     18       (49 )
Minority interests
    5       7       15       21  
   
Total Costs and Expenses
    37,182       28,416       71,160       55,669  
   
Income from continuing operations before income taxes
    5,432       3,470       10,372       6,434  
Provision for income taxes
    2,301       1,457       4,318       2,818  
   
Income From Continuing Operations
    3,131       2,013       6,054       3,616  
Income (loss) from discontinued operations
    7       62       (4 )     75  
   
Net Income
  $ 3,138       2,075       6,050       3,691  
   
 
                               
Income Per Share of Common Stock (dollars)(4)
                               
Basic
                               
Continuing operations
  $ 2.24       1.46       4.33       2.63  
Discontinued operations
    .01       .04             .05  
   
Net Income
  $ 2.25       1.50       4.33       2.68  
   
 
                               
Diluted
                               
Continuing operations
  $ 2.21       1.44       4.26       2.60  
Discontinued operations
          .04             .05  
   
Net Income
  $ 2.21       1.48       4.26       2.65  
   
 
Dividends Paid Per Share of Common Stock (dollars)(4)
  $ .31       .22       .56       .43  
   
 
Average Common Shares Outstanding (in thousands)(4)
                               
Basic
    1,396,724       1,379,380       1,397,305       1,375,788  
Diluted
    1,419,288       1,398,022       1,420,022       1,393,528  
   
(1) Includes excise, value added and other similar taxes on petroleum products sales:
$            4,338       4,172       8,493       7,994  
 
(2) Includes sales related to purchases/sales with the same counterparty:
4,836       3,433       9,405       6,799  
 
(3) Includes purchases related to purchases/sales with the same counterparty:
4,781       3,393       9,278       6,681  
 
(4) Per-share amounts and average number of common shares outstanding in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend on June 1, 2005.
*Certain amounts reclassified to conform to current year presentation.
See Notes to Consolidated Financial Statements.

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Consolidated Balance Sheet
  ConocoPhillips
                 
    Millions of Dollars
    June 30     December 31  
    2005     2004  
Assets
               
Cash and cash equivalents
  $ 1,541       1,387  
Accounts and notes receivable (net of allowance of $55 million in 2005 and 2004)
    8,607       5,449  
Accounts and notes receivable—related parties
    403       3,339  
Inventories
    4,870       3,666  
Prepaid expenses and other current assets
    1,159       986  
Assets of discontinued operations held for sale
    167       194  
 
Total Current Assets
    16,747       15,021  
Investments and long-term receivables
    12,569       10,408  
Net properties, plants and equipment
    51,730       50,902  
Goodwill
    14,943       14,990  
Intangibles
    1,051       1,096  
Other assets
    429       444  
 
Total Assets
  $ 97,469       92,861  
 
 
               
Liabilities
               
Accounts payable
  $ 9,875       8,727  
Accounts payable—related parties
    623       404  
Notes payable and long-term debt due within one year
    354       632  
Accrued income and other taxes
    2,840       3,154  
Employee benefit obligations
    1,119       1,215  
Other accruals
    1,412       1,351  
Liabilities of discontinued operations held for sale
    105       103  
 
Total Current Liabilities
    16,328       15,586  
Long-term debt
    13,659       14,370  
Asset retirement obligations and accrued environmental costs
    3,741       3,894  
Deferred income taxes
    10,614       10,385  
Employee benefit obligations
    2,250       2,415  
Other liabilities and deferred credits
    2,365       2,383  
 
Total Liabilities
    48,957       49,033  
 
 
               
Minority Interests
    1,212       1,105  
 
Common Stockholders’ Equity
               
Common stock (2,500,000,000 shares authorized at $.01 par value) Issued (2005—1,449,747,674 shares; 2004—1,437,729,662 shares)* Par value*
    14       14  
Capital in excess of par*
    26,550       26,047  
Compensation and Benefits Trust (CBT) (at cost: 2005—47,116,283 shares; 2004—48,182,820 shares)
    (798 )     (816 )
Treasury stock (at cost: 2005—10,670,000 shares; 2004—0 shares)
    (576 )      
Accumulated other comprehensive income
    1,003       1,592  
Unearned employee compensation
    (292 )     (242 )
Retained earnings
    21,399       16,128  
 
Total Common Stockholders’ Equity
    47,300       42,723  
 
Total
  $ 97,469       92,861  
 
*2004 restated to reflect a two-for-one stock split effected as a 100 percent stock dividend on June 1, 2005.
 
See Notes to Consolidated Financial Statements.

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Consolidated Statement of Cash Flows
  ConocoPhillips
                 
    Millions of Dollars
    Six Months Ended
    June 30
    2005     2004  
Cash Flows From Operating Activities
               
Income from continuing operations
  $ 6,054       3,616  
Adjustments to reconcile income from continuing operations to net cash provided by continuing operations
               
Non-working capital adjustments
               
Depreciation, depletion and amortization
    2,026       1,830  
Property impairments
    31       51  
Dry hole costs and leasehold impairments
    156       192  
Accretion on discounted liabilities
    89       77  
Deferred taxes
    492       670  
Undistributed equity earnings
    (1,219 )     (278 )
Gain on asset dispositions
    (242 )     (88 )
Other
    (191 )     135  
Working capital adjustments
               
Decrease in aggregate balance of accounts receivable sold
    (480 )     (675 )
Decrease (increase) in other accounts and notes receivable
    221       (1,319 )
Increase in inventories
    (1,280 )     (710 )
Decrease (increase) in prepaid expenses and other current assets
    (176 )     44  
Increase in accounts payable
    1,509       1,045  
Decrease in taxes and other accruals
    (130 )     (263 )
 
Net cash provided by continuing operations
    6,860       4,327  
Net cash provided by (used in) discontinued operations
    (3 )     22  
 
Net Cash Provided by Operating Activities
    6,857       4,349  
 
 
Cash Flows From Investing Activities
               
Capital expenditures and investments, including dry hole costs
    (4,947 )     (3,065 )
Proceeds from asset dispositions
    308       1,354  
Long-term advances/loans to affiliates and other
    (119 )     (72 )
Collection of advances/loans to affiliates and other
    148       37  
 
Net cash used in continuing operations
    (4,610 )     (1,746 )
Net cash used in discontinued operations
          (2 )
 
Net Cash Used in Investing Activities
    (4,610 )     (1,748 )
 
 
               
Cash Flows From Financing Activities
               
Issuance of debt
    333        
Repayment of debt
    (1,332 )     (2,083 )
Issuance of company common stock
    263       207  
Repurchase of company common stock
    (576 )      
Dividends paid on common stock
    (780 )     (590 )
Other
    97       183  
 
Net cash used in continuing operations
    (1,995 )     (2,283 )
 
Net Cash Used in Financing Activities
    (1,995 )     (2,283 )
 
 
               
Effect of Exchange Rate Changes on Cash and Cash Equivalents
    (98 )     (4 )
 
 
               
Net Change in Cash and Cash Equivalents
    154       314  
Cash and cash equivalents at beginning of period
    1,387       490  
 
Cash and Cash Equivalents at End of Period
  $ 1,541       804  
 
See Notes to Consolidated Financial Statements.

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Notes to Consolidated Financial Statements
  ConocoPhillips
Note 1—Interim Financial Information
The financial information for the interim periods presented in the financial statements included in this report is unaudited and includes all known accruals and adjustments that, in the opinion of management, are 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. These interim financial statements should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and the consolidated financial statements and notes included in ConocoPhillips’ 2004 Annual Report on Form 10-K. Certain amounts in the 2004 financial statements included in this report on Form 10-Q have been reclassified to conform to the 2005 presentation.
Note 2—Accounting Policies
Revenue Recognition—Revenues associated with sales of crude oil, natural gas, natural gas liquids, petroleum and chemical products, and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry. Revenues include the sales portion of transactions commonly called buy/sell contracts, in which physical commodity purchases and sales are simultaneously contracted with the same counterparty to either obtain a different quality or grade of refinery feedstock supply, reposition a commodity (for example, where we enter into a contract with a counterparty to sell refined products or natural gas volumes at one location and purchase similar volumes at another location closer to our wholesale customer), or both.
At its June 2005, March 2005 and November 2004 meetings, the Emerging Issues Task Force (EITF) discussed Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” which addresses accounting issues that arise when one company both sells inventory to, and buys inventory from, another company in the same line of business. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate contractual arrangements, and the inventory purchased or sold may be in the form of raw material, work-in-progress, or finished goods. At issue is whether both the revenue and inventory/cost of sales should be recorded at fair value or whether the transactions should be classified as nonmonetary exchanges subject to the fair value exception of Accounting Principles Board (APB) Opinion No. 29, “Accounting for Nonmonetary Transactions.” Issue No. 04-13 encompasses our buy/sell transactions described above.
Buy/sell transactions have the same general terms and conditions as typical commercial contracts including: separate title transfer, transfer of risk of loss, separate gross billing and cash settlement for both the buy and sell sides of the transaction, and non-performance by one party does not relieve the other party of its obligation to perform (except in events of force majeure). Because buy/sell contracts have similar terms and conditions, we account for these purchase and sale transactions in the consolidated income statement as monetary transactions outside the scope of APB Opinion No. 29.

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Our buy/sell transactions are similar to the “barrel back” example used in EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-3.” Using the “barrel back” example, the EITF concluded that a company’s decision to display buy/sell-type transactions either gross or net on the income statement is a matter of judgment that depends on relevant facts and circumstances. We apply this judgment based on guidance in EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” (Issue No. 99-19), which provides indicators for when to report revenues and the associated cost of goods sold gross (i.e., on separate revenue and cost of sales lines in the income statement) or net (i.e., on the same line). The indicators for gross reporting in Issue No. 99-19 are consistent with many of the characteristics of buy/sell transactions, which support our accounting for buy/sell transactions.
We also believe that the conclusion reached by the Derivatives Implementation Group Statement 133 Implementation Issue No. K1, “Miscellaneous: Determining Whether Separate Transactions Should be Viewed as a Unit,” further supports our judgment that the purchase and sale contracts should be viewed as two separate transactions and not as a single transaction.
At its March 2005 meeting, the EITF reached a tentative conclusion that exchanges of finished goods for raw materials or work-in-progress within the same line of business should be recorded at fair value because these exchanges culminate the earnings process. At its June 2005 meeting, the EITF reached a tentative conclusion that purchases and sales of inventory with the same party in the same line of business should be combined and accounted for as nonmonetary exchanges in accordance with APB Opinion No. 29 if they are entered into “in contemplation” of one another. The inventory could be raw materials, work-in progress, or finished goods. The tentative conclusions were posted to the Financial Accounting Standards Board (FASB) Web site for public comment and are scheduled to be discussed again at the EITF’s September meeting.
Depending on the EITF’s final conclusions, it is possible that we could be required to decrease sales and other operating revenues for second-quarter 2005 and 2004 periods by $4,836 million and $3,433 million, respectively, and six-month 2005 and 2004 periods by $9,405 million and $6,799 million, respectively, with a related decrease in purchased crude oil, natural gas and products on our consolidated income statement. We believe any impact to income from continuing operations and net income would result from LIFO inventory and would not be material to our financial statements.
Our Commercial organization uses commodity derivative contracts (such as futures and options) in various markets to optimize the value of our supply chain and balance physical systems. In addition to cash settlement prior to contract expiration, exchange-traded futures contracts may also be settled by physical delivery of the commodity, providing another source of supply to meet our refinery requirements or marketing demand.
Revenues from the production of natural gas properties, in which we have an interest with other producers, are recognized based on the actual volumes we sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant. Revenues associated with royalty fees from licensed technology are recorded based either upon volumes produced by the licensee or upon the successful completion of all substantive performance requirements related to the installation of licensed technology.

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Stock-Based Compensation—Effective January 1, 2003, we voluntarily adopted the fair-value accounting method prescribed by Statement of Financial Accounting Standard (SFAS) No. 123, “Accounting for Stock-Based Compensation.” We used the prospective transition method, applying the fair-value accounting method and recognizing compensation expense equal to the fair-market value on the grant date for all stock options granted or modified after December 31, 2002.
Employee stock options granted prior to 2003 continue to be accounted for under APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. Because the exercise price of our employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is generally recognized under APB Opinion No. 25. The following table displays pro forma information as if provisions of SFAS No. 123 had been applied to all employee stock options granted:
                                 
    Millions of Dollars
    Three Months Ended   Six Months Ended
    June 30   June 30
    2005     2004     2005     2004  
Net income, as reported
  $ 3,138       2,075       6,050       3,691  
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects
    29       26       68       39  
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effects
    (30 )     (28 )     (69 )     (44 )
 
Pro forma net income
  $ 3,137       2,073       6,049       3,686  
 
Earnings per share*:
                               
Basic—as reported
  $ 2.25       1.50       4.33       2.68  
Basic—pro forma
    2.25       1.50       4.33       2.68  
Diluted—as reported
    2.21       1.48       4.26       2.65  
Diluted—pro forma
    2.21       1.48       4.26       2.65  
 
*Per-share amounts reflect a two-for-one stock split effected as a 100 percent stock dividend on June 1, 2005.
Note 3—Common Stock Split
On April 7, 2005, our Board of Directors declared a 2-for-1 split on our common stock effected in the form of a 100 percent stock dividend, payable June 1, 2005, to stockholders of record as of May 16, 2005. The total number of authorized common stock shares and associated par value per share was unchanged by this action. Shares and per-share information in the Consolidated Income Statement and Consolidated Balance Sheet presented in this report are on an after-split basis for all periods presented.
Note 4—Changes in Accounting Principles
In April 2005, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) FAS 19-1, “Accounting for Suspended Well Costs,” with application required in the first reporting period beginning after April 4, 2005. Under early application provisions, we adopted FSP FAS 19-1 effective January 1, 2005. The adoption of this standard did not impact our six-month 2005 net income. See Note 8—Properties, Plants and Equipment for additional information.

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In December 2004, the FASB issued FSP FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” and FSP 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004.” See Note 20—Income Taxes for additional information.
Consolidation of Variable Interest Entities (VIEs)
In February 2003, we entered into two 20-year agreements establishing separate guarantee facilities of $50 million for two liquefied natural gas ships that were under construction. Subject to the terms of the facilities, we will be required to make payments should the charter revenue generated by the ships fall below a certain specified minimum threshold, and we will receive payments to the extent that such revenues exceed those thresholds. Actual gross payments over the 20 years could exceed $100 million to the extent cash is received by us. In the first quarter of 2004, we determined the entity associated with the first ship was a VIE, but we were not the primary beneficiary and did not consolidate the entity. The second ship was delivered to its owner in July 2005. We are currently assessing the entity associated with this ship to determine if the entity is a VIE, and if we are the primary beneficiary. We currently account for these agreements as guarantees and contingent liabilities. See Note 12—Guarantees for additional information.
In July 2004, we announced the finalization of our transaction with Freeport LNG Development, L.P. (Freeport LNG) to participate in a LNG receiving terminal in Quintana, Texas. We have no ownership in Freeport LNG; however, we obtained a 50 percent interest in Freeport LNG GP, Inc., which serves as the general partner managing the venture. We agreed to provide loan financing to the venture. We determined Freeport LNG is a VIE, and that we are not the primary beneficiary. We account for our loan to Freeport LNG as a financial asset. Through June 30, 2005, we have provided $105 million in loan financing.
On June 30, 2005, ConocoPhillips and LUKOIL created the OOO Naryanmarneftegaz (NMNG) joint venture to develop resources in the northwest Arctic Russia. We determined that NMNG is a VIE because we and our related party, LUKOIL, have disproportionate interests. We have a 30 percent ownership interest with a 50 percent governance interest in the joint venture. We will use the equity method of accounting for this investment because we have determined we are not the primary beneficiary. Our funding for a 30 percent ownership interest amounted to $512 million.
Production from the NMNG joint-venture fields is expected to be transported via pipeline to LUKOIL’s existing terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international markets. LUKOIL is expected to complete an expansion of the terminal capacity in 2007, with ConocoPhillips participating in the design and financing of the terminal expansion. We determined that the terminal entity, Varandey Terminal Company, is also a VIE because we and our related party, LUKOIL, have disproportionate interests. We have an obligation to fund, through loans, 30 percent of the terminal’s costs, but we will have no governance interest in the terminal. We have determined we are not the primary beneficiary and will account for our loan to Varandey Terminal Company as a financial asset. Through June 30, 2005, we had provided $26 million in loan financing.

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Note 5—Discontinued Operations
Sales and other operating revenues and income (loss) from discontinued operations were as follows:
                               
    Millions of Dollars
    Three Months Ended   Six Months Ended
    June 30   June 30
    2005     2004     2005     2004
Sales and other operating revenues from discontinued operations
  $ 89       341       165       919
 
Income (loss) from discontinued operations before-tax
  $ 11       82       (6 )     103
Income tax expense (benefit)
    4       20       (2 )     28
 
Income (loss) from discontinued operations
  $ 7       62       (4 )     75
 
Assets of discontinued operations were primarily properties, plants and equipment, while liabilities of discontinued operations were primarily deferred taxes.
Note 6—Inventories
Inventories consisted of the following:
               
    Millions of Dollars
    June 30     December 31
    2005     2004
Crude oil and petroleum products
  $ 4,305       3,147
Materials, supplies and other
    565       519
 
 
  $ 4,870       3,666
 
Inventories valued on a last-in, first-out (LIFO) basis totaled $4,145 million and $2,988 million at June 30, 2005, and December 31, 2004, respectively. The remainder of our inventories is 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 $4,214 million and $2,220 million at June 30, 2005, and December 31, 2004, respectively.
Note 7—Investments and Long-Term Receivables
LUKOIL
During the second quarter of 2005, we increased our ownership interest in LUKOIL to 12.6 percent at June 30, 2005, from 11.3 percent at March 31, 2005.
At June 30, 2005, the book value of our ordinary share investment in LUKOIL was $3,638 million. Our 12.6 percent share of the net assets of LUKOIL was estimated to be $2,833 million. This basis difference is $805 million, a majority of which is being amortized on a unit-of-production basis. On June 30, 2005, the closing price of LUKOIL shares on the London Stock Exchange was $36.81 per share, making the aggregate total market value of our LUKOIL investment $3,936 million at that date.

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Duke Energy Field Services, LLC (DEFS)
On July 1, 2005, ConocoPhillips and Duke Energy Corporation (Duke) completed the restructuring of their respective ownership levels in DEFS, which resulted in DEFS becoming a jointly controlled venture, owned 50 percent by each company. This restructuring increased our ownership in DEFS to 50 percent from 30.3 percent through a series of direct and indirect transfers of certain Canadian Midstream assets from DEFS to Duke, a disproportionate cash distribution from DEFS to Duke from the sale of DEFS’ interest in TEPPCO Partners, L.P., and a combined payment by ConocoPhillips to Duke and DEFS of approximately $840 million. This payment was approximately $230 million higher than previously anticipated as our interest in the Empress plant in Canada was not included in the initial transaction as anticipated due to weather-related damages. However, the Empress plant was sold to Duke on August 1, 2005. We remain responsible for the repair of weather-related damages.
In the first-quarter 2005, as a part of equity earnings, we recorded our $306 million (after-tax) equity share of the financial gain from DEFS’ sale of the interest in TEPPCO.
Note 8—Properties, Plants and Equipment
Properties, plants and equipment included the following:
                 
    Millions of Dollars
    June 30     December 31  
    2005     2004  
Properties, plants and equipment
  $ 71,442       69,151  
Accumulated depreciation, depletion and amortization
    (19,712 )     (18,249 )
 
Net properties, plants and equipment
  $ 51,730       50,902  
 
Suspended Wells
In April 2005, the FASB issued FSP FAS 19-1, “Accounting for Suspended Well Costs” (FSP 19-1). This FASB Staff Position was issued to address whether there are circumstances that would permit the continued capitalization of exploratory well costs beyond one year, other than when further exploratory drilling is planned and major capital expenditures would be required to develop the project.
FSP 19-1 requires the continued capitalization of suspended well costs if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. All relevant facts and circumstances should be evaluated in determining whether a company is making sufficient progress assessing the reserves, and FSP 19-1 provides several indicators to assist in this evaluation. FSP 19-1 prohibits continued capitalization of suspended well costs on the chance that market conditions will change or technology will be developed to make the project economic. We adopted FSP 19-1 effective January 1, 2005. There was no impact to our consolidated financial statements from the adoption of this FSP.

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The following table reflects the net changes in suspended exploratory well costs during the first six months of 2005, as well as for the years 2004 and 2003.
                         
    Millions of Dollars
    Six Months              
    Ended     Year     Year  
    June 30, 2005     2004     2003  
Beginning balance at January 1
  $ 347       403       221  
Additions pending the determination of proved reserves
    64       142       217  
Reclassifications to proved properties
    (59 )     (112 )     (6 )
Charged to dry hole expense
    (82 )     (86 )     (29 )
 
Ending balance
  $ 270       347       403  
 
The following table provides an aging of suspended well balances at June 30, 2005, and December 31, 2004 and 2003:
                         
    Millions of Dollars
    June 30     December 31  
    2005     2004     2003  
Capitalized exploratory well costs that have been capitalized for a period of one year or less
  $ 136       142       217  
Capitalized exploratory well costs that have been capitalized for a period greater than one year
    134       205       186  
 
Ending balance
  $ 270       347       403  
 
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year
    14       16       12  
 
The following table provides a further aging of those exploratory well costs that have been capitalized for more than one year since the completion of drilling as of June 30, 2005:
                                         
    Millions of Dollars
    Suspended Since
Project   Total     2004     2003     2002     200l  
 
Alpine satellite—Alaska (1)
  $ 21                   21        
Kashagan—Republic of Kazakhstan (2)
    18             9             9  
Aktote—Republic of Kazakhstan (4)
    12             12              
Gumusut—Malaysia (4)
    12             12              
Foothills of Western Alberta—Canada (3)
    11       11                    
Su Tu Trang—Vietnam (2)
    10             10              
Eight projects of less than $10 million each (2)(4)
    50       8       19       14       9  
 
Total of 14 projects
  $ 134       19       62       35       18  
 
(1)   Development decisions pending infrastructure west of Alpine and construction authorization.
 
(2)   Additional appraisal wells planned.
 
(3)   Wells in various stages of testing/completion.
 
(4)   Appraisal drilling complete; costs being incurred to assess development.

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Note 9—Property Impairments
In the second quarter and six-month periods of 2005 and 2004, we recorded property impairments related to planned dispositions in our Midstream, Exploration and Production (E&P) and Refining and Marketing (R&M) segments. The amount of property impairments by segment were:
                               
    Millions of Dollars
    Three Months Ended   Six Months Ended
    June 30     June 30
    2005     2004     2005     2004
Exploration and Production
  $ 1       4       1       8
Midstream
    9       16       30       36
Refining and Marketing
    (1 )                 7
 
 
  $ 9       20       31       51
 
Note 10—Debt
At June 30, 2005, we had two revolving credit facilities totaling $5 billion, available for use either as direct bank borrowings or as support for the issuance of up to $5 billion in commercial paper, a portion of which may be denominated in other currencies (limited to euro 3 billion equivalent). The facilities included a $2.5 billion four-year facility expiring in October 2008 and a $2.5 billion five-year facility expiring in October 2009. In addition, the five-year facility may be used to support issuances of letters of credit totaling up to $750 million. The facilities are broadly syndicated among financial institutions and do not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The credit agreements do contain a cross-default provision relating to our, or any of our consolidated subsidiaries’, failure to pay principal or interest on other debt obligations of $200 million or more. At June 30, 2005, and December 31, 2004, we had no outstanding borrowings under these facilities, but $62 million in letters of credit had been issued. There was no commercial paper outstanding at June 30, 2005, compared with $544 million at December 31, 2004.
In March 2005, we redeemed our $400 million 3.625% Notes due 2007 at par plus accrued interest. In conjunction with this redemption, $400 million of interest rate swaps were cancelled.
Note 11—Contingencies and Commitments
In the case of all known contingencies, we accrue a liability when the loss is probable and the amount is reasonably estimable. 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.
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.

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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 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 consideration the likely effects of societal and economic factors. 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 also consider unasserted claims in our determination of environmental liabilities and we accrue them in the period that they become 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 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 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 those assumed 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 June 30, 2005, our balance sheet included a total environmental accrual of $1,020 million, compared with $1,061 million at December 31, 2004. 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.
Legal Proceedings—We apply our 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 trial settings, as well as the status and pace of settlement discussions in individual matters. Based on our professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, we believe that there is only a remote likelihood 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 financial statements.

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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, we have performance obligations that are secured by unused letters of credit and various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.
Note 12—Guarantees
At June 30, 2005, 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, no liability has been recorded related to the guarantee.
Construction Completion Guarantees
    We have a construction completion guarantee related to our share of debt held by Hamaca Holding LLC, used to construct the joint-venture project in Venezuela. The maximum potential amount of future payments under the guarantee is estimated to be $360 million, which could be called due if completion certification is not achieved by the Guaranteed Project Completion Date. The required 90-day Lender’s Reliability Test is currently underway and is a key to achieving project completion certification. If any issue arises during the 90-day Lender’s Reliability Test, we expect the Guaranteed Project Completion Date (currently October 1, 2005) to be extended to at least December 1, 2005, because of force majeure events that occurred during the construction period. In addition, other completion certification requirements remain outstanding at this time. These certification requirements may be resolved satisfactorily so that completion certification can be achieved; however, it is reasonably possible that the construction completion guarantee may not be fully released or the debt could be called due if the issues are not satisfactorily resolved.
Guarantees of Joint-Venture Debt
    At June 30, 2005, we had guarantees outstanding for our portion of joint-venture debt obligations, which have terms of up to 20 years. The maximum potential amount of future payments under the guarantees is approximately $240 million. Payment would be required if a joint venture defaults on its debt obligations. Included in these outstanding guarantees was $98 million associated with the Polar Lights Company joint venture in Russia.
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 that the venture does not have enough cash to cover operating expenses after setting aside the amount required for debt service over the next 19 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. If such an operational disruption did occur, MSLP has business interruption insurance and would be entitled to insurance proceeds subject to deductibles and certain limits.

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    In February 2003, we entered into two agreements establishing separate guarantee facilities for $50 million each for two liquefied natural gas 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 an aggregate of $100 million. Actual gross payments over the 20 years could exceed that amount to the extent cash is received by us. 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. In September 2003, the first ship was delivered to its owner and the second ship was delivered to its owner in July 2005.
 
    We have other guarantees with maximum future potential payment amounts totaling $350 million, which consist primarily of dealer and jobber loan guarantees to support our marketing business, a guarantee to fund the short-term cash liquidity deficits of a lubricants joint venture, a guaranteed revenue deficiency payment to a pipeline joint venture, two small construction completion guarantees, a guarantee supporting a lease assignment on a corporate aircraft, a guarantee associated with a pending lawsuit and guarantees of the lease payment obligations of a joint venture. The carrying amount recorded for these other guarantees, as of June 30, 2005, was $22 million. These guarantees generally extend up to 15 years and payment would only be required if the dealer, jobber or lessee goes into default, if the lubricants joint venture has cash liquidity issues, if the pipeline joint venture has revenue below a certain threshold, if construction projects are not completed, if guaranteed parties default on lease payments, or if an adverse decision occurs in the lawsuit.
Indemnifications
    Over the years, we have entered into various agreements to sell ownership interests in certain corporations and joint ventures and sold several assets, including FTC-mandated sales of downstream and midstream assets, certain exploration and production assets, and downstream retail and wholesale sites, giving rise to qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, environmental liabilities, underground storage tank repairs or replacements, 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, as of June 30, 2005, was $461 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 that 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 that 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 $344 million of environmental accruals for known contamination that is included in asset retirement obligations and accrued environmental costs at June 30, 2005. For additional information about environmental liabilities, see Note 11—Contingencies and Commitments.

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Note 13—Financial Instruments and Derivative Contracts
Commodity Derivative Contracts
In June 2005, we acquired two limited-term, fixed-volume overriding royalty interests in Utah and the San Juan Basin related to our production. As part of the acquisition, we assumed related commodity swaps with a negative fair value of $261 million at June 30, 2005. In late June and early July, we entered into additional commodity swaps to offset essentially all of the exposure from the assumed swaps.
Note 14—Comprehensive Income
ConocoPhillips’ comprehensive income was as follows:
                                 
    Millions of Dollars  
    Three Months Ended     Six Months Ended  
    June 30     June 30  
    2005     2004     2005     2004  
Net income
  $ 3,138       2,075       6,050       3,691  
After-tax changes in:
                               
Minimum pension liability adjustment
                (1 )     (1 )
Foreign currency translation adjustments
    (336 )     48       (592 )     24  
Unrealized loss on securities
          (1 )     (1 )      
Hedging activities
    5       5       5       5  
 
 
  $ 2,807       2,127       5,461       3,719  
 
Accumulated other comprehensive income in the equity section of the balance sheet included:
                 
    Millions of Dollars  
    June 30     December 31  
    2005     2004  
Minimum pension liability adjustment
  $ (68 )     (67 )
Foreign currency translation adjustments
    1,070       1,662  
Unrealized gain on securities
    5       6  
Deferred net hedging loss
    (4 )     (9 )
 
 
  $ 1,003       1,592  
 

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Note 15—Supplemental Cash Flow Information
                 
    Millions of Dollars  
    Six Months Ended  
    June 30  
    2005     2004  
Non-Cash Investing and Financing Activities
               
Investment in properties, plants and equipment of businesses through the assumption of non-cash liabilities*
  $ 261        
Fair market value of properties, plants and equipment received in a nonmonetary exchange transaction
    138        
 
Cash Payments
               
Interest
  $ 269       322  
Income taxes
    3,681       1,825  
 
*See Note 13—Financial Instruments and Derivative Contracts for additional information.
Note 16—Sales of Receivables
At December 31, 2004, certain credit card and trade receivables had been sold to a Qualifying Special Purpose Entity (QSPE) in a revolving-period securitization arrangement. This arrangement provides for us to sell, and the QSPE to purchase, certain receivables and for the QSPE to then issue beneficial interests of up to $1.2 billion to five bank-sponsored entities. At December 31, 2004, the QSPE had issued beneficial interests to the bank-sponsored entities of $480 million. All five bank-sponsored entities are multi-seller conduits with access to the commercial paper market and purchase interests in similar receivables from numerous other companies unrelated to us. We have no ownership interests, nor any variable interests, in any of the bank-sponsored entities, which we do not consolidate. Furthermore, except as discussed below, we do not consolidate the QSPE because it meets the requirements of SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” to be excluded from the consolidated financial statements of ConocoPhillips. The receivables transferred to the QSPE met the isolation and other requirements of SFAS No. 140 to be accounted for as sales and were accounted for accordingly.
By January 31, 2005, all of the beneficial interests held by the bank-sponsored entities had matured; therefore, in accordance with SFAS No. 140, the operating results and cash flows of the QSPE subsequent to this maturity have been consolidated with our financial statements, and the assets and liabilities of the QSPE are included in our June 30, 2005 balance sheet. The revolving-period securitization arrangement expires in September 2005, and at this time we have no plans to renew the arrangement.
Total cash flows received from and paid under the securitization arrangements were as follows:
                 
    Millions of Dollars  
    2005     2004  
Receivables sold at beginning of year
  $ 480       1,200  
New receivables sold
    960       5,025  
Cash collections remitted
    (1,440 )     (5,700 )
 
Receivables sold at June 30
  $       525  
 
Discounts and other fees paid on revolving balances
  $ 2       4  
 

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Note 17—Employee Benefit Plans
Pension and Postretirement Plans
                                                 
    Millions of Dollars  
    Pension Benefits     Other Benefits  
Three Months Ended   June 30     June 30  
    2005     2004     2005     2004  
    U.S.     Int’l.     U.S.     Int’l.                  
Components of Net Periodic Benefit Cost
                                               
Service cost
  $ 38       19       38       18       5       6  
Interest cost
    44       32       43       27       12       14  
Expected return on plan assets
    (32 )     (28 )     (26 )     (22 )            
Amortization of prior service cost
    1       2       1       1       5       5  
Recognized net actuarial loss (gain)
    13       8       13       10       (1 )     3  
 
Net periodic benefit costs
  $ 64       33       69       34       21       28  
 
                                                 
    Millions of Dollars  
    Pension Benefits     Other Benefits  
Six Months Ended   June 30     June 30  
    2005     2004     2005     2004  
    U.S.     Int’l.     U.S.     Int’l.                  
Components of Net Periodic Benefit Cost
                                               
Service cost
  $ 76       37       75       34       10       11  
Interest cost
    87       64       87       55       25       29  
Expected return on plan assets
    (63 )     (56 )     (52 )     (45 )            
Amortization of prior service cost
    2       4       2       3       10       10  
Recognized net actuarial loss (gain)
    27       17       26       20       (2 )     5  
 
Net periodic benefit costs
  $ 129       66       138       67       43       55  
 
We recognized pension settlement losses of $6 million in the first six months of 2004 due to high levels of lump-sum elections by new retirees in certain plans. Of this amount, $2 million was recognized in the second quarter of 2004.
During the first six months of 2005, we contributed $220 million to our domestic qualified and non-qualified benefit plans and $82 million to international qualified and non-qualified benefit plans.
At the end of 2004, we estimated that during 2005, we would contribute approximately $410 million to our domestic qualified and non-qualified plans and $140 million to our international benefits plans. We presently anticipate 2005 contributions to be $540 million to our domestic plans and $145 million to our international plans.

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Note 18—Related Party Transactions
Significant transactions with related parties were:
                                 
    Millions of Dollars  
    Three Months Ended     Six Months Ended  
    June 30     June 30  
    2005     2004     2005     2004  
Operating revenues (a)
  $ 1,833       1,273       3,478       2,359  
Purchases (b)
    1,496       1,101       2,652       2,125  
Operating expenses and selling, general and administrative expenses (c)
    198       198       444       334  
Net interest income (d)
    9       8       19       15  
 
(a)   Our Exploration and Production (E&P) segment sells natural gas to Duke Energy Field Services, LLC (DEFS) and crude oil to the Malaysian Refining Company Sdn. Bhd (Melaka), among others, for processing and marketing. Natural gas liquids, solvents and petrochemical feedstocks are sold to Chevron Phillips Chemical Company LLC (CPChem), gas oil and hydrogen feedstocks are sold to Excel Paralubes, and refined products are sold primarily to CFJ Properties and Getty Petroleum Marketing, Inc. (a subsidiary of LUKOIL). Also, we charge several of our affiliates including CPChem, MSLP, and Hamaca Holding LLC for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.
 
(b)   We purchase natural gas and natural gas liquids from DEFS and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchase upgraded crude oil from Petrozuata C.A. and refined products from Melaka. We also pay fees to various pipeline equity companies for transporting finished refined products and a price upgrade to MSLP for heavy crude processing. We purchase base oils and fuel products from Excel Paralubes for use in our refinery and specialty businesses.
 
(c)   We pay processing fees to various affiliates. Additionally, we pay crude oil transportation fees to pipeline equity companies.
 
(d)   We pay and/or receive interest to/from various affiliates including, prior to consolidation, the receivables securitization QSPE.
Elimination amounts related to our equity percentage share of profit or loss on the above transactions were not material.
Note 19—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 and markets crude oil, natural gas, and natural gas liquids on a worldwide basis. At June 30, 2005, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Nigeria, Venezuela, offshore Timor Leste in the Timor Sea, Australia, China, Indonesia, the United Arab Emirates, Vietnam, and Russia. The E&P segment’s U.S. and international operations are disclosed separately for reporting purposes.

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  2)   Midstream—Through both consolidated and equity interests, this segment gathers and processes natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in the United States, Canada and Trinidad. The Midstream segment includes our equity investment in DEFS. Through June 30, 2005, our equity ownership in DEFS was 30.3 percent. Effective July 1, 2005, we increased our ownership interest to 50 percent.
 
  3)   R&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. At June 30, 2005, we owned 12 refineries in the United States; one in the United Kingdom; one in Ireland; and had equity interests in one refinery in Germany, two in the Czech Republic, and one in Malaysia. The R&M segment’s U.S. and international operations are disclosed separately for reporting purposes.
 
  4)   LUKOIL Investment—This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia. In October 2004, we closed on a transaction to acquire 7.6 percent of LUKOIL’s shares held by the Russian government. During the remainder of 2004, we increased our ownership to 10.0 percent. During the first six months of 2005, we increased our ownership to 12.6 percent.
 
  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 encompasses the development of new businesses beyond our traditional operations. Emerging Businesses includes new technologies related to natural gas conversion into clean fuels and related products (gas-to-liquids), technology solutions, power generation, and emerging technologies.
Corporate and Other includes general corporate overhead; interest income and expense; discontinued operations; restructuring charges; certain eliminations; 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.

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Analysis of Results by Operating Segment
                                 
    Millions of Dollars  
    Three Months Ended     Six Months Ended  
    June 30     June 30  
    2005     2004     2005     2004  
Sales and Other Operating Revenues
                               
E&P
                               
United States
  $ 7,493       5,646       14,525       11,213  
International
    4,331       3,668       9,238       7,707  
Intersegment eliminations-U.S.
    (979 )     (697 )     (1,891 )     (1,359 )
Intersegment eliminations-international
    (995 )     (1,021 )     (1,992 )     (1,959 )
 
E&P
    9,850       7,596       19,880       15,602  
 
Midstream
                               
Total sales
    850       700       1,871       1,939  
Intersegment eliminations
    (197 )     (184 )     (427 )     (537 )
 
Midstream
    653       516       1,444       1,402  
 
R&M
                               
United States
    24,021       17,391       43,976       32,818  
International
    7,296       6,078       14,155       11,617  
Intersegment eliminations-U.S.
    (150 )     (97 )     (237 )     (192 )
Intersegment eliminations-international
    (4 )           (6 )     (1 )
 
R&M
    31,163       23,372       57,888       44,242  
 
LUKOIL Investment
                       
Chemicals
    4       3       7       7  
Emerging Businesses
    134       39       215       85  
Corporate and Other
    4       2       5       3  
 
Consolidated Sales and Other Operating Revenues
  $ 41,808       31,528       79,439       61,341  
 
Net Income (Loss)
                               
E&P
                               
United States
  $ 966       671       1,858       1,306  
International
    963       683       1,858       1,305  
 
Total E&P
    1,929       1,354       3,716       2,611  
 
Midstream
    68       42       453       97  
 
R&M
                               
United States
    936       734       1,506       1,137  
International
    174       84       304       145  
 
Total R&M
    1,110       818       1,810       1,282  
 
LUKOIL Investment
    148             258        
Chemicals
    63       46       196       85  
Emerging Businesses
    (8 )     (29 )     (16 )     (51 )
Corporate and Other
    (172 )     (156 )     (367 )     (333 )
 
Consolidated Net Income
  $ 3,138       2,075       6,050       3,691  
 

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    Millions of Dollars  
    June 30     December 31  
    2005     2004  
Total Assets
               
E&P
               
United States
  $ 16,676       16,105  
International
    27,288       26,481  
Goodwill
    11,043       11,090  
 
Total E&P
    55,007       53,676  
 
Midstream
    1,671       1,293  
 
R&M
               
United States
    20,735       19,180  
International
    6,036       5,834  
Goodwill
    3,900       3,900  
 
Total R&M
    30,671       28,914  
 
LUKOIL Investment
    3,738       2,723  
Chemicals
    2,352       2,221  
Emerging Businesses
    897       972  
Corporate and Other
    3,133       3,062  
 
Consolidated Total Assets
  $ 97,469       92,861  
 
Note 20—Income Taxes
Our effective tax rate for the second quarter and first six months of 2005 was 42 percent, compared with 42 percent and 44 percent for the same periods a year ago. While there was not a change in the effective tax rate for the second quarter of 2005, versus the same period in 2004, there was a lower proportion of income in higher tax rate jurisdictions that offset the effect of international tax law changes in 2004. The change in the effective tax rate for the first six months of 2005, versus the same period in 2004, was due to the utilization of capital loss carryforwards that previously had a full valuation allowance and a lower proportion of income in higher tax rate jurisdictions that more than offset the effect of international tax law changes in 2004. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.
One of the provisions of the American Jobs Creation Act of 2004 was a special deduction for qualifying manufacturing activities. While the legislation is still undergoing clarifications, under guidance from FSP 109-1, we included the estimated impact as a current benefit, which was not material to the company’s effective tax rate, and it did not have any impact on our assessment of the need for possible valuation allowances.
Another provision of the American Jobs Creation Act of 2004 was a special one-time provision allowing earnings of controlled foreign companies to be repatriated at a reduced tax rate. At this point, our investigation into our response to the legislation is preliminary, as we await additional and final clarifying legislation and guidance from the government. Because of the uncertainties related to this legislation, and as provided by FSP 109-2, we elected to defer our decision on potentially altering our current plans on permanently reinvesting in certain foreign subsidiaries and foreign corporate joint ventures. We expect final guidance to be issued and our investigation into our response to the legislation to be completed late in 2005.

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Note 21—New Accounting Standards and Emerging Issues
New Accounting Standards
In June 2005, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.” Issue No. 04-5 adopts a framework for evaluating whether the general partner (or general partners as a group) controls the partnership. The framework makes it more likely that a single general partner (or a general partner within a general partner group) would have to consolidate the limited partnership regardless of its ownership in the limited partnership. The new guidance was effective upon ratification for all newly-formed limited partnerships and for existing limited partnership agreements that are modified. The guidance is effective January 1, 2006, for existing limited partnership agreements that are not modified. We are reviewing Issue No. 04-5 to determine the impact, if any, on our financial statements.
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3.” Among other changes, this Statement requires retrospective application for voluntary changes in accounting principle, unless it is impractical to do so. Guidance is provided on how to account for changes when retrospective application is impractical. This Statement is effective on a prospective basis beginning January 1, 2006.
In March 2005, the FASB issued FASB Interpretation 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). This Interpretation clarifies that an entity is required to recognize a liability for a legal obligation to perform asset retirement activities when the retirement is conditional on a future event and if the liability’s fair value can be reasonably estimated. If the liability’s fair value cannot be reasonably estimated, then the entity must disclose (a) a description of the obligation, (b) the fact that a liability has not been recognized because the fair value cannot be reasonably estimated, and (c) the reasons why the fair value cannot be reasonably estimated. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. We are required to implement this Interpretation in the fourth quarter of 2005 and are currently studying its provisions to determine the impact, if any, on our financial statements.
In December 2004, the FASB issued SFAS No. 153, “Exchange of Nonmonetary Assets, an amendment of APB Opinion No. 29.” This amendment eliminates the APB Opinion No. 29 exception for fair value recognition of nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges of nonmonetary assets that do not have commercial substance. This Statement is effective on a prospective basis beginning July 1, 2005.
Also in December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” (SFAS 123(R)), which supercedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” which we adopted at the beginning of 2003. SFAS 123(R) prescribes the accounting for a wide range of share-based compensation arrangements, including share options, restricted share plans, performance-based awards, share appreciation rights, and employee share purchase plans, and generally requires the fair value of share-based awards to be expensed in the income statement. For ConocoPhillips, this Statement provided for an effective date of third-quarter 2005; however, in April 2005, the Securities and Exchange Commission approved a new rule that delayed the effective date until January 1, 2006. We plan to adopt the provisions of this Statement January 1, 2006. We are studying the provisions of this new pronouncement to determine the impact, if any, on our financial statements. For more information on our adoption of SFAS No. 123 and its effect on net income, see Note 2—Accounting Policies.

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In November 2004, the FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4.” This Statement requires that items, such as abnormal idle facility expense, excessive spoilage, double freight, and handling costs, be recognized as a current-period charge. We are required to implement this Statement in the first quarter of 2006. We are analyzing the provisions of this Statement to determine the effects, if any, on our financial statements.
In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity,” to address the balance sheet classification of certain financial instruments that have characteristics of both liabilities and equity. The Statement, already effective for contracts created or modified after May 31, 2003, was originally intended to become effective July 1, 2003, for all contracts existing at May 31, 2003. However, on November 7, 2003, the FASB issued an indefinite deferral of certain provisions of SFAS No. 150. We continue to monitor and assess the FASB’s modifications of SFAS No. 150, but do not anticipate any material impact to our financial statements.
Emerging Issues
At a November 2004 meeting and subsequent meetings, the EITF continued to discuss Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” which addresses accounting issues that arise when one company both sells inventory to and buys inventory from another company in the same line of business. For additional information, see the Revenue Recognition section of Note 2—Accounting Policies.

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Supplementary Information—Condensed Consolidating Financial Information
We have various cross guarantees among ConocoPhillips and ConocoPhillips Company with respect to publicly held debt securities. ConocoPhillips Company is wholly owned by ConocoPhillips. ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. Similarly, 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 and ConocoPhillips Company (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).
 
    All other non-guarantor subsidiaries of ConocoPhillips Company.
 
    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.
Effective January 1, 2005, ConocoPhillips Holding Company was merged into ConocoPhillips Company. Previously reported prior period information has been restated to reflect this reorganization of companies under common control.

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    Millions of Dollars  
    Three Months Ended June 30, 2005
            ConocoPhillips     All Other     Consolidating     Total  
Income Statement   ConocoPhillips     Company     Subsidiaries     Adjustments     Consolidated  
Revenues
                                       
Sales and other operating revenues
  $       28,832       12,976             41,808  
Equity in earnings of affiliates
    3,142       2,207       577       (5,225 )     701  
Other income
          97       8             105  
Intercompany revenues
    8       447       2,261       (2,716 )      
 
Total Revenues
    3,150       31,583       15,822       (7,941 )     42,614  
 
 
                                       
Costs and Expenses
                                       
Purchased crude oil, natural gas and products
          24,173       6,731       (2,381 )     28,523  
Production and operating expenses
          1,131       1,028       (12 )     2,147  
Selling, general and administrative expenses
    5       334       204       (4 )     539  
Exploration expenses
          25       96             121  
Depreciation, depletion and amortization
          321       664             985  
Property impairments
          (2 )     11             9  
Taxes other than income taxes
          1,519       3,255       (110 )     4,664  
Accretion on discounted liabilities
          9       32             41  
Interest and debt expense
    26       226       84       (209 )     127  
Foreign currency transaction losses (gains)
          6       15             21  
Minority interests
                5             5  
 
Total Costs and Expenses
    31       27,742       12,125       (2,716 )     37,182  
 
Income from continuing operations before income taxes
    3,119       3,841       3,697       (5,225 )     5,432  
Provision for income taxes
    (12 )     699       1,614             2,301  
 
Income from continuing operations
    3,131       3,142       2,083       (5,225 )     3,131  
Income (loss) from discontinued operations
    7       7             (7 )     7  
 
Net Income
  $ 3,138       3,149       2,083       (5,232 )     3,138  
 

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    Millions of Dollars
    Three Months Ended June 30, 2004
            ConocoPhillips     All Other     Consolidating     Total  
Income Statement   ConocoPhillips     Company     Subsidiaries     Adjustments     Consolidated  
Revenues
                                       
Sales and other operating revenues
  $       21,046       10,482             31,528  
Equity in earnings of affiliates
    2,011       1,292       274       (3,255 )     322  
Other income
          57       (21 )           36  
Intercompany revenues
    21       372       1,586       (1,979 )      
 
Total Revenues
    2,032       22,767       12,321       (5,234 )     31,886  
 
 
                                       
Costs and Expenses
                                       
Purchased crude oil, natural gas and products
          16,898       5,336       (1,871 )     20,363  
Production and operating expenses
          1,001       849       (10 )     1,840  
Selling, general and administrative expenses
    2       348       169       (3 )     516  
Exploration expenses
          32       131             163  
Depreciation, depletion and amortization
          277       635             912  
Property impairments
                20             20  
Taxes other than income taxes
          1,570       2,858             4,428  
Accretion on discounted liabilities
          9       32             41  
Interest and debt expense
    22       177       55       (95 )     159  
Foreign currency transaction losses (gains)
          7       (40 )           (33 )
Minority interests
                7             7  
 
Total Costs and Expenses
    24       20,319       10,052       (1,979 )     28,416  
 
Income from continuing operations before income taxes
    2,008       2,448       2,269       (3,255 )     3,470  
Provision for income taxes
    (5 )     437       1,025             1,457  
 
Income from continuing operations
    2,013       2,011       1,244       (3,255 )     2,013  
Income from discontinued operations
    62       62       31       (93 )     62  
 
Net Income
  $ 2,075       2,073       1,275       (3,348 )     2,075  
 

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    Millions of Dollars
    Six Months Ended June 30, 2005
            ConocoPhillips     All Other     Consolidating     Total  
Income Statement   ConocoPhillips     Company     Subsidiaries     Adjustments     Consolidated  
Revenues
                                       
Sales and other operating revenues
  $       53,458       25,981             79,439  
Equity in earnings of affiliates
    6,078       4,587       1,412       (10,323 )     1,754  
Other income
    (9 )     235       113             339  
Intercompany revenues
    18       941       4,281       (5,240 )      
 
Total Revenues
    6,087       59,221       31,787       (15,563 )     81,532  
 
 
                                       
Costs and Expenses
                                       
Purchased crude oil, natural gas and products
          44,931       13,873       (4,709 )     54,095  
Production and operating expenses
          2,155       1,968       (24 )     4,099  
Selling, general and administrative expenses
    9       675       407       (13 )     1,078  
Exploration expenses
          38       254             292  
Depreciation, depletion and amortization
          683       1,343             2,026  
Property impairments
                31             31  
Taxes other than income taxes
          3,067       6,195       (110 )     9,152  
Accretion on discounted liabilities
          18       71             89  
Interest and debt expense
    50       430       169       (384 )     265  
Foreign currency transaction losses (gains)
          5       13             18  
Minority interests
                15             15  
 
Total Costs and Expenses
    59       52,002       24,339       (5,240 )     71,160  
 
Income from continuing operations before income taxes
    6,028       7,219       7,448       (10,323 )     10,372  
Provision for income taxes
    (26 )     1,141       3,203             4,318  
 
Income from continuing operations
    6,054       6,078       4,245       (10,323 )     6,054  
Income (loss) from discontinued operations
    (4 )     (4 )           4       (4 )
 
Net Income
  $ 6,050       6,074       4,245       (10,319 )     6,050  
 

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    Millions of Dollars
    Six Months Ended June 30, 2004
            ConocoPhillips     All Other     Consolidating     Total  
Income Statement   ConocoPhillips     Company     Subsidiaries     Adjustments     Consolidated  
Revenues
                                       
Sales and other operating revenues
  $       40,460       20,881             61,341  
Equity in earnings of affiliates
    3,611       2,446       489       (5,955 )     591  
Other income
          51       120             171  
Intercompany revenues
    44       756       3,014       (3,814 )      
 
Total Revenues
    3,655       43,713       24,504       (9,769 )     62,103  
 
 
                                       
Costs and Expenses
                                       
Purchased crude oil, natural gas and products
          33,002       10,659       (3,563 )     40,098  
Production and operating expenses
          1,892       1,635       (22 )     3,505  
Selling, general and administrative expenses
    4       648       342       (10 )     984  
Exploration expenses
          50       256             306  
Depreciation, depletion and amortization
          517       1,313             1,830  
Property impairments
          7       44             51  
Taxes other than income taxes
          2,921       5,621             8,542  
Accretion on discounted liabilities
          19       58             77  
Interest and debt expense
    44       384       95       (219 )     304  
Foreign currency transaction losses (gains)
          1       (50 )           (49 )
Minority interests
                21             21  
 
Total Costs and Expenses
    48       39,441       19,994       (3,814 )     55,669  
 
Income from continuing operations before income taxes
    3,607       4,272       4,510       (5,955 )     6,434  
Provision for income taxes
    (9 )     661       2,166             2,818  
 
Income from continuing operations
    3,616       3,611       2,344       (5,955 )     3,616  
Income from discontinued operations
    75       75       90       (165 )     75  
 
Net Income
  $ 3,691       3,686       2,434       (6,120 )     3,691  
 

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    Millions of Dollars
    At June 30, 2005
            ConocoPhillips     All Other     Consolidating     Total  
Balance Sheet   ConocoPhillips     Company     Subsidiaries     Adjustments     Consolidated  
Assets
                                       
Cash and cash equivalents
  $       949       592             1,541  
Accounts and notes receivable
    782       14,138       17,941       (23,851 )     9,010  
Inventories
          3,358       1,512             4,870  
Prepaid expenses and other current assets
    9       501       649             1,159  
Assets of discontinued operations held for sale
          131       36             167  
 
Total Current Assets
    791       19,077       20,730       (23,851 )     16,747  
Investments and long-term receivables
    42,854       51,790       17,269       (99,344 )     12,569  
Net properties, plants and equipment
          17,408       34,322             51,730  
Goodwill
          14,943                   14,943  
Intangibles
          739       312             1,051  
Other assets
    17       151       261             429  
 
Total Assets
  $ 43,662       104,108       72,894       (123,195 )     97,469  
 
 
                                       
Liabilities and Stockholders’ Equity
                                       
Accounts payable
  $ 51       20,863       13,435       (23,851 )     10,498  
Notes payable and long-term debt due within one year
          267       87             354  
Accrued income and other taxes
          4       2,836             2,840  
Employee benefit obligations
          819       300             1,119  
Other accruals
    18       736       658             1,412  
Liabilities of discontinued operations held for sale
          (8 )     113             105  
 
Total Current Liabilities
    69       22,681       17,429       (23,851 )     16,328  
Long-term debt
    1,600       7,897       4,162             13,659  
Asset retirement obligations and accrued environmental costs
          875       2,866             3,741  
Deferred income taxes
          3,159       7,463       (8 )     10,614  
Employee benefit obligations
          1,681       569             2,250  
Other liabilities and deferred credits
    1,054       17,743       17,987       (34,419 )     2,365  
 
Total Liabilities
    2,723       54,036       50,476       (58,278 )     48,957  
Minority interests
          (8 )     1,220             1,212  
Retained earnings
    14,863       22,053       15,416       (30,933 )     21,399  
Other stockholders’ equity
    26,076       28,027       5,782       (33,984 )     25,901  
 
Total
  $ 43,662       104,108       72,894       (123,195 )     97,469  
 

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    Millions of Dollars
    At December 31, 2004
            ConocoPhillips     All Other     Consolidating     Total  
Balance Sheet   ConocoPhillips     Company     Subsidiaries     Adjustments     Consolidated  
Assets
                                       
Cash and cash equivalents
  $       879       508             1,387  
Accounts and notes receivable
    767       11,742       20,995       (24,716 )     8,788  
Inventories
          2,367       1,299             3,666  
Prepaid expenses and other current assets
    20       381       585             986  
Assets of discontinued operations held for sale
          150       44             194  
 
Total Current Assets
    787       15,519       23,431       (24,716 )     15,021  
Investments and long-term receivables
    38,194       46,325       15,980       (90,091 )     10,408  
Net properties, plants and equipment
          16,618       34,284             50,902  
Goodwill
          14,990                   14,990  
Intangibles
          747       349             1,096  
Other assets
    17       124       303             444  
 
Total Assets
  $ 38,998       94,323       74,347       (114,807 )     92,861  
 
 
                                       
Liabilities and Stockholders’ Equity
                                       
Accounts payable
  $ 62       17,443       16,342       (24,716 )     9,131  
Notes payable and long-term debt due within one year
    544       27       61             632  
Accrued income and other taxes
          360       2,794             3,154  
Employee benefit obligations
          646       569             1,215  
Other accruals
    20       488       843             1,351  
Liabilities of discontinued operations held for sale
          (10 )     113             103  
 
Total Current Liabilities
    626       18,954       20,722       (24,716 )     15,586  
Long-term debt
    1,994       8,163       4,213             14,370  
Asset retirement obligations and accrued environmental costs
          890       3,004             3,894  
Deferred income taxes
    (1 )     2,979       7,415       (8 )     10,385  
Employee benefit obligations
          1,809       606             2,415  
Other liabilities and deferred credits
    8       18,120       18,140       (33,885 )     2,383  
 
Total Liabilities
    2,627       50,915       54,100       (58,609 )     49,033  
Minority interests
          (6 )     1,111             1,105  
Retained earnings
    9,592       16,762       14,089       (24,315 )     16,128  
Other stockholders’ equity
    26,779       26,652       5,047       (31,883 )     26,595  
 
Total
  $ 38,998       94,323       74,347       (114,807 )     92,861  
 

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    Millions of Dollars
    Six Months Ended June 30, 2005
            ConocoPhillips     All Other     Consolidating     Total  
Statement of Cash Flows   ConocoPhillips     Company     Subsidiaries     Adjustments     Consolidated
Cash Flows From Operating Activities
                                       
Net cash provided by continuing operations
  $ 152       2,471       4,973       (736 )     6,860  
Net cash used in discontinued operations
          (3 )                 (3 )
 
Net Cash Provided by Operating Activities
    152       2,468       4,973       (736 )     6,857  
 
 
                                       
Cash Flows From Investing Activities
                                       
Capital expenditures and investments, including dry holes
          (1,894 )     (3,833 )     780       (4,947 )
Proceeds from asset dispositions
          81       227             308  
Long-term advances/loans to affiliates and other investments
          (2,062 )     (1,086 )     3,029       (119 )
Collection of advances/loans to affiliates
          432       78       (362 )     148  
 
Net cash used in continuing operations
          (3,443 )     (4,614 )     3,447       (4,610 )
Net cash used in discontinued operations
                             
 
Net Cash Used in Investing Activities
          (3,443 )     (4,614 )     3,447       (4,610 )
 
 
                                       
Cash Flows From Financing Activities
                                       
Issuance of debt
    1,895       1,390       77       (3,029 )     333  
Repayment of debt
    (952 )     (347 )     (393 )     360       (1,332 )
Issuance of company common stock
    263                         263  
Repurchase of company common stock
    (576 )                       (576 )
Dividends paid on common stock
    (780 )           (739 )     739       (780 )
Other
    (2 )           880       (781 )     97  
 
Net Cash Used in Financing
                                       
Activities
    (152 )     1,043       (175 )     (2,711 )     (1,995 )
 
 
                                       
Effect of Exchange Rate Changes on Cash and Cash Equivalents
          2       (100 )           (98 )
 
 
                                       
Net Change in Cash and Cash Equivalents
          70       84             154  
Cash and cash equivalents at beginning of year
          878       509             1,387  
 
Cash and Cash Equivalents at End
  $                                    
of Period
          948       593             1,541  
 

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    Millions of Dollars  
    Six Months Ended June 30, 2004
            ConocoPhillips     All Other     Consolidating     Total  
Statement of Cash Flows   ConocoPhillips     Company     Subsidiaries     Adjustments     Consolidated  
Cash Flows From Operating Activities
                                       
Net cash provided by (used in) continuing operations
  $ (267 )     2,516       2,929       (851 )     4,327  
Net cash provided by (used in) discontinued operations
          (319 )     341             22  
 
Net Cash Provided by (Used in) Operating Activities
    (267 )     2,197       3,270       (851 )     4,349  
 
 
                                       
Cash Flows From Investing Activities
                                       
Capital expenditures and investments, including dry holes
          (707 )     (2,464 )     106       (3,065 )
Proceeds from asset dispositions
          1,097       458       (201 )     1,354  
Long-term advances/loans to affiliates and other investments
          (1,817 )           1,745       (72 )
Collection of advances/loans to affiliates
    1,359       1,728             (3,050 )     37  
 
Net cash provided by (used in) continuing operations
    1,359       301       (2,006 )     (1,400 )     (1,746 )
Net cash provided by (used in) discontinued operations
          (2 )                 (2 )
 
Net Cash Provided by (Used in) Investing Activities
    1,359       299       (2,006 )     (1,400 )     (1,748 )
 
 
                                       
Cash Flows From Financing Activities
                                       
Issuance of debt
          1,668       77       (1,745 )      
Repayment of debt
    (709 )     (4,009 )     (415 )     3,050       (2,083 )
Issuance of company common stock
    207                         207  
Repurchase of company common stock
                             
Dividends paid on common stock
    (590 )           (851 )     851       (590 )
Other
                88       95       183  
 
Net Cash Used in Financing Activities
    (1,092 )     (2,341 )     (1,101 )     2,251       (2,283 )
 
 
                                       
Effect of Exchange Rate Changes on Cash and Cash Equivalents
          (5 )     1             (4 )
 
 
Net Change in Cash and Cash Equivalents
          150       164             314  
Cash and cash equivalents at beginning of year
          268       222             490  
 
Cash and Cash Equivalents at End of Period
  $       418       386             804  
 

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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,” “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 58.
RESULTS OF OPERATIONS
Unless otherwise indicated, discussion of results for the three- and six-month periods ending June 30, 2005, is based on a comparison with the corresponding periods of 2004.
Business Environment and Executive Overview
Favorable market conditions and consistent production and throughput resulted in net income and cash from operations in the second quarter of 2005 that increased 51 percent and 22 percent, respectively, over the second quarter of 2004. Net income in the second quarter of 2005 was $3,138 million, while cash from operations totaled $2,768 million. During the quarter, we funded our capital expenditures and investments program of $3,125 million, which included a $512 million investment to acquire a 30 percent economic interest in a joint venture with LUKOIL to explore for and develop oil and gas resources in the northern part of Russia’s Timan-Pechora province, as well as a $384 million increase of our investment in the ordinary shares of LUKOIL. We also used cash to repurchase $382 million of our common stock in the quarter and pay $432 million in dividends. As a result of the above activity, our cash balance decreased $880 million during the quarter.
In the first six months of 2005, net income was $6,050 million, while cash from operations totaled $6,857 million. This allowed us to fund our capital expenditures and investments of $4,947 million, including a $708 million increase in our LUKOIL investment. Cash from operations was also used in the six-month period of 2005 to reduce debt by $989 million, pay $780 million in dividends, and repurchase $576 million of our common stock.
The Exploration and Production segment had net income of $1,929 million in the second quarter of 2005, compared with $1,787 million in the first quarter of 2005 and $1,354 million in the second quarter of 2004. Industry crude oil prices for West Texas Intermediate continued to strengthen in the second quarter of 2005, increasing to $53.03 per barrel, or $3.33 per barrel higher than the first quarter 2005 average price per barrel. Average crude prices in the second quarter of 2005 were $14.72 per barrel higher than in the same period a year earlier. Price increases continued to be supported by strong fundamentals, including robust global consumption and concern over the ability of production to keep pace with demand. Heightened geopolitical risk lent further support to crude prices worldwide.

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Industry natural gas prices for Henry Hub during the second quarter of 2005 were up $0.47 to $6.74 per thousand cubic feet. Overall strength in natural gas prices was due primarily to higher crude oil prices and continued concerns regarding the adequacy of U.S. natural gas supplies.
The Refining and Marketing segment had net income of $1,110 million in the second quarter of 2005, compared with $700 million in the first quarter of 2005 and $818 million in the second quarter of 2004. Worldwide refining and marketing margins improved during the second quarter of 2005, compared with the first quarter of 2005. Industry U.S. refining margins strengthened due to the relatively higher demand for gasoline and distillates, concurrent with tight inventories and concern over adequate refining capacity to meet demand growth. This improvement was partially offset by narrowing light-heavy differentials. Worldwide marketing results improved as wholesale and retail prices began catching up with rising gasoline and diesel spot market prices, which rose, in part, as a consequence of the increase in crude oil prices.
Through the first six months of 2005, we continued to reduce debt, as well as increase stockholders’ equity through increased earnings. As a result, our debt-to-capital ratio was 22 percent at June 30, 2005, compared with 26 percent at December 31, 2004, and 34 percent at December 31, 2003.
On April 7, 2005, our Board of Directors declared a 2-for-1 stock split, which was paid on June 1, 2005, to stockholders of record as of May 16, 2005.
Consolidated Results
A summary of net income (loss) by business segment follows:
                                 
    Millions of Dollars  
    Three Months Ended     Six Months Ended  
    June 30     June 30  
    2005     2004     2005     2004  
Exploration and Production (E&P)
  $ 1,929       1,354       3,716       2,611  
Midstream
    68       42       453       97  
Refining and Marketing (R&M)
    1,110       818       1,810       1,282  
LUKOIL Investment
    148             258        
Chemicals
    63       46       196       85  
Emerging Businesses
    (8 )     (29 )     (16 )     (51 )
Corporate and Other
    (172 )     (156 )     (367 )     (333 )
 
Net income
  $ 3,138       2,075       6,050       3,691  
 
Net income was $3,138 million in the second quarter of 2005, compared with $2,075 million in the second quarter of 2004. For the June year-to-date periods, net income was $6,050 million in 2005 and $3,691 million in 2004. The improved results in both 2005 periods primarily were the result of:
    Higher crude oil, natural gas and natural gas liquids prices in the E&P segment.
 
    Improved refining margins in the R&M segment.
 
    Equity earnings from our investment in LUKOIL.

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In addition, the improved results in the six-month period of 2005 also reflected higher net gains on assets sales, including our equity share of DEFS’ sale of the general partner interest in TEPPCO Partners, LP (TEPPCO), as well as improved margins in the Chemicals segment.
See the “Segment Results” section for additional information on our segment results.
Income Statement Analysis
Sales and other operating revenues increased 33 percent in the second quarter of 2005 and 30 percent in the six-month period, while purchased crude oil, natural gas and products increased 40 percent and 35 percent in the same periods, respectively. These increases mainly were due to higher petroleum product prices and higher prices for crude oil, natural gas and natural gas liquids.
Equity in earnings of affiliates increased 118 percent in the second quarter of 2005, and 197 percent in the six-month period. The increases reflect equity earnings from our investment in LUKOIL, which was initiated in October 2004, as well as improved results from:
    Our chemicals joint venture, Chevron Phillips Chemical Company LLC, due to higher margins.
 
    Our heavy-oil joint ventures in Venezuela, due to higher crude oil prices and higher production volumes.
 
    Our joint-venture refinery in Melaka, Malaysia, due to improved refining margins in the Asia Pacific region.
 
    Our joint-venture delayed coker facilities at the Sweeny, Texas, refinery, Merey Sweeny, L.P., due to higher crude oil light-heavy differentials.
 
    Our midstream joint venture, DEFS, due to higher natural gas liquids prices.
In addition, the six-month period also included our equity share of DEFS’ gain on the sale of the TEPPCO general partnership interest.
Other income increased 192 percent in the second quarter of 2005, and 98 percent in the six-month period. The increases were primarily due to higher net gains on asset dispositions in the 2005 periods. Asset dispositions in the first six months of 2005 included the sale of our interest in coalbed methane acreage positions in the Powder River Basin in Wyoming, as well as our interests in Dixie Pipeline and Turcas Petrol A.S. Asset dispositions in the first six months of 2004 included our interest in the Petrovera heavy-oil joint venture in Canada.
Production and operating expenses increased 17 percent in the second quarter and first six months of 2005. The increases were primarily due to new fields in the E&P segment, including the Magnolia field in the Gulf of Mexico that began producing in late-2004, and the Bayu-Undan field in the Timor Sea, which began production in February 2004 and achieved full production in the third quarter of 2004; and higher maintenance and utility costs in the R&M segment, due to increased turnaround activity and higher natural gas costs.
Depreciation, depletion and amortization (DD&A) increased 8 percent in second quarter of 2005, and 11 percent in the six-month period. The increases primarily were due to new fields in the E&P segment, including the Magnolia field and the Bayu-Undan field.

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Segment Results
E&P
                               
    Millions of Dollars
    Three Months Ended     Six Months Ended
    June 30     June 30
    2005     2004     2005     2004
Net Income
                             
Alaska
  $ 572       397       1,104       800
Lower 48
    394       274       754       506
 
United States
    966       671       1,858       1,306
International
    963       683       1,858       1,305
 
 
  $ 1,929       1,354       3,716       2,611
 
                               
    Dollars Per Unit
Average Sales Prices
                             
Crude oil (per barrel)
                             
United States
  $ 48.21       36.22       45.86       34.45
International
    49.41       34.58       47.68       33.02
Total consolidated
    48.88       35.32       46.85       33.68
Equity affiliates*
    36.11       25.48       33.59       22.17
Worldwide
    46.93       34.17       45.04       32.27
Natural gas—lease (per thousand cubic feet)
                             
United States
    6.07       5.35       5.83       5.11
International
    5.16       3.81       5.10       3.96
Total consolidated
    5.53       4.43       5.38       4.42
Equity affiliates*
    .32       .31       .30       3.14
Worldwide
    5.52       4.43       5.38       4.42
 
                               
    Millions of Dollars
Worldwide Exploration Expenses
                             
General administrative; geological and geophysical; and lease rentals
  $ 73       58       136       114
Leasehold impairment
    18       63       38       83
Dry holes
    30       42       118       109
 
 
  $ 121       163       292       306
 

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    Three Months Ended     Six Months Ended
    June 30     June 30
    2005     2004     2005     2004
    Thousands of Barrels Daily
Operating Statistics
                             
Crude oil produced
                             
Alaska
    297       307       303       314
Lower 48
    63       52       62       52
 
United States
    360       359       365       366
European North Sea
    255       276       261       279
Asia Pacific
    88       88       98       86
Canada
    23       25       23       26
Other areas
    54       61       54       61
 
Total consolidated
    780       809       801       818
Equity affiliates*
    123       104       122       109
 
 
    903       913       923       927
 
 
                             
Natural gas liquids produced*
                             
Alaska
    16       23       20       25
Lower 48
    31       26       29       25
 
United States
    47       49       49       50
European North Sea
    12       13       13       13
Asia Pacific
    9       4       13       2
Canada
    10       10       10       10
Other areas
    2       3       2       3
 
 
    80       79       87       78
 
                               
    Millions of Cubic Feet Daily
Natural gas produced**
                             
Alaska
    148       147       166       166
Lower 48
    1,195       1,226       1,182       1,229
 
United States
    1,343       1,373       1,348       1,395
European North Sea
    1,009       1,124       1,065       1,162
Asia Pacific
    336       284       331       295
Canada
    422       437       420       432
Other areas
    81       81       78       73
 
Total consolidated
    3,191       3,299       3,242       3,357
Equity affiliates*
    7       4       7       6
 
 
    3,198       3,303       3,249       3,363
 
                               
    Thousands of Barrels Daily
Mining operations
                             
Syncrude produced
    21       20       18       22
 
 
*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.

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The E&P segment explores for, produces 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 June 30, 2005, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Nigeria, Venezuela, offshore Timor Leste in the Timor Sea, Australia, China, Indonesia, the United Arab Emirates, Vietnam, and Russia.
Net income for the E&P segment increased 42 percent in the second quarter and first six months of 2005. The increase in both periods was primarily due to higher crude oil prices and, to a lesser extent, higher natural gas and natural gas liquids prices. Higher prices were partially offset by higher production taxes, reduced foreign currency exchange benefits, and a benefit in the 2004 periods from Canadian tax law changes. See the Business Environment and Executive Overview section for our view of the factors that helped support crude oil and natural gas prices during the second quarter of 2005.
U.S. E&P
Net income from our U.S. E&P operations increased 44 percent in the second quarter of 2005, and 42 percent in the six-month period. Both increases reflect higher crude oil, natural gas and natural gas liquids prices. Higher prices were partially offset by increased production taxes and higher depreciation, depletion and amortization resulting from new producing fields. In addition the six-month period of 2005 reflects increased gains from asset dispositions.
U.S. E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 631,000 BOE per day in the second quarter of 2005, down slightly from 637,000 BOE per day in the second quarter of 2004. The decrease reflects unplanned maintenance, the impact of asset dispositions, and field production declines, mostly mitigated by new production from the Magnolia field in the Gulf of Mexico and increased production resulting from the Alpine expansion project on the western North Slope of Alaska.
International E&P
Net income from our international E&P operations increased 41 percent in the second quarter of 2005, and 42 percent in the six-month period. Both increases reflect higher crude oil, natural gas and natural gas liquids prices, as well as higher natural gas liquids volumes. Higher prices were partially offset by reduced foreign currency exchange benefits, a benefit in the 2004 periods from Canadian tax law changes, and increased costs associated with new production. In addition the six-month period of 2005 reflects lower gains from asset dispositions and increased maintenance costs primarily associated with a turnaround of Syncrude operations in Canada.
International E&P production averaged 885,000 BOE per day in the second quarter of 2005, down 2 percent from 906,000 BOE per day in the second quarter of 2004. Production was favorably impacted in 2005 by the Bayu-Undan field, the Hamaca project, and the Belanak field. At the Bayu-Undan field in the Timor Sea, second-quarter 2005 production was higher than in the same period of 2004 when production was still ramping up, despite a planned six-week shutdown for maintenance in the second quarter of 2005. At the Hamaca project in Venezuela, production increased in late 2004 with the startup of a heavy-oil upgrader. At the Belanak field offshore Indonesia, production began in late 2004. These increases in production were more than offset by the impact of asset dispositions, field production declines, and maintenance.

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Midstream
                                 
    Three Months Ended   Six Months Ended
    June 30   June 30
    2005   2004   2005   2004
    Millions of Dollars
Net income*
  $   68       42       453       97
 
*Includes DEFS-related net income:
  $   51       33       410       66
                                 
    Dollars Per Barrel
Average Sales Prices
                               
U.S. natural gas liquids*
                               
Consolidated
    $ 32.49       26.42       32.22       26.05
Equity affiliates
      31.33       25.61       30.97       25.21
 
 
*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*
      183       174       187       195
Natural gas liquids fractionated**
      186       187       199       204
 
 
*Includes our share of equity affiliates, except LUKOIL, which is reported in the LUKOIL Investment segment.
 
**Excludes DEFS.
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 equity investment in Duke Energy Field Services, LLC (DEFS), as well as our other natural gas gathering and processing operations, and natural gas liquids fractionation and marketing businesses, primarily in the United States, Canada and Trinidad. Through June 30, 2005, our equity ownership in DEFS was 30.3 percent. Effective July 1, 2005, we increased our ownership interest to 50 percent.
Net income from the Midstream segment increased 62 percent in the second quarter of 2005, and 367 percent in the six-month period. The improvement in both periods reflects higher natural gas liquids prices, which resulted in improved earnings from DEFS, as well as our other Midstream operations, partially offset by asset dispositions in 2004. In addition, the six-month 2005 results included our share of a gain from DEFS’ sale of its general partnership interest in TEPPCO. Our share of this gain, reflected in equity earnings, was $306 million on an estimated after-tax basis.
On July 1, 2005, ConocoPhillips and Duke Energy Corporation (Duke) completed the restructuring of their respective ownership levels in DEFS, which resulted in DEFS becoming a jointly controlled venture, owned 50 percent by each company. This restructuring increased our ownership in DEFS to 50 percent from 30.3 percent through a series of direct and indirect transfers of certain Canadian Midstream assets from DEFS to Duke, a disproportionate cash distribution from DEFS to Duke from the sale of DEFS’ interest in TEPPCO, and a combined payment by ConocoPhillips to Duke and DEFS of approximately $840 million. This payment was approximately $230 million higher than previously anticipated as our

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interest in the Empress plant in Canada was not included in the initial transaction as anticipated due to weather-related damages. However, the Empress plant was sold to Duke on August 1, 2005. We remain responsible for the repair of weather-related damages.
The restructuring is expected to have the effect of significantly reducing the favorable basis difference in our investment in DEFS which, in turn, will significantly reduce the basis difference amortization reported in equity method earnings.

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R&M
                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
    2005     2004     2005     2004  
    Millions of Dollars  
Net Income
                               
United States
  $ 936       734       1,506       1,137  
International
    174       84       304       145  
 
 
  $ 1,110       818       1,810       1,282  
 
                                 
    Dollars Per Gallon  
U.S. Average Sales Prices*
                               
Automotive gasoline
                               
Wholesale
  $ 1.67       1.40       1.56       1.28  
Retail
    1.85       1.61       1.70       1.47  
Distillates—wholesale
    1.66       1.17       1.57       1.09  
 
                                 
    Thousands of Barrels Daily  
Operating Statistics
                               
Refining operations**
                               
United States
                               
Rated crude oil capacity
    2,182       2,168       2,178 ***     2,168  
Crude oil runs
    2,133       2,119       2,046       2,112  
Capacity utilization (percent)
    98 %     98       94       97  
Refinery production
    2,349       2,300       2,247       2,273  
International
                               
Rated crude oil capacity
    428       447       428       447  
Crude oil runs
    402       309       415       359  
Capacity utilization (percent)
    94 %     69       97       80  
Refinery production
    410       318       427       364  
Worldwide
                               
Rated crude oil capacity
    2,610       2,615       2,606 ***     2,615  
Crude oil runs
    2,535       2,428       2,461       2,471  
Capacity utilization (percent)
    97 %     93       94       94  
Refinery production
    2,759       2,618       2,674       2,637  
 
Petroleum products outside sales
                               
United States
                               
Automotive gasoline
    1,426       1,328       1,364       1,321  
Distillates
    680       538       662       554  
Aviation fuels
    214       191       206       185  
Other products
    566       573       514       545  
 
 
    2,886       2,630       2,746       2,605  
International
    477       440       486       472  
 
 
    3,363       3,070       3,232       3,077  
 
*Excludes excise taxes.
 
**Includes ConocoPhillips’ 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 period. Actual capacity at June 30, 2005, was 2,182,000 and 2,610,000 barrels per day for the
United States and worldwide, respectively.

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The R&M segment’s operations encompass refining crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels), buying and selling crude oil and petroleum products, and transporting, distributing and marketing petroleum products. R&M has operations in the United States, Europe and Asia Pacific.
Net income from the R&M segment increased 36 percent in the second quarter of 2005, and 41 percent in the six-month period. Both increases were primarily due to higher worldwide refining margins. See the Business Environment and Executive Overview section for our view of the factors that supported the improved refining margins during the second quarter of 2005. In addition to refining margins, R&M benefited from improved U.S. marketing margins in the second quarter of 2005, higher refinery production volumes, and net gains from asset sales. These factors were partially offset by increased maintenance turnaround costs, as well as higher utility expenses.
U.S. R&M
Net income from our U.S. R&M operations increased 28 percent in the second quarter of 2005, and 32 percent in the six-month period. Both increases mainly were the result of higher refining margins. In addition to refining margins, the U.S. R&M operations benefited from improved marketing margins and higher refinery production volumes in the second quarter of 2005. These factors were partially offset by increased maintenance turnaround costs, as well as higher utility expenses.
Our U.S. refining capacity utilization rate was 98 percent in the second quarter of 2005, the same as in the corresponding quarter of 2004. Effective April 1, 2005, we increased the crude oil processing capacity at our San Francisco refinery by 9,000 barrels per day as a result of a project implementation related to clean fuels.
International R&M
Net income from our international R&M operations increased 107 percent in the second quarter of 2005, and 110 percent in the six-month period. Both increases were primarily due to higher refining margins, as well as improved refinery production volumes and net gains on asset sales. These factors were partially offset by negative foreign currency exchange impacts.
Our international refining capacity utilization rate was 94 percent in the second quarter of 2005, compared with 69 percent in the second quarter of 2004. The second-quarter 2004 rate reflects maintenance turnarounds at most of our international refineries, whereas in 2005 only the Humber refinery was in turnaround.
LUKOIL Investment
                                 
    Millions of Dollars  
    Three Months Ended     Six Months Ended  
    June 30     June 30  
    2005     2004     2005     2004  
         
Net income
  $ 148             258        
 
 
Operating Statistics*
                               
Net crude oil production (thousands of barrels daily)
    215             203        
Net natural gas production (millions of cubic feet daily)
    50             58        
Net refinery crude processed (thousands of barrels daily)
    102             97        
 
*Represents our net share of our estimate of LUKOIL’s production and processing.

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This 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. In October 2004, we purchased 7.6 percent of LUKOIL’s ordinary shares held by the Russian government and during the remainder of 2004, we increased our ownership interest to 10.0 percent. During the first six months of 2005, we expended $708 million to further increase our ownership interest to 12.6 percent. Purchase of LUKOIL shares continued into the third quarter.
In addition to our estimate of our equity share of LUKOIL’s earnings, this segment also reflects the amortization of the basis difference between our equity interest in the net assets of LUKOIL and the historical cost of our investment in LUKOIL and includes the costs associated with the employees seconded to LUKOIL.
Because LUKOIL’s accounting cycle close and preparation of U.S. GAAP financial statements occurs subsequent to our accounting cycle close, our equity earnings and statistics for our LUKOIL investment are an estimate, based on market indicators, historical production trends of LUKOIL, and other factors. Any difference between the estimate and actual results will be recorded in a subsequent period. This estimate-to-actual adjustment will be a recurring component of future period results. This adjustment to our estimate of LUKOIL’s fourth quarter 2004 and first quarter 2005 results in the second quarter of 2005 was not material.
Chemicals
                                 
    Millions of Dollars  
    Three Months Ended     Six Months Ended  
    June 30     June 30  
    2005     2004     2005     2004  
         
Net income
  $ 63       46       196       85  
 
The Chemicals segment consists of our 50 percent interest in Chevron Phillips Chemical Company LLC (CPChem), which we account for using the equity method of accounting. CPChem uses natural gas liquids and other feedstocks to produce petrochemicals such as ethylene, propylene, styrene, benzene, and paraxylene. These products are then marketed and sold, or used as feedstocks to produce plastics and commodity chemicals, such as polyethylene, polystyrene and cyclohexane.
Net income from the Chemicals segment increased 37 percent in the second quarter of 2005, and 131 percent in the six-month period. Results for the second quarter reflect improved ethylene and polyethylene margins and lower maintenance turnaround costs, partially offset by lower benzene margins and higher utility costs. The improved results for the six-month period was primarily due to higher ethylene and polyethylene margins, partially offset by higher utility costs.

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Emerging Businesses
                                 
    Millions of Dollars  
    Three Months Ended     Six Months Ended  
    June 30     June 30  
    2005     2004     2005     2004  
         
Net Income (Loss)
                               
Technology solutions
  $ (4 )     (4 )     (6 )     (8 )
Gas-to-liquids
    (7 )     (7 )     (14 )     (16 )
Power
    9       (16 )     11       (20 )
Other
    (6 )     (2 )     (7 )     (7 )
 
 
  $ (8 )     (29 )     (16 )     (51 )
 
The Emerging Businesses segment includes the development of new businesses outside our traditional operations. These activities include gas-to-liquids (GTL) operations, power generation, technology solutions such as sulfur removal technologies, and emerging technologies, such as renewable fuels and emission management technologies.
The Emerging Businesses segment incurred net losses of $8 million and $16 million in the second quarter and first six months of 2005, respectively, compared with net losses of $29 million and $51 million in the corresponding periods of 2004. The improved results in both periods reflect that the Immingham power plant was fully operational throughout the first six months of 2005, but was completing construction and commissioning activities during the corresponding periods of 2004.
Corporate and Other
                                 
    Millions of Dollars  
    Three Months Ended     Six Months Ended  
    June 30     June 30  
    2005     2004     2005     2004  
         
Net Income (Loss)
                               
Net interest
  $ (84 )     (143 )     (185 )     (256 )
Corporate general and administrative expenses
    (46 )     (52 )     (104 )     (100 )
Discontinued operations
    7       62       (4 )     75  
Merger-related costs
                      (14 )
Other
    (49 )     (23 )     (74 )     (38 )
 
 
  $ (172 )     (156 )     (367 )     (333 )
 
After-tax net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest decreased 41 percent in the second quarter of 2005, and 28 percent in the six-month period. The decreases were primarily due to lower average debt levels and an increased amount of interest income, partially offset by a lower amount of interest being capitalized in the 2005 periods.
After-tax corporate general and administrative expenses decreased 12 percent in the second quarter of 2005, while they increased 4 percent in the six-month period. The changes in both periods primarily reflect fluctuations in compensation and benefit costs.
Results from discontinued operations reflect asset dispositions completed during 2004.

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Beginning with the second quarter of 2004, we no longer separately identify merger-related costs because these activities have been substantially completed.
The category “Other” consists primarily of items not directly associated with the operating segments on a stand-alone basis, including certain foreign currency transaction gains and losses, and environmental costs associated with sites no longer in operation. Results from Other were lower in both 2005 periods due to unfavorable foreign currency transactions, higher environmental accruals, and global information technology initiatives.

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CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
                 
    Millions of Dollars  
    At June 30     At December 31  
    2005     2004  
     
Current ratio
    1.0       1.0  
Notes payable and long-term debt due within one year
  $ 354       632  
Total debt
  $ 14,013       15,002  
Minority interests
  $ 1,212       1,105  
Common stockholders’ equity
  $ 47,300       42,723  
Percent of total debt to capital*
    22 %     26  
Percent of floating-rate debt to total debt
    13 %     19  
 
*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, primarily cash generated from operating activities. During the first six months of 2005, available cash was used to support our ongoing capital expenditures and investments program, repay debt, pay dividends and repurchase shares of our common stock. Total dividends paid on our common stock during the first six months were $780 million. During the first six months of 2005, cash and cash equivalents increased $154 million to $1.5 billion.
In addition to cash flows from operating activities, we also rely on our cash balance, commercial paper and credit facility programs, and our $5 billion universal shelf registration statement, to support our short- and long-term liquidity requirements. We anticipate that these sources of liquidity will be adequate to meet our funding requirements through 2006, including our capital spending program and required debt payments.
Significant Sources of Capital
Operating Activities
During the first six months of 2005, cash from operating activities totaled $6,857 million, compared with cash from operations of $4,349 million in the corresponding period of 2004. This 58 percent increase correlates with the 67 percent increase in income from continuing operations over the same time periods. The percentage increase in cash from operations was somewhat lower than income from continuing operations due to higher non-cash items included in earnings in 2005, primarily undistributed equity earnings. After excluding these non-cash items, cash from operations was higher in 2005 primarily due to higher crude oil, natural gas and natural gas liquid prices, as well as improved worldwide refining margins.
Our cash flows from operating activities, for both the short- and long-term, are highly dependent upon prices for crude oil, natural gas and natural gas liquids, as well as refining and marketing margins. During the first six months of 2005 and the year 2004, we benefited from favorable crude oil and natural gas prices, as well as strong refining margins. The sustainability of these prices and margins are driven by market conditions over which we have no control. In addition, 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, the addition of proved reserves through exploratory success, and the timely and cost-effective development of those proved reserves.

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Asset Sales
During the first six months of 2005, proceeds from asset sales were $308 million, compared with asset sales in the same period of 2004 of $1,354 million, which were related to our asset disposition program that began following the merger in late August of 2002 between Conoco and Phillips. While we will continue to have modest asset disposition activity, this asset disposition program was essentially completed at the end of the second quarter of 2004. Proceeds from these asset sales were used primarily to repay debt.
Commercial Paper and Credit Facilities
While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our operating cash flows remain exposed to the volatility of commodity crude oil and natural gas prices and refining and marketing margins, as well as periodic cash needs to finance tax payments and crude oil, natural gas and petroleum product purchases. Our primary funding source for short-term working capital needs is a $5 billion commercial paper program, a portion of which may be denominated in other currencies (limited to euro 3 billion equivalent). Commercial paper maturities are generally limited to 90 days. At June 30, 2005, we had no commercial paper outstanding, compared with $544 million of commercial paper outstanding at December 31, 2004.
At June 30, 2005, we had two revolving credit facilities totaling $5 billion. The two facilities included a $2.5 billion four-year facility expiring in October 2008 and a $2.5 billion five-year facility expiring in October 2009. Both facilities are available for use as direct bank borrowings or as support for our $5 billion commercial paper program. In addition, the five-year facility may be used to support issuances of letters of credit totaling up to $750 million. The facilities are broadly syndicated among financial institutions and do not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The credit agreements do contain a cross-default provision relating to our, or any of our consolidated subsidiaries’, failure to pay principal or interest on other debt obligations of $200 million or more. There were no outstanding borrowings under these facilities at June 30, 2005.
Based on having no commercial paper outstanding and having issued $62 million of letters of credit, we had access to $4.9 billion in borrowing capacity under the two revolving credit facilities as of June 30, 2005, which provides liquidity to cover daily operations. In addition, at June 30, 2005, our $1.5 billion cash balance and $1.2 billion of capacity related to our receivables monetization program also supported our liquidity position.
Shelf Registration
In late 2002, we filed a universal shelf registration statement with the U.S. Securities and Exchange Commission for various types of debt and equity securities. As a result, we have available to issue and sell a total of $5 billion of various types of securities under the universal shelf registration statement.
Minority Interests
At June 30, 2005, we had outstanding $1,212 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 controlled-operating joint ventures with minority interest owners. The largest of these, $640 million, was related to the Bayu-Undan liquefied natural gas project in the Timor Sea and northern Australia.

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Off-Balance Sheet Arrangements
Receivables Monetization
At December 31, 2004, certain credit card and trade receivables had been sold to a Qualifying Special Purpose Entity (QSPE) in a revolving-period securitization arrangement. This arrangement provides for us to sell, and the QSPE to purchase, certain receivables and for the QSPE to then issue beneficial interests of up to $1.2 billion to five bank-sponsored entities. At December 31, 2004, the QSPE had issued beneficial interests to the bank-sponsored entities of $480 million. All five bank-sponsored entities are multi-seller conduits with access to the commercial paper market and purchase interests in similar receivables from numerous other companies unrelated to us. We have no ownership interests, nor any variable interests, in any of the bank-sponsored entities, which we do not consolidate. Furthermore, except as discussed below, we do not consolidate the QSPE because it meets the requirements of SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” to be excluded from the consolidated financial statements of ConocoPhillips. The receivables transferred to the QSPE met the isolation and other requirements of SFAS No. 140 to be accounted for as sales and were accounted for accordingly.
By January 31, 2005, all of the beneficial interests held by the bank-sponsored entities had matured; therefore, in accordance with SFAS No. 140, the operating results and cash flows of the QSPE subsequent to this maturity have been consolidated with our financial statements, and the assets and liabilities of the QSPE are included in our June 30, 2005, balance sheet. The revolving-period securitization arrangement expires in September 2005, and at this time we have no plans to renew the arrangement. See Note 16—Sales of Receivables, in the Notes to Consolidated Financial Statements, for additional information.
Capital Requirements
For information about our capital expenditures and investments, see the “Capital Spending” section.
Our balance sheet debt at June 30, 2005, was $14 billion. This reflects debt reductions of approximately $1 billion during the first six months of 2005. The decline in debt primarily resulted from a reduction of $544 million in our commercial paper balance to zero at June 30, 2005, and the redemption in late March of our $400 million 3.625% Notes due 2007, at par plus accrued interest. In conjunction with the redemption, $400 million of interest rate swaps were cancelled. Going forward, we have no significant mandatory debt retirements until payment of the $1,250 million aggregate principal amount of our 5.45% Notes due in 2006, at maturity.
On February 4, 2005, we announced a stock repurchase program that provides for the repurchase of up to $1 billion of the company’s common stock over a period of up to two years. The program will serve as a means of limiting dilution to shareholders from the company’s stock-based compensation programs. Acquisitions for the share repurchase program will be made at management’s discretion at prevailing prices, subject to market conditions and other factors. Purchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan will be held as treasury shares. During the first six months of 2005, we repurchased 10.7 million shares of our common stock under this program at a cost of $576 million.
In April 2005, we announced a quarterly dividend of 62 cents per share, payable June 1, 2005, to stockholders of record as of May 16, 2005. This represented a 24 percent increase in the dividend for our common stock over the previous quarter’s dividend of 50 cents per share. This quarterly dividend applied to shares held on the record date before giving effect to the 2-for-1 stock split also announced in April. See Note 3—Common Stock Split, in the Notes to the Consolidated Financial Statements, for additional information about the stock split.

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In July 2004, we announced the finalization of our transaction with Freeport LNG Development, L.P. (Freeport LNG) to participate in a proposed LNG receiving terminal in Quintana, Texas. Construction began in early 2005. We do not have an ownership interest in the facility, but we do have a 50 percent interest in the general partnership managing the venture, along with contractual rights to regasification capacity of the terminal. We entered into a credit agreement with Freeport LNG, whereby we will provide loan financing of approximately $600 million for the construction of the facility. Through June 30, 2005, we had provided $105 million in loan financing.
Anticipated production from the joint venture with LUKOIL in the Timan-Pechora province of Russia is expected to be transported via pipeline to LUKOIL’s existing terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international markets. LUKOIL is expected to complete an expansion of the terminal capacity in 2007, with ConocoPhillips participating in the design and financing of the terminal expansion. We have an obligation to provide loan financing to Varandey Terminal Company for 30 percent of the costs of the terminal expansion, but we will have no governance interest in the terminal. Through June 30, 2005, we had provided $26 million in loan financing.
We account for our loans to Freeport LNG and Varandey Terminal Company as financial assets in the “Investments and long-term receivables” line on the balance sheet.
Contractual Obligations
Our contractual purchase obligations at June 30, 2005, are estimated to be $74 billion, an increase of $7 billion from the amount reported at December 31, 2004, of $67 billion. The majority of the increase results from higher purchase obligations within our Commercial crude oil trading organization, reflecting both higher purchase volume commitments, as well as higher commodity prices.

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Capital Spending
Capital Expenditures and Investments
                 
    Millions of Dollars  
    Six Months Ended  
    June 30  
    2005     2004  
     
E&P
               
United States—Alaska
  $ 358       324  
United States—Lower 48
    540       290  
International
    2,645       1,835  
 
 
    3,543       2,449  
 
Midstream
    1       5  
 
R&M
               
United States
    563       365  
International
    72       128  
 
 
    635       493  
 
LUKOIL Investment
    708        
Chemicals
           
Emerging Businesses
    3       55  
Corporate and Other*
    57       63  
 
 
  $ 4,947       3,065  
 
United States
  $ 1,518       1,047  
International
    3,429       2,018  
 
 
  $ 4,947       3,065  
 
Discontinued operations
  $       1  
 
*Excludes discontinued operations.
E&P
UNITED STATES
Alaska
During the first six months of 2005, we continued development drilling in the Greater Kuparuk Area, the Greater Prudhoe Area, the Alpine field and the West Sak development. We continued work on the construction of Alpine’s first satellite fields, Nanuq and Fiord, the startup of which is expected in the fourth quarter of 2006. In addition, the Alpine Capacity Expansion-Phase II project was completed in June.
During the first half of 2005, we and our co-venturers in the Trans-Alaska Pipeline System continued a project, which began in 2004, to upgrade the pipeline’s pump stations. This project is anticipated to be complete in 2006.
Lower 48 States
In the Lower 48, capital expenditures during the first half of 2005 included the acquisition of limited-term, fixed-volume overriding royalty interests in Utah and the San Juan Basin related to our production. These acquisitions are expected to have a positive but otherwise insignificant impact to production. In addition, Lower 48 capital expenditures were focused on the completion of Magnolia wells in the deepwater Gulf of Mexico and development of natural gas reserves within core areas, including the San Juan Basin of New Mexico and the Lobo Trend of South Texas.

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CANADA
During the first six months of 2005, we continued with the development of our Surmont heavy-oil project and on the development of the Syncrude Stage III expansion-mining project in the Canadian province of Alberta, where an upgrader expansion project is expected to be fully operational in the second quarter of 2006. In April 2005, we exercised our right of first refusal to acquire an additional 6.5 percent interest in Surmont, increasing our interest to 50 percent. We will remain the operator of the project. The acquisition was completed in the second quarter of 2005.
NORTHWEST EUROPE
In the U.K. and Norwegian sectors of the North Sea, funds were invested during the six-month 2005 period for development of the Britannia satellite fields, Callanish and Brodgar, where production is expected in 2007; the Ekofisk Area growth project, where production is expected in the fourth quarter of 2005; and the Alvheim project, where production is scheduled to begin in 2007.
RUSSIA AND CASPIAN SEA
Russia
In June 2005, we invested funds of $512 million to acquire a 30 percent economic interest and a 50 percent voting interest in OOO Naryanmarneftegaz (NMNG), a joint venture with LUKOIL to explore for and develop oil and gas resources in the northern part of Russia’s Timan-Pechora province.
Caspian Sea
In the six-month 2005 period, we continued to participate in construction activities to develop the Kashagan field on the Kazakhstan shelf in the North Caspian Sea. In March 2005, agreement was reached with the Republic of Kazakhstan government to conclude the sale of B.G. International’s interest in the North Caspian Production Sharing Agreement to several of the remaining partners and for the subsequent sale of one-half of the acquired interests to KazMunayGas. This agreement increased our ownership interest from 8.33 percent to 9.26 percent.
ASIA PACIFIC
Timor Sea
In the Timor Sea, we continued with final development activities associated with Phase I of the Bayu-Undan gas recycle project, where condensate and natural gas liquids are separated and removed and the dry gas is re-injected into the reservoir. Production of liquids began from Phase I in February of 2004, and development drilling concluded at the end of March 2005.
Construction activities continued in 2005 for Phase II, the development of a liquefied natural gas (LNG) plant near Darwin, Australia, as well as a gas pipeline from Bayu-Undan to the LNG facility. The LNG project was approximately 86 percent complete at the end of the first six months of 2005. The first LNG cargo from the facility is scheduled for delivery in early 2006.
Indonesia
During the first half of 2005, we continued to invest funds on the development of the Belanak, Kerisi and Hiu fields in the South Natuna Sea Block B. Oil production at Belanak began in late 2004. The commissioning of gas plant facilities on the Belanak floating production, storage and offloading facility (FPSO) continued in June, resulting in first condensate production. In South Sumatra, we continued with the development of the Suban Phase II project, which is an expansion of the existing Suban gas plant.

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China
Following developmental approval from the Chinese government in early 2005, we began development of Phase II of the Peng Lai 19-3 oil field, as well as concurrent development of the nearby 25-6 field. The development of Peng Lai 19-3 and Peng Lai 25-6 will include multiple wellhead platforms and a larger FPSO.
Vietnam
In early 2005, we began preliminary engineering for the Su Tu Vang development. The Su Tu Vang field is in Vietnam’s Block 15-1, near our producing Su Tu Den field.
At our producing Rang Dong field on Block 15-2, we continued work during 2005 on the development of the central part of the field, where two additional platforms and additional production and injection wells were added. First production began in the second quarter.
R&M
In the United States, we continued to expend funds related to clean fuels, safety and environmental projects during the first half of 2005, including investing in a new diesel hydrotreater at the Rodeo facility of our San Francisco refinery. This hydrotreater began operation at the end of March 2005. The new diesel hydrotreater provides the capability to produce reformulated California highway diesel over one year ahead of the June 2006 deadline.
Internationally, we continued to invest in our ongoing refining and marketing operations, including marketing growth in select countries in Europe and Asia.
LUKOIL Investment
During the first six months of 2005, we increased our ownership interest in LUKOIL to 12.6 percent at June 30, 2005, from 10.0 percent at December 31, 2004. Purchase of LUKOIL shares continued into the third quarter.
Contingencies
Legal and Tax Matters
We accrue for contingencies when a loss is probable and amounts can be reasonably estimated. Based on currently available information, we believe that 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 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 industry; and refining, marketing and transportation of crude oil and refined products businesses. The most significant of these environmental laws and regulations include, among others, the:
    Federal Clean Air Act, which governs air emissions.

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    Federal Clean Water Act, which governs discharges to water bodies.
 
    Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatened to occur.
 
    Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage, and disposal of solid waste.
 
    Federal Oil Pollution Act of 1990, under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States.
 
    Federal Emergency Planning and Community Right-to-Know Act, which requires facilities to report toxic chemical inventories with local emergency planning committees and responses departments.
 
    Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells.
 
    U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages.
These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.
We are also subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks located at numerous past and present ConocoPhillips-owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require that contamination caused by such underground storage tank release be assessed and remediated to meet applicable standards. In addition to other cleanup standards, many states have adopted cleanup criteria for methyl tertiary-butyl ether (MTBE) for both soil and groundwater. MTBE standards continue to evolve and future environmental expenditures associated with the remediation of MTBE-contaminated underground storage tank sites could be substantial.
At RCRA permitted facilities, we are required to assess environmental conditions. If conditions warrant, we may be required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as “Superfund,” the cost of corrective action activities under RCRA corrective action programs typically is borne solely by us. Over the next decade, we anticipate that significant ongoing expenditures for RCRA remediation activities may be required, but such annual expenditures for the near term are not expected to vary significantly from the range of such expenditures we have experienced over the past few years. Longer term, expenditures are subject to considerable uncertainty and may fluctuate significantly.

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From time to time, we receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under 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, 2004, we reported we had been notified of potential liability under CERCLA and comparable state laws at 64 sites around the United States. At June 30, 2005, we had resolved 3 of these sites, reclassified 1 site as unresolved, and had received 4 new notices of potential liability, leaving 66 unresolved sites where we have been notified of potential liability.
For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. 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 site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.
Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.
The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States and in other countries in which we operate.
Remediation Accruals
We accrue for remediation activities when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. These accrued liabilities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).
Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we have identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA. Considerable uncertainty exists with respect to these costs, and under adverse changes in circumstances, potential liability may exceed amounts accrued as of June 30, 2005.

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Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.
At June 30, 2005, our balance sheet included a total environmental accrual of $1,020 million, compared with $1,061 million at December 31, 2004. We expect to incur a substantial 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 affect upon our results of operations or financial position as a result of compliance with environmental laws and regulations.
NEW ACCOUNTING STANDARDS AND EMERGING ISSUES
New Accounting Standards
In June 2005, the Financial Accounting Standards Board (FASB) ratified Emerging Issues Task Force (EITF) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.” Issue No. 04-5 adopts a framework for evaluating whether the general partner (or general partners as a group) controls the partnership. The framework makes it more likely that a single general partner (or a general partner within a general partner group) would have to consolidate the limited partnership regardless of its ownership in the limited partnership. The new guidance was effective upon ratification for all newly-formed limited partnerships and for existing limited partnership agreements that are modified. The guidance is effective January 1, 2006, for existing limited partnership agreements that are not modified. We are reviewing Issue No. 04-5 to determine the impact, if any, on our financial statements.
In May 2005, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3.” Among other changes, this Statement requires retrospective application for voluntary changes in accounting principle, unless it is impractical to do so. Guidance is provided on how to account for changes when retrospective application is impractical. This Statement is effective on a prospective basis beginning January 1, 2006.
In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). This Interpretation clarifies that an entity is required to recognize a liability for a legal obligation to perform asset retirement activities when the retirement is conditional on a future event and if the liability’s fair value can be reasonably estimated. If the liability’s fair value cannot be reasonably estimated, then the entity must disclose (a) a description of the obligation, (b) the fact that a liability has not been recognized because the fair value cannot be reasonably estimated, and (c) the reasons why the fair value cannot be reasonably estimated. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. We are required to implement this Interpretation in the fourth quarter of 2005. We are studying the provisions of this Interpretation to determine the impact, if any, on our financial statements.
In December 2004, the FASB issued SFAS No. 153, “Exchange of Nonmonetary Assets, an amendment of APB Opinion No. 29.” This amendment eliminates the Accounting Principles Board (APB) Opinion No. 29

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exception for fair value recognition of nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges of nonmonetary assets that do not have commercial substance. This Statement is effective on a prospective basis beginning July 1, 2005.
Also in December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” (SFAS 123(R)), which supercedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” that we adopted at the beginning of 2003. SFAS 123(R) prescribes the accounting for a wide range of share-based compensation arrangements, including share options, restricted share plans, performance-based awards, share appreciation rights, and employee share purchase plans, and generally requires the fair value of share-based awards to be expensed in the income statement. For ConocoPhillips, this Statement provided for an effective date of third-quarter 2005; however, the Securities and Exchange Commission approved a new rule that delayed the effective date until January 1, 2006. We plan to adopt the provisions of this Statement January 1, 2006. We are studying the provisions of this new pronouncement to determine the impact, if any, on our financial statements. For more information on our adoption of SFAS No. 123 and its effect on net income, see Note 2—Accounting Policies, in the Notes to Consolidated Financial Statements.
In November 2004, the FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4.” This Statement requires that items, such as abnormal idle facility expense, excessive spoilage, double freight, and handling costs, be recognized as a current-period charge. We are required to implement this Statement in the first quarter of 2006. We are analyzing the provisions of this Statement to determine the effects, if any, on our financial statements.
In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity,” to address the balance sheet classification of certain financial instruments that have characteristics of both liabilities and equity. The Statement, already effective for contracts created or modified after May 31, 2003, was originally intended to become effective July 1, 2003, for all contracts existing at May 31, 2003. However, on November 7, 2003, the FASB issued an indefinite deferral of certain provisions of SFAS No. 150. We continue to monitor and assess the FASB’s modifications of SFAS No. 150, but do not anticipate any material impact to our financial statements.
Emerging Issues
At a November 2004 meeting and subsequent meetings, the EITF continued to discuss Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” which addresses accounting issues that arise when one company both sells inventory to and buys inventory from another company in the same line of business. For additional information, see the Revenue Recognition section of Note 2—Accounting Policies, in the Notes to Consolidated Financial Statements.
OUTLOOK
E&P’s production for the full year 2005 is expected to be approximately 3 percent higher than the amount produced in 2004. E&P’s production for the third quarter of 2005 is expected to be higher than its second-quarter level, primarily due to a lower level of scheduled maintenance at Bayu-Undan and in Norway, and continued increase from new projects in the Lower 48, Venezuela and Indonesia. Actual production increases from quarter-to-quarter and year-to-year may vary due to the timing of maintenance work, individual project ramp-ups, unscheduled downtime, reservoir performance, price impacts of production sharing contracts and other factors. These projections exclude amounts related to our Canadian Syncrude operations, and the impact of our equity investment in LUKOIL.

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We have received correspondence from the Venezuelan Ministry of Energy and Petroleum regarding the royalty and production applicable to our heavy oil projects. We believe we are, and continue to be, in compliance with the contractual terms related to production and payment of royalties from our heavy oil project. We continue to work closely with the Venezuelan government on any potential impacts to our heavy oil projects in Venezuela.
In February 2003, the Venezuelan government implemented a currency exchange control regime. The government has published legal instruments supporting the controls, one of which establishes official exchange rates for the U.S. dollar. The devaluation of the Venezuelan currency by approximately 11 percent in March 2005 did not have a significant impact on our Venezuelan operations; however, future changes in the exchange rate could have a significant impact on our Venezuelan operations.
In March 2005, a development plan addendum for Phase I of the Corocoro field in the Gulf of Paria was approved by the Venezuelan government. This addendum addressed revisions to the original development plan approved in 2003.
Because of delays pertaining to access and related regulatory matters, the Mackenzie Gas Project co-venturers have elected to halt selected data collection, engineering and preliminary contracting work. Near term efforts will be focused on finalizing benefits and access agreements and firming up the regulatory process and schedule. As a result, we expect first production from the project to be deferred beyond the 2009 time frame.
During the first quarter of 2005, we announced that the PETRONAS Carigali-ConocoPhillips joint venture had signed a production sharing contract with PETRONAS, the Malaysian national oil company, for the appraisal and development of the Kebabangan oil field, offshore Sabah, Malaysia. We will have a 40 percent interest in the Kebabangan field. The Kebabangan appraisal represents an opportunity for us to build upon previously announced exploration success in deepwater blocks G and J, offshore Sabah.
In December 2003, we signed a Statement of Intent with Qatar Petroleum regarding the construction of a gas-to-liquids (GTL) plant in Ras Laffan, Qatar. Preliminary engineering and design studies have been completed. In April 2005, the Qatar Minister of Petroleum stated that there would be a postponement of new GTL projects in order to further study impacts on infrastructure, shipping and contractors, and to ensure that the development of its gas resources occurs at a sustainable rate. As a result, we continue to work with Qatar authorities on the appropriate timing of the project to ensure that the development meets Qatar’s and our objectives.
In R&M, we expect our average refinery crude oil utilization rate for the third quarter to be in the high 90 percent range.
Also in R&M, in addition to our announced capital program, we are planning to spend an additional $3 billion over the period 2006 through 2010 to increase our refining system’s ability to process heavy-sour crude oil and other low-quality feedstocks. These investments, primarily domestic, are expected to incrementally increase refining capacity and clean products yield at our existing facilities, while providing competitive returns.

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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 that we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual 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.
 
    Changes in our business, operations, results and prospects.
 
    The operation and financing of our midstream and chemicals joint ventures.
 
    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.
 
    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 projects, manufacturing or refining.
 
    Unexpected technological or commercial difficulties in manufacturing or refining 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, 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 LNG projects and related facilities.
 
    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.
 
    Liability for remedial actions, including removal and reclamation obligations, under environmental regulations.
 
    Liability resulting from litigation.

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    General domestic and international economic and political conditions, including armed hostilities and governmental disputes over territorial boundaries.
 
    Changes in tax and other laws, regulations or royalty rules applicable to our business.
 
    Inability to obtain economical financing for exploration and development projects, construction or modification of facilities and general corporate purposes.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
With the exception of the item described below, information about market risks for the six months ended June 30, 2005, does not differ materially from that discussed under Item 7A of ConocoPhillips’ Annual Report on Form 10-K for the year ended December 31, 2004.
In June 2005, we acquired limited-term, fixed-volume overriding royalty interests in Utah and the San Juan Basin related to our production. As part of the acquisition, we assumed related commodity swaps with a negative fair value of $261 million at June 30, 2005. In late June and early July, we entered into additional commodity swaps to offset most of the exposure from the assumed swaps.
Item 4. CONTROLS AND PROCEDURES
As of June 30, 2005, with the participation of our management, our Chairman, President and Chief Executive Officer and our Executive Vice President, Finance, and Chief Financial Officer carried out an evaluation of the effectiveness of the design and operation of ConocoPhillips’ disclosure controls and procedures pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended. Based upon that evaluation, our Chairman, President and Chief Executive Officer and our Executive Vice President, Finance, and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of June 30, 2005.
There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Securities Exchange Act, that occurred subsequent to the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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 second quarter of 2005 and any material developments with respect to those matters previously reported in ConocoPhillips’ 2004 Form 10-K and 2005 first quarter 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.
In June 2005, the South Coast Air Quality Management District (SCAQMD) notified us of their intent to seek civil penalties in the amount of $401,000 for 18 alleged violations of various SCAQMD regulations at our Los Angeles Refinery in Wilmington and Carson, California and one of our tank facilities in Torrance, California. We are currently assessing these allegations and expect to work with the SCAQMD towards a resolution of this matter.
In July 2004, Polar Tankers, Inc. notified the U.S. Coast Guard of possible environmental violations onboard the vessel Polar Discovery. On June 29, 2005, the U.S. Attorney’s office in Anchorage issued a subpoena for records to Polar Tankers regarding the possible environmental violations onboard that vessel. We are fully cooperating with the governmental authorities in their investigation.
On March 2, 2004, the Bay Area Air Quality Management District (BAAQMD) notified us of their intent to seek civil penalties in the amount of $750,000 for 17 alleged violations of various BAAQMD regulations at our Rodeo facility and carbon plant located in the San Francisco area. Since that time, we have worked with the BAAQMD to resolve these and subsequent alleged violations. In May 2005, we entered into a settlement with the BAAQMD to resolve the alleged violations and paid a civil penalty of $419,000.
In December 2004, the San Luis Obispo Air Pollution Control District (SLOAPCD) notified us of their intent to seek civil penalties in the amount of $2,700,000 for alleged violations of various SLOAPCD regulations at the Santa Maria facility of our San Francisco refinery. During May 2005, we agreed in principle to settle the alleged violations by funding $675,000 for supplemental environmental projects and paying a $225,000 civil penalty to the SLOAPCD.

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Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Issuer Purchases of Equity Securities
                                 
                    Total Number of     Millions of Dollars  
                    Shares Purchased     Approximate Dollar  
                    as Part of Publicly     Value that May Yet  
    Total Number of     Average Price     Announced Plans     Be Purchased Under  
Period   Shares Purchased*     Paid per Share     or Programs**     the Plans or Programs  
                       
April 1-30, 2005
    1,770,686     $ 53.46       1,760,000     $ 680  
May 1-31, 2005
    2,214,568       51.41       2,200,000       567  
June 1-30, 2005
    2,525,217       56.93       2,510,000       424  
         
Total
    6,510,471     $ 54.11       6,470,000          
       
*   Includes the repurchase of common shares from company employees in connection with the company’s broad-based employee incentive plans.
 
**   On February 4, 2005, we announced a stock repurchase program that provides for the repurchase of up to $1 billion of the company’s common stock over a period of up to two years. The program will serve as a means of limiting dilution to shareholders from the company’s stock-based compensation programs. Acquisitions for the share repurchase program will be made at management’s discretion at prevailing prices, subject to market conditions and other factors. Purchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares.
 
Note: Per-share amounts and number of shares in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend on June 1, 2005.

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Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
We held our annual stockholders meeting on May 5, 2005. A brief description of each proposal and the voting results follow:
     A company proposal to elect four directors.
                 
            Withheld  
    For     or Against  
Norman R. Augustine
    629,634,898       12,519,426  
Larry D. Horner
    613,129,035       29,025,289  
Charles C. Krulak
    630,145,712       12,008,612  
J. J. Mulva
    622,103,463       20,050,861  
Those directors whose term of office continued were as follows: Richard H. Auchinleck, James E. Copeland, Kenneth M. Duberstein, Ruth R. Harkin, William K. Reilly, William R. Rhodes, J. Stapleton Roy, Victoria J. Tschinkel and Kathryn C. Turner.
A company proposal to ratify the appointment of Ernst & Young LLP as ConocoPhillips’ independent registered public accounting firm for 2005.
         
For
    629,906,085  
Against
    7,286,074  
Abstentions
    4,962,078  
Broker Non-Votes
    87  
A shareholder proposal to replace the current system of compensation for senior executives.
         
For
    51,338,513  
Against
    510,681,552  
Abstentions
    9,121,405  
Broker Non-Votes
    71,012,854  
A shareholder proposal to amend the ConocoPhillips’ governance documents to provide that director nominees shall be elected by the affirmative vote of the majority of votes cast at an annual meeting of shareholders.
         
For
    276,887,565  
Against
    285,192,224  
Abstentions
    9,062,378  
Broker Non-Votes
    71,012,157  
All four nominated directors were elected and the appointment of the independent auditors was ratified. The two shareholder proposals were not ratified.

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Item 6. EXHIBITS
Exhibits
12   Computation of Ratio of Earnings to Fixed Charges.
 
31.1   Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
 
31.2   Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
 
32   Certifications pursuant to 18 U.S.C. Section 1350.

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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
 
  CONOCOPHILLIPS    
 
       
 
  /s/ Rand C. Berney    
 
       
 
  Rand C. Berney    
 
  Vice President and Controller    
 
  (Chief Accounting and Duly Authorized Officer)    
 
       
August 3, 2005
       

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Index to Exhibits
Exhibits
12   Computation of Ratio of Earnings to Fixed Charges.
 
31.1   Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
 
31.2   Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
 
32   Certifications pursuant to 18 U.S.C. Section 1350.

exv12
 

Exhibit 12
CONOCOPHILLIPS AND CONSOLIDATED SUBSIDIARIES
TOTAL ENTERPRISE
Computation of Ratio of Earnings to Fixed Charges
                 
    Millions of Dollars
    Six Months Ended
    June 30
    2005   2004
    (Unaudited)
Earnings Available for Fixed Charges
               
Income from continuing operations before income taxes
  $ 10,372       6,434  
Distributions less than equity in earnings of fifty-percent-or-less-owned companies
    (1,223 )     (235 )
Fixed charges, excluding capitalized interest*
    388       387  
     
 
  $ 9,537       6,586  
     
 
               
Fixed Charges
               
Interest and debt expense, excluding capitalized interest
  $ 265       304  
Capitalized interest
    179       219  
Interest portion of rental expense
    87       75  
Interest expense relating to guaranteed debt of fifty-percent-or-less owned companies
    8        
     
 
  $ 539       598  
     
Ratio of Earnings to Fixed Charges
    17.7       11.0  
     
*   Includes amortization of capitalized interest totaling approximately $28 million in 2005 and $8 million in 2004.
Earnings available for fixed charges include, if any, our equity in losses of companies owned less than fifty percent and having debt for which the company is contingently liable. Fixed charges include our proportionate share, if any, of interest relating to the contingent debt.
Earnings available for fixed charges include, if any, 100 percent of the losses of companies owned greater than fifty percent that have debt for which we are contingently liable. Fixed charges include 100 percent of interest and capitalized interest, if any, relating to the contingent debt.

 

exv31w1
 

Exhibit 31.1
CERTIFICATION
I, J. J. Mulva, certify that:
1. I have reviewed this quarterly report on Form 10-Q of ConocoPhillips;
2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.   The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
  (a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
  (b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
 
  (c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
  (d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.   The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
  (a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
  (b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
         
Date: August 3, 2005
       
 
  /s/ J. J. Mulva    
 
       
 
  J. J. Mulva    
 
  Chairman, President and Chief Executive    
 
  Officer    

 

exv31w2
 

Exhibit 31.2
CERTIFICATION
I, John A. Carrig, certify that:
1.   I have reviewed this quarterly report on Form 10-Q of ConocoPhillips;
 
2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.   The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
  (a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
  (b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
 
  (c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
  (d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.   The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
  (a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
  (b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: August 3, 2005
         
 
  /s/ John A. Carrig    
 
       
 
  John A. Carrig    
 
  Executive Vice President, Finance, and    
 
  Chief Financial Officer    

 

exv32
 

Exhibit 32
CERTIFICATIONS PURSUANT TO 18 U.S.C. SECTION 1350
     In connection with the Quarterly Report of ConocoPhillips (the company) on Form 10-Q for the period ended June 30, 2005, as filed with the U.S. Securities and Exchange Commission on the date hereof (the Report), each of the undersigned hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to their knowledge:
  (1)   The Report fully complies with the requirements of Sections 13(a) or 15(d) of the Securities Exchange Act of 1934; and
 
  (2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the company.
Date: August 3, 2005
         
 
  /s/ J. J. Mulva    
 
       
 
  J. J. Mulva    
 
  Chairman, President and Chief Executive Officer    
 
       
 
  /s/ John A. Carrig    
 
       
 
  John A. Carrig    
 
  Executive Vice President, Finance, and    
 
  Chief Financial Officer