e10vq
 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

       
(Mark One)      
       
[X]   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
     
For the quarterly period ended   June 30, 2003
   

OR

       
[   ]   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
             
For the transition period from       to    
   
     
     
Commission file number   000-49987
   

ConocoPhillips

(Exact name of registrant as specified in its charter)
     
Delaware
(State or other jurisdiction of
incorporation or organization)
  01-0562944
(I.R.S. Employer
Identification No.)

600 North Dairy Ashford, Houston, TX 77079
(Address of principal executive offices)

281-293-1000
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes   X   No       

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes   X   No       

The registrant had 679,926,255 shares of common stock, $.01 par value, outstanding at July 31, 2003.

 


 

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
Consolidated Income Statement
Consolidated Balance Sheet
Consolidated Statement of Cash Flows
Notes to Consolidated Financial Statements
Supplementary Information—Condensed Consolidating Financial Information
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 4. CONTROLS AND PROCEDURES
PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Item 5. OTHER INFORMATION
Item 6. EXHIBITS AND REPORTS ON FORM 8-K
SIGNATURE
EXHIBIT INDEX
Key Employee Deferred Compensation Plan
Computation of Ratio of Earnings to Fixed Charges
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certifications Pursuant to Section 906

CONOCOPHILLIPS

TABLE OF CONTENTS

             
        Page(s)
       
Part I – Financial Information
       
 
Item 1. Financial Statements
       
   
Consolidated Income Statement
    1  
   
Consolidated Balance Sheet
    2  
   
Consolidated Statement of Cash Flows
    3  
   
Notes to Consolidated Financial Statements
    4  
   
Supplementary Information—Condensed Consolidating Financial Information
    23  
 
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
    32  
 
Item 3. Quantitative and Qualitative Disclosures About Market Risk
    59  
 
Item 4. Controls and Procedures
    59  
Part II – Other Information
       
 
Item 1. Legal Proceedings
    61  
 
Item 4. Submission of Matters to a Vote of Security Holders
    61  
 
Item 5. Other Information
    62  
 
Item 6. Exhibits and Reports on Form 8-K
    62  
Signature
    63  

 


 

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  
       
 
        2003     2002 **   2003     2002 **
       
 
Revenues
                               
Sales and other operating revenues*
  $ 25,347       10,414       52,289       18,845  
Equity in earnings of affiliates
    156       29       205       49  
Other income
    92       22       178       51  

   
Total Revenues
    25,595       10,465       52,672       18,945  

Costs and Expenses
                               
Purchased crude oil and products
    16,378       7,154       34,064       12,793  
Production and operating expenses
    1,897       882       3,546       1,799  
Selling, general and administrative expenses
    624       207       1,133       471  
Exploration expenses
    142       67       258       230  
Depreciation, depletion and amortization
    847       395       1,696       791  
Property impairments
    146       8       174       18  
Taxes other than income taxes*
    3,624       977       7,046       1,891  
Accretion on discounted liabilities
    35       6       68       11  
Interest and debt expense
    184       106       393       213  
Foreign currency transaction gains
    (20 )     (6 )     (23 )     (5 )
Preferred dividend requirements of capital trusts and minority interests
    13       12       27       25  

   
Total Costs and Expenses
    23,870       9,808       48,382       18,237  

Income from continuing operations before income taxes and subsidiary equity transactions
    1,725       657       4,290       708  
Gain on subsidiary equity transactions
    28             28        

Income from continuing operations before income taxes
    1,753       657       4,318       708  
Provision for income taxes
    674       345       1,969       494  

Income From Continuing Operations
    1,079       312       2,349       214  
Income from discontinued operations
    59       39       81       35  

Income Before Cumulative Effect of Change In Accounting Principle
    1,138       351       2,430       249  
Cumulative effect of change in accounting principle
                145        

Net Income
  $ 1,138       351       2,575       249  

Income Per Share of Common Stock
                               
Basic
                               
 
Continuing operations
  $ 1.59       .81       3.46       .56  
 
Discontinued operations
    .08       .10       .12       .09  

 
Before cumulative effect of change in accounting principle
    1.67       .91       3.58       .65  
 
Cumulative effect of change in accounting principle
                .21        

Net Income
  $ 1.67       .91       3.79       .65  

Diluted
                               
 
Continuing operations
  $ 1.58       .81       3.44       .55  
 
Discontinued operations
    .08       .10       .12       .10  

 
Before cumulative effect of change in accounting principle
    1.66       .91       3.56       .65  
 
Cumulative effect of change in accounting principle
                .21        

Net Income
  $ 1.66       .91       3.77       .65  

Dividends Paid Per Share of Common Stock
  $ .40       .36       .80       .72  

Average Common Shares Outstanding (in thousands)
                               
 
Basic
    680,028       383,913       679,784       383,130  
 
Diluted
    684,188       386,711       683,867       385,927  

   *Includes excise taxes on petroleum products sales:
  $ 3,387       819       6,535       1,583  
**Restated for discontinued operations.
                               
See Notes to Consolidated Financial Statements.
                               

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Consolidated Balance Sheet   ConocoPhillips
                     
        Millions of Dollars
       
        June 30   December 31
        2003   2002
       
Assets
               
Cash and cash equivalents
  $ 524       307  
Accounts and notes receivable (net of allowance of $45 million in 2003 and $48 million in 2002)
    3,215       2,904  
Accounts and notes receivable—related parties
    1,460       1,476  
Inventories
    4,163       3,845  
Prepaid expenses and other current assets
    657       766  
Assets of discontinued operations held for sale
    1,562       1,605  

   
Total Current Assets
    11,581       10,903  
Investments and long-term receivables
    7,067       6,821  
Net properties, plants and equipment
    45,264       43,030  
Goodwill
    15,206       14,444  
Intangibles
    1,113       1,119  
Other assets
    498       519  

Total Assets
  $ 80,729       76,836  

Liabilities
               
Accounts payable
  $ 6,045       5,949  
Accounts payable—related parties
    468       303  
Notes payable and long-term debt due within one year
    1,544       849  
Accrued income and other taxes
    3,116       1,991  
Other accruals
    2,825       3,075  
Liabilities of discontinued operations held for sale
    610       649  

   
Total Current Liabilities
    14,608       12,816  
Long-term debt
    16,025       18,917  
Accrued dismantlement, removal and environmental costs
    3,264       1,666  
Deferred income taxes
    8,778       8,361  
Employee benefit obligations
    2,655       2,755  
Other liabilities and deferred credits
    2,294       1,803  

Total Liabilities
    47,624       46,318  

Company-Obligated Mandatorily Redeemable Preferred Securities of Phillips 66 Capital Trust II
    350       350  

Other Minority Interests
    723       651  

Common Stockholders’ Equity
               
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2003—705,886,532 shares; 2002—704,354,839 shares)
               
 
Par value
    7       7  
 
Capital in excess of par
    25,242       25,178  
Compensation and Benefits Trust (CBT) (at cost: 2003—26,035,094 shares; 2002—26,785,094 shares)
    (882 )     (907 )
Accumulated other comprehensive income (loss)
    204       (164 )
Unearned employee compensation—Long-Term Stock Savings Plan (LTSSP)
    (209 )     (218 )
Retained earnings
    7,670       5,621  

Total Common Stockholders’ Equity
    32,032       29,517  

Total
  $ 80,729       76,836  

See Notes to Consolidated Financial Statements.

2


 

     

Consolidated Statement of Cash Flows   ConocoPhillips
                     
        Millions of Dollars
       
        Six Months Ended
        June 30
       
        2003   2002*
       
Cash Flows From Operating Activities
               
Income from continuing operations
  $ 2,349       214  
Adjustments to reconcile income from continuing operations to net cash provided by continuing operations
               
 
Non-working capital adjustments
               
   
Depreciation, depletion and amortization
    1,696       791  
   
Property impairments
    174       18  
   
Dry hole costs and leasehold impairments
    94       141  
   
Accretion on discounted liabilities
    68       11  
   
Deferred taxes
    235       65  
   
Other
    (114 )     120  
 
Working capital adjustments**
               
   
Increase (decrease) in aggregate balance of accounts receivable sold
    4       (51 )
   
Decrease (increase) in other accounts and notes receivable
    25       (562 )
   
Decrease (increase) in inventories
    (283 )     46  
   
Decrease (increase) in prepaid expenses and other current assets
    125       (14 )
   
Increase in accounts payable
    155       448  
   
Increase (decrease) in taxes and other accruals
    690       (168 )

Net cash provided by continuing operations
    5,218       1,059  
Net cash provided by discontinued operations
    76       50  

Net Cash Provided by Operating Activities
    5,294       1,109  

Cash Flows From Investing Activities
               
Capital expenditures and investments, including dry hole costs
    (2,883 )     (1,519 )
Proceeds from asset dispositions
    591       81  
Long-term advances to affiliates and other investments
    (36 )     2  

Net cash used in continuing operations
    (2,328 )     (1,436 )
Net cash used in discontinued operations
    (57 )     (24 )

Net Cash Used in Investing Activities
    (2,385 )     (1,460 )

Cash Flows From Financing Activities
               
Issuance of debt
    269       1,240  
Repayment of debt
    (2,451 )     (311 )
Issuance of company common stock
    33       33  
Redemption of preferred stock of subsidiary
          (300 )
Dividends paid on common stock
    (543 )     (275 )
Other
          (33 )

Net cash provided by (used in) continuing operations
    (2,692 )     354  

Net Cash Provided by (Used in) Financing Activities
    (2,692 )     354  

Net Change in Cash and Cash Equivalents
    217       3  
Cash and cash equivalents at beginning of period
    307       142  

Cash and Cash Equivalents at End of Period
  $ 524       145  

* Restated for discontinued operations.
** Net of acquisition and disposition of businesses.
See Notes to Consolidated Financial Statements.

3


 

     

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 the consolidated financial statements and notes included in ConocoPhillips’ 2002 Annual Report on Form 10-K. Certain amounts in the 2002 financial statements have been reclassified to reflect discontinued operations and to conform to ConocoPhillips’ presentation.

The financial statements reflect the August 30, 2002, merger of Conoco Inc. (Conoco) and Phillips Petroleum Company (Phillips). The transaction was accounted for using the purchase method of accounting as required by Statement of Financial Accounting Standards (SFAS) No. 141, “Business Combinations.” Phillips was designated as the acquirer. Results of operations for the second quarter and first six months of 2002 reflect only Phillips’ activity.

Note 2—Changes in Accounting Principles

Effective January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which applies to legal obligations associated with the retirement and removal of long-lived assets. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period when it is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related property, plant and equipment. Over time, the liability is accreted upward for the change in its present value each period, and the initial capitalized cost is depreciated over the useful life of the related asset.

Application of this new accounting standard resulted in an initial increase in net properties, plants and equipment of $1.2 billion and an asset retirement obligation liability increase of $1.1 billion. The cumulative effect of this change in accounting principle increased net income in the first quarter of 2003 by $145 million. The second quarter 2003 effect of adopting this accounting principle increased net income $8 million, $.01 per basic and diluted share. The effect on net income for the first six months of 2003 was an increase of $16 million, or $.02 per basic and diluted share.

We have numerous asset removal obligations that we are required to perform under law or contract once an asset is permanently taken out of service. Most of these obligations are not expected to be paid until several years, or decades, in the future and will be funded from general company resources at the time of removal. Our largest individual obligations are related to fixed-base offshore production platforms around the world and to production facilities and pipelines in Alaska.

SFAS No. 143 calls for measurements of asset retirement obligations to include, as a component of expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties and unforeseeable circumstances inherent in the obligations, sometimes referred to as a market-risk premium. To date, the oil and gas industry has no examples of credit-worthy third

4


 

parties who are willing to assume this type of risk, for a determinable price, on major oil and gas production facilities and pipelines. Therefore, because determining such a market-risk premium would be an arbitrary process, we have excluded it from our SFAS No. 143 estimates.

During the first six months of 2003, ConocoPhillips’ overall asset retirement obligation changed as follows:

         
    Millions
    of Dollars
   
Opening balance at January 1, 2003
  $ 2,110  
Accretion of discount
    55  
New obligations
     
Spending on existing obligations
    (29 )
Property dispositions
    (19 )
Foreign currency remeasurement
    37  
Other adjustments
    473  

Ending balance at June 30, 2003
  $ 2,627  

The pro forma effects of the retroactive application of this change in accounting principle follows:

                                   
      Millions of Dollars
      Except Per Share Amounts
     
      Three Months Ended   Six Months Ended
      June 30   June 30
     
 
      2003   2002   2003   2002
     
 
Net income
  $ 1,138       360       2,430       268  
Earnings per share
                               
 
Basic
    1.67       .94       3.57       .70  
 
Diluted
    1.66       .93       3.55       .69  

           
      Millions
      of Dollars
     
      2002
     
Pro forma asset retirement obligation liability
       
 
At January 1, 2002
  $ 1,171  
 
At June 30, 2002
    1,264  

Also, effective January 1, 2003, we adopted SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” The adoption of SFAS No. 145 requires that gains and losses on extinguishments of debt no longer be presented as extraordinary items in the income statement. Accordingly, a loss from the extinguishment of debt of $15 million (after reduction for income taxes of $6 million), previously reported as an extraordinary item in the second quarter and six months of 2002, has been reclassified as a charge to other income with the appropriate tax benefit to provision for income taxes.

5


 

Note 3—Merger of Conoco and Phillips

On August 30, 2002, Conoco and Phillips combined their businesses by merging with separate acquisition subsidiaries of ConocoPhillips (the merger). As a result, each company became a wholly owned subsidiary of ConocoPhillips. For accounting purposes, Phillips was treated as the acquirer of Conoco, and ConocoPhillips was treated as the successor of Phillips. Conoco’s operating results have been included in ConocoPhillips’ consolidated financial statements since the merger date.

The $16 billion purchase price attributed to Conoco for accounting purposes was based on an exchange of Conoco common shares for ConocoPhillips common shares. The preliminary allocation of the purchase price to specific assets and liabilities was based, in part, upon a preliminary outside appraisal of the fair value of Conoco’s assets. ConocoPhillips expects to receive the final outside appraisal of the long-lived assets during the third quarter of 2003 and conclude the fair value determination of all other Conoco assets and liabilities. Subsequent to completion of the final allocation of the purchase price and determination of the ultimate asset and liability tax bases, the deferred tax liabilities will also be finalized in the third quarter. The following table summarizes, based on a June 30, 2003, preliminary purchase price allocation, the fair values of the assets acquired and liabilities assumed as of August 30, 2002:

         
    Millions
    of Dollars
   
Cash and cash equivalents
  $ 1,250  
Accounts and notes receivable
    2,830  
Inventories
    1,609  
Prepaid expenses and other current assets
    329  
Investments and long-term receivables
    3,032  
Properties, plants and equipment (including $300 million of land)
    18,871  
Goodwill
    12,841  
Intangibles
    633  
In-process research and development
    246  
Other assets
    301  

Total assets
  $ 41,942  

Accounts payable
  $ 2,873  
Notes payable and long-term debt due within one year
    3,101  
Accrued income and other taxes
    1,333  
Other accruals
    1,662  
Long-term debt
    8,930  
Accrued dismantlement, removal and environmental costs
    553  
Deferred income taxes
    3,797  
Employee benefit obligations
    1,638  
Other liabilities and deferred credits
    1,351  
Minority interests
    648  
Common stockholders’ equity
    16,056  

Total liabilities and equity
  $ 41,942  

The allocation of the purchase price, as reflected above, has not been adjusted for the U.S. Federal Trade Commission (FTC)-mandated dispositions described in Note 4—Discontinued Operations. Goodwill, land and certain identifiable intangible assets recorded in the acquisition are not subject to amortization, but the goodwill and intangible assets will be tested periodically for impairment as required by SFAS No. 142, “Goodwill and Other Intangible Assets.”

6


 

ConocoPhillips has not yet determined the assignment of Conoco goodwill to specific reporting units. Currently, Conoco goodwill is being reported as part of the Corporate and Other reporting segment. Included in the $12,841 million of goodwill is $4,026 million attributable to recording a net liability required under purchase accounting for deferred taxes. This and the remaining goodwill of $8,815 million will ultimately be assigned to reporting units based on the benefits received by the units from the synergies and strategic advantages of the merger. None of the goodwill is deductible for tax purposes. During the first six months of 2003, the balance of goodwill was adjusted upward by $762 million, primarily due to revisions to properties, plants and equipment, and assumed contingent liabilities.

Note 4—Discontinued Operations

During 2002 and the first six months of 2003, we disposed of, or had committed to a plan to dispose of, certain U.S. retail and wholesale marketing assets, certain U.S. refining and related assets, and exploration and production assets in the Netherlands. Certain of these planned dispositions were mandated by the FTC as a condition of the merger. For reporting purposes, these operations are classified as discontinued operations, and in Note 17—Segment Disclosures and Related Information, these operations are included in Corporate and Other.

FTC-Mandated Divestitures
In the fourth quarter of 2002, we sold our propane terminal assets at Jefferson City, Missouri, and East St. Louis, Illinois. In the second quarter of 2003 we sold:

    our Woods Cross business unit, which includes the Woods Cross, Utah, refinery; the Utah, Idaho, Montana, and Wyoming Phillips-branded motor fuel marketing operations (both retail and wholesale) and associated assets; and a refined products terminal in Spokane, Washington; and

    certain midstream natural gas gathering and processing assets in southeast New Mexico, and certain midstream natural gas gathering assets in West Texas.

In August 2003, we sold our Commerce City, Colorado, refinery, and related crude oil pipelines, and our Colorado Phillips-branded motor fuel marketing operations (both retail and wholesale). This completed our FTC-mandated asset dispositions.

Other Dispositions
In the fourth quarter of 2002, we committed to a plan to dispose of 3,200 marketing sites that do not fit into our long-range plans. Discussions are under way with potential buyers, and we expect to complete the sales of these assets by the end of 2003. The second quarter of 2003 included a $24 million after-tax charge for lease loss provisions expected from lease guaranteed residual value deficiencies that are being recognized as the company operates the sites until sold. The corresponding amount for the first six months of 2003 was $49 million.

7


 

Sales and other operating revenues and income from discontinued operations were as follows:

                                 
    Millions of Dollars
   
    Three Months Ended   Six Months Ended
    June 30   June 30
   
 
    2003   2002   2003   2002
   
 
Sales and other operating revenues from discontinued operations
  $ 2,373       1,492       4,555       2,808  

Income from discontinued operations before-tax
  $ 96       59       134       53  
Income tax expense
    37       20       53       18  

Income from discontinued operations
  $ 59       39       81       35  

The major classes of assets and liabilities of discontinued operations held for sale were as follows:

                 
    Millions of Dollars
   
    June 30   December 31
    2003   2002
   
Assets
               
Inventories
  $ 180       211  
Other current assets
    106       136  
Net properties, plants and equipment
    1,186       1,178  
Intangibles
    23       23  
Other assets
    67       57  

Assets of discontinued operations
  $ 1,562       1,605  

Liabilities
               
Accounts payable and other current liabilities
  $ 360       331  
Long-term debt
    33       34  
Accrued dismantlement, removal and environmental costs
    61       86  
Other liabilities and deferred credits
    156       198  

Liabilities of discontinued operations
  $ 610       649  

Note 5—Subsidiary Equity Transactions

ConocoPhillips, through various affiliates, and its unaffiliated co-venturers received final approvals from the relevant authorities in June 2003 to proceed with the natural gas development phase of the Bayu-Undan project in the Timor Sea. The natural gas development phase of the project will include a pipeline from the offshore Bayu-Undan field to Darwin, Australia, and a liquefied natural gas facility, also located in Darwin. The pipeline portion of the project is owned and operated by an unincorporated joint venture, while the liquefied natural gas facility is owned and operated by Darwin LNG Pty Ltd (DLNG). Both of these entities are consolidated subsidiaries of ConocoPhillips.

In June 2003, as part of a broad Bayu-Undan ownership interest re-alignment with co-venturers, these entities issued equity and sold interests to the co-venturers (as described below), which resulted in a gain of $28 million before-tax, $25 million after-tax, recorded in the second quarter of 2003. This non-operating gain is shown in the consolidated statement of income in the line item entitled “Gain on subsidiary equity transactions.”

8


 

DLNG—DLNG issued 118.9 million shares of stock, valued at 1 Australian dollar per share, to co-venturers for 118.9 million Australian dollars ($76.2 million U.S. dollars), reducing our ownership interest in DLNG from 100 percent to 56.72 percent. The transaction resulted in a before-tax gain of $21 million in the consolidated financial statements. Deferred income taxes were not recognized as this was an issuance of common stock and therefore not taxable.

Unincorporated Pipeline Joint Venture—The co-venturers purchased pro-rata interests in the pipeline assets held by ConocoPhillips Pipeline Australia Pty Ltd for $26.6 million U.S. dollars and contributed the purchased assets to the unincorporated joint venture, reducing our ownership interest from 100 percent to 56.72 percent. The transaction resulted in a before-tax gain of $7 million in the consolidated financial statements. A deferred tax liability of $1.3 million was recorded in connection with the transaction.

Note 6—Stock-Based Compensation

Effective January 1, 2003, ConocoPhillips adopted the fair-value accounting method of SFAS No. 123, “Accounting for Stock-Based Compensation.” Using the prospective transition method, we recognize compensation expense using the fair-value accounting method for all stock options granted or modified after December 31, 2002, whereas we continue to account for options granted prior to 2003 in accordance with Accounting Principles Board (APB) No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. The following table illustrates the effect on net income and earnings per share as if the fair-value-based method had been applied to all outstanding and unvested awards in each period.

                                   
      Millions of Dollars
     
      Three Months Ended   Six Months Ended
      June 30   June 30
     
 
      2003   2002   2003   2002
     
 
Net income, as reported
  $ 1,138       351       2,575       249  
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects
    9       9       18       22  
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effects
    16       12       34       71  

Pro forma net income
  $ 1,131       348       2,559       200  

Earnings per share:
                               
 
Basic—as reported
  $ 1.67       .91       3.79       .65  
 
Basic—pro forma
    1.66       .91       3.76       .52  
 
Diluted—as reported
    1.66       .91       3.77       .65  
 
Diluted—pro forma
    1.65       .90       3.74       .52  

The pro forma total stock-based employee compensation expense determined using the fair-value-based method was higher during the first six months of 2002, compared with the same period in 2003, due to the accelerated vesting of options triggered by the March 2002 shareholder approval of the merger.

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Note 7—Inventories

Inventories consisted of the following:

                 
    Millions of Dollars
   
    June 30   December 31
    2003   2002
   
Crude oil and petroleum products
  $ 3,674       3,395  
Canadian Syncrude (from mining operations)
    4       4  
Materials, supplies and other
    485       446  

 
  $ 4,163       3,845  

Inventories valued on a last-in, first-out (LIFO) basis totaled $3,482 million and $3,349 million at June 30, 2003, and December 31, 2002, respectively. The excess of current replacement cost over LIFO cost of inventories amounted to $1,079 million and $1,083 million at June 30, 2003, and December 31, 2002, respectively.

Note 8—Properties, Plants and Equipment

Properties, plants and equipment included the following:

                 
    Millions of Dollars
   
    June 30   December 31
    2003   2002
   
Properties, plants and equipment (at cost)
  $ 58,925       54,559  
Less accumulated depreciation, depletion and amortization
    13,661       11,529  

 
  $ 45,264       43,030  

Property Impairments—In the second quarter of 2003, we recorded property impairments totaling $146 million before-tax, $49 million after-tax. The impairments were recorded as a result of asset status changes from held for use to held for sale, unsuccessful development drilling results, and Norway tax law changes dealing with the treatment of asset removal costs. Of the total charges in the second quarter, $141 million before-tax, $46 million after-tax, were related to properties in the Exploration and Production segment, primarily in the North Sea, Canada, and the U.S. Lower 48. The remaining amounts related to the Corporate and Other reporting segment.

Note 9—Restructuring

In 2002, as a result of the merger, we began a restructuring program to capture the benefits of combining Conoco and Phillips by eliminating redundancies, consolidating assets, and sharing common services and functions across regions. As a result, we recognized an estimated restructuring liability for anticipated employee severance payments and incremental pension and medical plan benefit costs associated with work force reductions, site closings, and Conoco employee relocations. In the first six months of 2003, we recorded additional accruals totaling $225 million for severance-related benefits, site closings, Conoco

10


 

employee relocation costs, and pension and other post-retirement benefits. Of this total, $77 million was reflected as a purchase price adjustment in the consolidated financial statements and $148 million was reflected in selling, general and administrative expense and production and operating expense. Included in the total additional accruals of $225 million was an $83 million expense related to pension and other post-retirement benefits that will be paid in conjunction with other retirement benefits over a number of future years. This is reported as part of our employee benefit plan obligations. A roll-forward of activity during the first six months of 2003 is provided below for the non-pension portion of the accrual, which consists of severance-related benefits to be provided to approximately 3,800 employees worldwide, most of whom are in the United States, as well as other merger related expenses.

                                 
    Millions of Dollars
   
            Six Months 2003    
    Reserve at  
  Reserve at
    December 31, 2002   Accrual   Payments   June 30, 2003
   
 
 
 
Conoco
  $ 106       77       (64 )     119  
Phillips
    269       65       (166 )     168  

Total
  $ 375       142       (230 )     287  

The restructuring liability at June 30 of $287 million is expected to be expended by the end of the first quarter of 2004; except for $36 million, classified as long-term. The remaining $251 million is included in other accruals in the current liabilities section of the balance sheet. Approximately 1,550 employees were terminated during the first six months of 2003 and approximately 2,325 employees have been terminated since the restructuring program was implemented.

Note 10—Debt

At June 30, 2003, we had three bank credit facilities in place, totaling $4 billion, available for use either as direct bank borrowings or as support for the issuance of up to $4 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 billion, 364-day revolving credit facility expiring on October 14, 2003, and two revolving credit facilities totaling $2 billion expiring in October 2006. At June 30, 2003, we had no debt outstanding under these credit facilities, but had $801 million in commercial paper outstanding, of which $99 million was denominated in foreign currencies. The commercial paper is supported 100 percent by the credit facilities and the amount approximates fair value. One of our Norwegian subsidiaries has two $300 million revolving credit facilities that expire in June 2004, under which no borrowings were outstanding as of June 30, 2003.

During the first six months of 2003, in addition to reducing our commercial paper from $1,517 million at December 31, 2002, to $801 million at June 30, 2003, we paid the following notes as they were called or matured, and funded the payments with cash from operating activities and proceeds from asset dispositions:

    $250 million 8.49% notes due January 1, 2023, at 104.245 percent;

    $181 million SRW Cogeneration Limited Partnership note;

    $100 million 6.65% notes that matured on March 1, 2003;

    $250 million 7.92% notes due in 2023 at 103.96 percent;

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    $500 million floating rate notes due April 15, 2003; and

    $150 million 8.25% notes due May 15, 2003.

Note 11—Contingencies

We are subject to various lawsuits and claims including, but not limited to: actions challenging oil and gas royalty and severance tax payments; actions related to gas measurement and valuation methods; actions related to joint interest billings to operating agreement partners; and claims for damages resulting from leaking underground storage tanks, or other accidental releases, with related toxic tort claims. As a result of Conoco’s separation agreement with DuPont, we also have assumed responsibility for current and future claims related to certain discontinued chemicals and agricultural chemicals businesses operated by Conoco in the past. In general, the effect on future financial results is not subject to reasonable estimation because considerable uncertainty exists. The ultimate liabilities resulting from such lawsuits and claims may be material to results of operations in the period in which they are recognized.

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. 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.

As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates that are particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.

Environmental—We are subject to federal, state and local environmental laws and regulations. These may result in obligations to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various sites. When we prepare our financial statements, we record accruals for environmental liabilities based on management’s best estimate, 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 consider unasserted claims in our determination of environmental liabilities and we accrue them in the period that they are both probable and reasonably estimable.

Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all of the cleanup costs related to any site at which we have been designated as a potentially responsible party. If ConocoPhillips were solely responsible, the costs, in some cases, could be material to our, or one of our segment’s, operations, capital resources or liquidity. However, settlements and costs incurred in matters

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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, ConocoPhillips may have no liability or attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability and we adjust our accruals accordingly.

As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnification agreements and some of the indemnifications are subject to dollar limits and time limits. We have not recorded accruals for any potential contingent liabilities that we expect to be funded by the prior owners under these indemnifications.

We are currently participating in environmental assessments and cleanups at 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, if assumed in a purchase business combination, we record such costs 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. 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. At June 30, 2003, ConocoPhillips’ balance sheet included a total environmental accrual from continuing operations of $845 million, compared with $743 million at December 31, 2002. The increase in the accrual from year-end 2002, primarily resulted from the continuing assessment of Conoco environmental liabilities during the period allowed by purchase accounting rules. These accrued environmental liabilities assumed in the merger are discounted obligations. These expected expenditures are discounted using a weighted average 5 percent discount factor, resulting in an additional accrued balance of $113 million. The expected inflated expenditures for these additional accruals are: $25 million in 2003, $39 million in 2004, $18 million in 2005, $8 million in 2006, and $7 million in 2007. The remaining expenditures in all future years after 2007 for these additional accruals are expected to total $42 million. Final purchase price adjustments will be recognized in the third quarter of 2003.

Other Legal Proceedings—We are a party to a number of other legal proceedings pending in various courts or agencies for which, in some instances, no provision has been made.

Other Contingencies—We have contingent liabilities resulting from throughput agreements with pipeline and processing companies. 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 by ConocoPhillips. In addition, we have 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, 2003, we were liable for certain contingent obligations under various contractual arrangements as described below. We are required to recognize a liability at inception for the fair value of our obligation as a guarantor for guarantees issued or modified after December 31, 2002. Unless the carrying amount of the liability is noted, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial.

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Construction Completion Guarantees

    We have a construction completion guarantee related to debt and bond financing arrangements secured by the Merey Sweeny, L.P. (MSLP) joint-venture project at the Sweeny refinery in Old Ocean, Texas. The maximum potential amount of future payments under the guarantee, including joint-and-several debt at its gross amount, is estimated to be $403 million assuming that completion certification is not achieved. Of this amount, $202 million is attributable to Petroleos de Venezuela S.A. (PDVSA) because it is joint-and-severally liable for a portion of the debt. If completion certification is not attained by June 2004, the full debt balance becomes due. The debt becomes non-recourse upon completion certification.

    We also issued a construction completion guarantee related to debt financing arrangements for the Hamaca Holding LLC joint-venture project in Venezuela. The maximum potential amount of future payments under the guarantee is estimated to be $441 million, which could be payable if the full debt financing capacity is utilized and startup and completion of the Hamaca project is not achieved by October 1, 2005. The project financing debt is non-recourse upon startup and completion certification.

Guaranteed Residual Value on Leases

    We lease ocean transport vessels, corporate aircraft, service stations, office buildings, certain refining equipment, and other facilities and equipment under leases with remaining terms of up to eight years. Associated with these leases we have guaranteed approximately $1.7 billion in residual values, which are due at the end of the lease terms. However, those guaranteed amounts would be reduced by the fair market value of the leased assets returned.

Guarantees of Joint-Venture Debt

    At June 30, 2003, we had guarantees of about $356 million outstanding for our portion of joint-venture debt obligations, which have terms of up to 24 years. We have recognized an $11 million liability related to these guaranteed debt obligations. Payment will be required if a joint venture defaults on its debt obligations.

Other Guarantees

    In addition to the construction completion guarantee explained above, the MSLP agreement also requires the partners in the venture to pay cash calls as required to meet the minimum operating requirements of the venture, in the event revenues do not cover expenses over the next 20 years. Our maximum potential future payments under the agreement are estimated to be $303 million, assuming MSLP does not earn any revenue over the entire period and fixed costs cannot be reduced. To the extent revenue is generated by the venture or fixed costs are reduced, future required payments would be reduced accordingly.

    We have also guaranteed certain potential payments related to our interest in a drillship, which is operated by a joint venture. Potential payments could be required for the guaranteed residual value amount and the amount due under an interest rate hedging agreement. The maximum potential future payments under the agreements are estimated to be approximately $98 million.

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    In February 2003, we entered into two agreements establishing separate guarantee facilities for $50 million each for two LNG vessels. Under each such facility, we will be required to make payments should the charter revenue generated by the relevant 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 over the 20-year terms of the agreements could be up to $100 million. In the event the two ships are 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. Based on the current market view of both long-term and short-term shipping capacity, rates, and utilization probability, we estimated the fair value of the liability to be immaterial.

    We have other guarantees totaling $134 million, which consist primarily of dealer and jobber loan guarantees to support our marketing business, a guarantee supporting a lease assignment on a corporate aircraft and guarantees of lease payment obligations for a joint venture. These guarantees generally extend up to 15 years and payment would only be required if the dealer, jobber or lessee was in default.

Indemnifications

    Over the years, we have entered into various agreements to sell ownership interests in certain corporations and joint ventures. In addition, we entered into a Tax Sharing Agreement in 1998 related to Conoco’s separation from DuPont. These agreements typically include indemnifications for additional taxes determined to be due under the relevant tax law, in connection with operations for years prior to the sale or separation. Generally, the obligation extends until the related tax years are closed. The maximum potential amount of future payments under the indemnifications is the amount of additional tax determined to be due under relevant tax law and the various agreements. There are no material outstanding claims that have been asserted under these agreements.

    During the first six months of 2003, we sold several assets such as FTC-mandated downstream and midstream assets, upstream non-producing leasehold, and downstream retail and wholesale sites giving rise to qualifying indemnifications. We recognized a $4 million liability associated with these indemnifications. Arrangements associated with these sales include indemnifications for taxes, environmental liabilities, permits and licenses, employee claims and litigation. The maximum potential payout under these arrangements totals $124 million. Certain environmental indemnifications are not subject to this limitation. Payments for these environmental indemnifications would be equal to remediation costs for assets sold. All probable and estimable environmental liabilities associated with these assets have been accrued for under SFAS No. 5, “Accounting For Contingencies.” Environmental accruals associated with assets sold during the first six months of 2003 totaling $6 million are included in accrued dismantlement, removal and environmental costs in our consolidated balance sheet. For additional information about environmental liabilities, see Note 11—Contingencies.

    As part of our normal ongoing business operations and consistent with generally accepted and recognized industry practice, we enter into numerous agreements with other parties, which apportion future risks between the parties to the transaction or relationship governed by the agreements. One method of apportioning risk is the inclusion of provisions requiring one party to indemnify the other against losses that might otherwise be incurred by the other party in the future. Many of our agreements contain an indemnity or indemnities that require us to perform certain acts, such as remediation, as a result of the occurrence of a triggering event or condition. In some instances we indemnify third parties against losses resulting from certain events or conditions that arise out of operations conducted by our equity affiliates.

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    The nature of these indemnity obligations are diverse and numerous and each has different terms, business purposes, and triggering events or conditions. Consistent with customary business practice, any particular indemnity obligation incurred is the result of a negotiated transaction or contractual relationship for which we have accepted a certain level of risk in return for a financial or other type of benefit. In addition, the indemnities in each agreement vary widely in their definitions of both the triggering event and the resulting obligation, which is contingent on that triggering event.

    With regard to indemnifications, our risk management philosophy is to limit risk in any transaction or relationship to the maximum extent reasonable in relation to commercial and other considerations. Before accepting any indemnity obligation, we make an informed risk management decision considering, among other things, the remoteness of the possibility that the triggering event will occur, the potential costs to perform under any resulting indemnity obligation, possible actions to reduce the likelihood of a triggering event or to reduce the costs of performing under the indemnity obligation, whether we are indemnified by an unrelated third party, insurance coverage that may be available to offset the cost of the indemnity obligation, and the benefits from the transaction or relationship.

    Because many or most of our indemnity obligations are not limited in duration or potential monetary exposure, we cannot calculate the maximum potential amount of future payments that could be paid under our indemnity obligations stemming from all our existing agreements. We have disclosed significant contractual matters, including, but not limited to, indemnity obligations, which are reasonably possible to have a material impact on our financial performance in quarterly, annual and other reports required by applicable securities laws and regulations. We also accrue for contingent liabilities, including those arising out of indemnity obligations, when a loss is probable and the amounts can be reasonably estimated (see Note 11—Contingencies). We are not aware of the occurrence of any triggering event or condition that would have a material adverse impact on our financial statements as a result of an indemnity obligation relating to such triggering event or condition.

Note 13—Comprehensive Income

ConocoPhillips’ comprehensive income was as follows:

                                     
        Millions of Dollars
       
        Three Months Ended   Six Months Ended
        June 30   June 30
       
        2003   2002   2003   2002
       
Net income
  $ 1,138       351       2,575       249  
After-tax changes in:
                               
 
Minimum pension liability adjustment
                5        
 
Foreign currency translation adjustments
    134       51       266       50  
 
Unrealized gain (loss) on securities
    2       (2 )     2       (2 )
 
Hedging activities
    1             4        
 
Equity affiliates:
                               
   
Foreign currency translation
    58       16       90       12  
   
Derivatives related
          (1 )     1       (24 )

 
  $ 1,333       415       2,943       285  

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Accumulated other comprehensive income (loss) in the equity section of the balance sheet included:

                   
      Millions of Dollars
     
      June 30   December 31
      2003   2002
     
Minimum pension liability adjustment
  $ (231 )     (236 )
Foreign currency translation adjustments
    364       98  
Unrealized gain on securities
    3       1  
Deferred net hedging loss
    (1 )     (5 )
Equity affiliates:
               
 
Foreign currency translation
    91       1  
 
Derivatives related
    (22 )     (23 )

 
  $ 204       (164 )

Note 14—Supplemental Cash Flow Information

Cash payments for the six-month periods ended June 30 included the following:

                 
    Millions of Dollars
   
    2003   2002
   
Cash Payments
               
Interest
  $ 422       207  
Income taxes
    1,331       438  

Non-cash investing and financing activities for the six-month period of 2003 included a $1.6 billion increase in properties, plants and equipment and a related increase in long-term liabilities of $1.5 billion associated with the implementation and continuing application of SFAS No. 143. For additional information related to the implementation of SFAS No. 143, see Note 2—Changes in Accounting Principles.

Note 15—Sales of Receivables

At June 30, 2003, ConocoPhillips had sold certain credit card and trade receivables to two Qualifying Special Purpose Entities (QSPEs) in revolving-period securitization arrangements. These arrangements provide for us to sell, and the QSPEs to purchase, certain receivables and for the QSPEs to then issue beneficial interests of up to $1.5 billion to five bank-sponsored entities. We retain beneficial interests in the pools of receivables held by the QSPEs that are subordinate to the beneficial interests issued to the bank-sponsored entities. Our retained interests, reported on the balance sheet in accounts and notes receivable—related parties, were $1.3 billion at June 30, 2003, and December 31, 2002. We also retain servicing responsibility related to the sold receivables, the fair value of which approximates adequate compensation for the servicing costs incurred.

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In the first six months of 2003 and 2002, total cash flows received from and paid under the securitization arrangements were as follows:

                 
    Millions of Dollars
   
    2003   2002
   
Receivables sold at beginning of year
  $ 1,323       940  
New receivables sold
    13,849       8,489 *
Cash collections remitted
    (13,751 )     (8,540 )*

Receivables sold at June 30
  $ 1,421       889  

Discounts and other fees paid on revolving balances
  $ 11       10  

*New receivables sold and cash collections remitted under these ongoing revolving securitization arrangements have been revised due to correction of disclosure calculations.

At June 30, 2003, and December 31, 2002, we had sold $171 million and $264 million, respectively, of receivables under a factoring arrangement that included a recourse obligation to repurchase uncollected receivables.

Note 16—Related Party Transactions

Significant transactions with related parties were:

                                 
    Millions of Dollars
   
    Three Months Ended   Six Months Ended
    June 30   June 30
   
    2003   2002   2003   2002
   
Operating revenues (a)
  $ 922       195       2,009       350  
Purchases (b)
    794       235       1,679       438  
Operating expenses and selling, general and administrative expenses (c)
    144       30       282       64  
Net interest (income) expense (d)
    (12 )     3       (25 )     5  

(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) and refined products are sold primarily to CFJ Properties. Also, we charge several of our affiliates including CPChem, MSLP, Hamaca Holding LLC, and Venture Coke Company 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 crude oil from Petrozuata C.A. and refined products from Melaka and Ceská rafinérská, a.s. located in the Czech Republic. We also pay fees to various pipeline equity companies for transporting finished refined products.

(c)   We pay processing fees to various affiliates, the most significant being MSLP. Additionally, we pay contract drilling fees to deepwater drillship affiliates, crude oil transportation fees to pipeline equity companies, and commissions to the receivable monetization companies.

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(d)   We pay and/or receive interest to/from various affiliates including the receivable monetization companies and MSLP.

Elimination of our equity percentage share of profit or loss on the above transactions was not material.

Note 17—Segment Disclosures and Related Information

We have organized our reporting structure based on the grouping of similar products and services, resulting in five operating segments:

(1)   Exploration and Production (E&P)—This segment primarily explores for and produces crude oil, natural gas and natural gas liquids on a worldwide basis. At June 30, 2003, E&P was producing in the United States, the Norwegian and U.K. sectors of the North Sea, Canada, Nigeria, Venezuela, the Timor Sea, offshore Australia and China, Indonesia, the United Arab Emirates, Vietnam, Russia, and Ecuador. The E&P segment’s U.S. and international operations are disclosed separately for reporting purposes.

(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 30.3 percent equity investment in DEFS.

(3)   Refining and Marketing (R&M)—This segment refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. At June 30, 2003, we owned 12 refineries in the United States (excluding one refinery treated as discontinued operations that is reported in Corporate and Other); 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)   Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists primarily of our 50 percent equity investment in CPChem.

(5)   Emerging Businesses—This segment includes the development of new businesses beyond our traditional operations. Emerging Businesses includes natural gas-to-liquids technology, fuels technology, power generation and other emerging technologies.

Corporate and Other includes general corporate overhead, all interest income and expense, preferred dividend requirements of capital trusts, discontinued operations, restructuring charges and goodwill resulting from the merger, certain eliminations, and various other corporate activities. Corporate assets include all cash and cash equivalents.

We evaluate performance and allocate resources based on, among other items, net income. Intersegment sales are recorded at prices that approximate market value.

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Analysis of Results by Operating Segment

                                     
        Millions of Dollars
       
        Three Months Ended   Six Months Ended
        June 30   June 30
       
 
        2003   2002   2003   2002
       
 
Sales and Other Operating Revenues
                               
E&P
                               
 
United States
  $ 5,279       1,323       10,050       2,360  
 
International
    3,159       490       6,505       967  
 
Intersegment eliminations-U.S.
    (755 )     (309 )     (1,471 )     (530 )
 
Intersegment eliminations-international
    (782 )           (1,623 )      

   
E&P
    6,901       1,504       13,461       2,797  

Midstream
                               
 
Total sales
    889       168       2,509       355  
 
Intersegment eliminations
    (312 )     (49 )     (688 )     (156 )

   
Midstream
    577       119       1,821       199  

R&M
                               
 
United States
    13,333       8,783       27,742       15,833  
 
International
    4,585       4       9,373       8  
 
Intersegment eliminations-U.S.
    (96 )     (2 )     (217 )     (4 )
 
Intersegment eliminations-international
    (1 )           (1 )      

   
R&M
    17,821       8,785       36,897       15,837  

Chemicals
    4       4       7       6  
Emerging Businesses
    39       2       95       3  
Corporate and Other
    5             8       3  

Consolidated Sales and Other Operating Revenues
  $ 25,347       10,414       52,289       18,845  

Net Income (Loss)
                               
E&P
                               
 
United States
  $ 516       280       1,353       435  
 
International
    554       59       1,000       46  

   
Total E&P
    1,070       339       2,353       481  

Midstream
    25       12       56       24  

R&M
                               
 
United States
    227       73       483       (19 )
 
International
    74       (5 )     188        

   
Total R&M
    301       68       671       (19 )

Chemicals
    12       7       (11 )     (4 )
Emerging Businesses
    (23 )     (3 )     (57 )     (8 )
Corporate and Other
    (247 )     (72 )     (437 )     (225 )

Consolidated Net Income
  $ 1,138       351       2,575       249  

20


 

                     
        Millions of Dollars
       
        June 30   December 31
        2003   2002
       
 
Total Assets
               
E&P
               
 
United States
  $ 15,295       14,196  
 
International
    21,085       19,541  

   
Total E&P
    36,380       33,737  

Midstream
    1,741       1,931  

R&M
               
 
United States
    19,164       19,068 *
 
International
    4,480       4,117 *

   
Total R&M
    23,644       23,185  

Chemicals
    2,065       2,095  
Emerging Businesses
    708       737  
Corporate and Other**
    16,191       15,151  

Consolidated Total Assets
  $ 80,729       76,836  

* Reclassified to conform to 2003 presentation.
** Includes goodwill not yet allocated to reporting units of $12,841 million at June 30, 2003, and $12,079 million at December 31, 2002.

Note 18—Income Taxes

ConocoPhillips’ effective tax rates for the second quarter and first six months of 2003 were 38 percent and 46 percent, respectively, compared with 53 percent and 70 percent for the same periods a year ago. Contributing to the decline in both the second quarter and six months of 2003, compared with the corresponding periods in 2002, was the one-time impact of tax law changes in certain international jurisdictions. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was generally due to foreign taxes in excess of the domestic federal statutory rate. In addition, the 2002 period was impacted by a higher proportion of income in higher tax-rate jurisdictions and losses in lower tax-rate jurisdictions, including the partial impairment in the six-month period of an exploration prospect that had no corresponding tax benefit.

Note 19—New Accounting Standards

In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, “Consolidation of Variable Interest Entities,” (FIN 46) in an effort to expand upon and strengthen existing accounting guidance that addresses when a company should include in its consolidated financial statements the assets, liabilities and activities of another entity. In general, a variable interest entity (VIE) is a corporation, partnership, trust, or any other legal structure used for business purposes that either (a) does not have equity investors with voting rights or (b) has equity investors that do not provide sufficient financial resources for the entity to support its activities. FIN 46 requires a VIE to be consolidated by a company if that company is subject to a majority of the risk of loss from the VIE’s activities, is entitled to receive a majority of the VIE’s residual returns, or both (the company required to consolidate is called the primary beneficiary). It also requires deconsolidation of a VIE if a company is not the primary beneficiary of the VIE. The interpretation also requires disclosures about VIEs that we are not required to consolidate, but in which we have a significant variable interest. The consolidation requirements of FIN 46 applied immediately to VIEs created after January 31, 2003, and will apply to older VIEs effective July 1, 2003. For our VIEs created before January 31, 2003, we plan to adopt this pronouncement in the third quarter of 2003, with retroactive application as of January 1, 2003.

21


 

    Application of FIN 46 will require consolidation of certain VIEs related to our leasing arrangements, including those related to ocean vessels, marketing sites and office buildings, and is expected to increase assets (primarily net properties, plants and equipment) by approximately $1.8 billion, increase debt by approximately $2.4 billion, increase minority interests by approximately $90 million, reduce other accruals by $275 million and result in a cumulative after-tax effect-of-adoption loss that is expected to decrease net income and stockholders’ equity by approximately $260 million. Our maximum exposure to loss as a result of our involvement with these entities is the debt of the entity, less the fair value of the assets at the end of the lease terms.

    Ashford Energy Capital S.A. will continue to be consolidated in our financial statements by the provisions of FIN 46, because we are the primary beneficiary. In December 2001, in order to raise funds for various corporate purposes, Conoco and Cold Spring Finance S.a.r.l. formed Ashford Energy Capital S.A. through the contribution of a $1 billion Conoco subsidiary promissory note and $500 million cash. Through its initial $500 million investment, Cold Spring is entitled to a cumulative annual preferred return, based on three-month LIBOR rates, plus 1.27 percent. In 2008 and each 10-year anniversary thereafter, Cold Spring may elect to sell their investment in Ashford, and if unsuccessful, could require ConocoPhillips to provide a letter of credit in support of Cold Spring's investment or cause the redemption of their interest in Ashford. Should ConocoPhillips’ credit rating fall below investment grade, Ashford would require a letter of credit to support various term loans, totaling $582 million as of June 30, 2003, made by Ashford to other ConocoPhillips subsidiaries. If the letter of credit could not be obtained within 60 days, Cold Spring could cause Ashford to sell the ConocoPhillips subsidiary notes. At June 30, 2003, Ashford held $1.6 billion of ConocoPhillips subsidiary notes. ConocoPhillips currently reports Cold Spring’s investment as a minority interest.

    Under the provisions of FIN 46, Phillips 66 Capital II (Trust) will cease to be consolidated in our financial statements. During 1997 in order to raise funds for general corporate purposes, we formed the Trust (a statutory business trust), in which we own all common beneficial interests. The Trust was created for the sole purpose of issuing mandatorily redeemable preferred securities to third-party investors and investing the proceeds thereof in an approximately equivalent amount of subordinated debt securities of ConocoPhillips, which were eliminated in consolidation. Application of FIN 46 will require deconsolidation of the Trust, which will result in debt increasing by $361 million since the 8% Junior Subordinated Deferrable Interest Debentures due 2037 will no longer be eliminated in consolidation, and the $350 million of mandatorily redeemable preferred securities will be deconsolidated.

In April 2003, the FASB released SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” most of which must be adopted prospectively as of July 1, 2003. We have reviewed this new release and do not expect adoption of this standard to have a material impact on our results of operations or financial position.

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 is already effective for all contracts created or modified after May 31, 2003, and became effective July 1, 2003, for all previously existing contracts. Applying the new rule, we expect to reclassify $141 million of currently reported minority interest securities to debt.

22


 

Supplementary Information—Condensed Consolidating Financial Information

In connection with the merger of ConocoPhillips Holding Company (formerly named Conoco Inc.) and ConocoPhillips Company (formerly named Phillips Petroleum Company) with wholly owned subsidiaries of ConocoPhillips, and to simplify our credit structure, we have established various cross guarantees between ConocoPhillips, ConocoPhillips Holding Company, and ConocoPhillips Company. With the new organizational structure, ConocoPhillips Company is the direct or indirect parent of former Conoco and Phillips subsidiaries and is wholly owned by ConocoPhillips Holding Company, which is wholly owned by ConocoPhillips. ConocoPhillips and ConocoPhillips Holding Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. Similarly, ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Holding Company with respect to the publicly held debt securities of ConocoPhillips Holding Company. In addition, ConocoPhillips Company and ConocoPhillips Holding Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:

    ConocoPhillips, ConocoPhillips Holding Company, ConocoPhillips Company, (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting);

    All other non-guarantor subsidiaries of ConocoPhillips Holding Company and ConocoPhillips Company; and

    The consolidating adjustments necessary to present ConocoPhillips’ results on a consolidated basis.

Effective June 30, 2003, Bayway Refining Company and Marcus Hook Refining Company were merged into ConocoPhillips Company. Previously reported prior period information has been restated to reflect this reorganization of companies under common control.

This condensed consolidating financial information should be read in conjunction with our accompanying consolidated financial statements and notes.

23


 

                                                   
      Millions of Dollars
     
      Three Months Ended June 30, 2003
     
              ConocoPhillips   ConocoPhillips   All Other   Consolidating   Total
Income Statement   ConocoPhillips   Holding Company   Company   Subsidiaries   Adjustments   Consolidated
   
 
 
 
 
 
Revenues
                                               
Sales and other operating revenues
  $             16,407       8,940             25,347  
Equity in earnings of affiliates
    1,093       1,055       1,121       139       (3,252 )     156  
Other income
                41       51             92  
Intercompany revenues
    7       150       794       1,294       (2,245 )      

 
Total Revenues
  1,100       1,205       18,363       10,424       (5,497 )     25,595  

Costs and Expenses
                                               
Purchased crude oil and products
                14,260       4,017       (1,899 )     16,378  
Production and operating expenses
                1,052       911       (66 )     1,897  
Selling, general and administrative expenses
    4             482       146       (8 )     624  
Exploration expenses
                28       114             142  
Depreciation, depletion and amortization
                296       551             847  
Property impairments
                26       120             146  
Taxes other than income taxes
                803       2,821             3,624  
Accretion on discounted liabilities
                6       29             35  
Interest and debt expense
    34       91       304       27       (272 )     184  
Foreign currency transaction losses (gains)
                (8 )     (12 )           (20 )
Preferred dividend requirements of capital trusts and minority interests
                      13             13  

 
Total Costs and Expenses
    38       91       17,249       8,737       (2,245 )     23,870  

Income from continuing operations before income taxes and subsidiary equity transactions
    1,062       1,114       1,114       1,687       (3,252 )     1,725  
Gain on subsidiary equity transactions
                      28             28  

Income from continuing operations before income taxes
    1,062       1,114       1,114       1,715       (3,252 )     1,753  
Provision for income taxes
    (17 )     21       80       590             674  

Income from continuing operations
    1,079       1,093       1,034       1,125       (3,252 )     1,079  
Income from discontinued operations
    59       59       59       54       (172 )     59  

Income before accounting change
    1,138       1,152       1,093       1,179       (3,424 )     1,138  
Accounting change
                                   

Net Income
  $ 1,138       1,152       1,093       1,179       (3,424 )     1,138  

24


 

                                                   
      Millions of Dollars
     
      Six Months Ended June 30, 2003
     
              ConocoPhillips   ConocoPhillips   All Other   Consolidating   Total
Income Statement   ConocoPhillips   Holding Company   Company   Subsidiaries   Adjustments   Consolidated
   
 
 
 
 
 
Revenues
                                               
Sales and other operating revenues
  $             34,169       18,120             52,289  
Equity in earnings of affiliates
    2,377       2,302       2,254       220       (6,948 )     205  
Other income
                (116 )     294             178  
Intercompany revenues
    14       300       1,778       2,832       (4,924 )      

 
Total Revenues
  2,391       2,602       38,085       21,466       (11,872 )     52,672  

Costs and Expenses
                                               
Purchased crude oil and products
                29,432       8,852       (4,220 )     34,064  
Production and operating expenses
                2,007       1,680       (141 )     3,546  
Selling, general and administrative expenses
    5             893       245       (10 )     1,133  
Exploration expenses
                59       199             258  
Depreciation, depletion and amortization
                582       1,114             1,696  
Property impairments
                26       148             174  
Taxes other than income taxes
                2,060       4,986             7,046  
Accretion on discounted liabilities
                13       55             68  
Interest and debt expense
    65       184       613       84       (553 )     393  
Foreign currency transaction losses (gains)
                (16 )     (7 )           (23 )
Preferred dividend requirements of capital trusts and minority interests
                      27             27  

 
Total Costs and Expenses
    70       184       35,669       17,383       (4,924 )     48,382  

Income from continuing operations before income taxes and subsidiary equity transactions
    2,321       2,418       2,416       4,083       (6,948 )     4,290  
Gain on subsidiary equity transactions
                      28             28  

Income from continuing operations before income taxes
    2,321       2,418       2,416       4,111       (6,948 )     4,318  
Provision for income taxes
    (28 )     41       148       1,808             1,969  

Income from continuing operations
    2,349       2,377       2,268       2,303       (6,948 )     2,349  
Income from discontinued operations
    81       81       81       63       (225 )     81  

Income before accounting change
    2,430       2,458       2,349       2,366       (7,173 )     2,430  
Accounting change
    145       145       145       147       (437 )     145  

Net Income
  $ 2,575       2,603       2,494       2,513       (7,610 )     2,575  

25


 

                                                   
      Millions of Dollars
     
      Three Months Ended June 30, 2002
     
              ConocoPhillips   ConocoPhillips   All Other   Consolidating   Total
Income Statement   ConocoPhillips   Holding Company   Company   Subsidiaries   Adjustments   Consolidated
   
 
 
 
 
 
Revenues
                                               
Sales and other operating revenues
  $             7,946       2,468               10,414  
Equity in earnings of affiliates
              393       25         (389 )     29  
Other income
              34       (12 )             22  
Intercompany revenues
              649       906         (1,555 )      

 
Total Revenues
              9,022       3,387         (1,944 )     10,465  

Costs and Expenses
                                               
Purchased crude oil and products
              6,943       1,642         (1,431 )     7,154  
Production and operating expenses
              553       370         (41 )     882  
Selling, general and administrative expenses
              196       24         (13 )     207  
Exploration expenses
              8       48         11       67  
Depreciation, depletion and amortization
              145       250             395  
Property impairments
                    8             8  
Taxes other than income taxes
              704       273             977  
Accretion on discounted liabilities
              4       2             6  
Interest and debt expense
              170       17         (81 )     106  
Foreign currency transaction losses (gains)
                    (6 )           (6 )
Preferred dividend requirements of capital trusts and minority interests
                    12             12  

 
Total Costs and Expenses
              8,723       2,640         (1,555 )     9,808  

Income from continuing operations before income taxes and subsidiary equity transactions
              299       747         (389 )     657  
Gain on subsidiary equity transactions
                                 

Income from continuing operations before income taxes
              299       747         (389 )     657  
Provision for income taxes
              (13 )     358             345  

Income from continuing operations
              312       389         (389 )     312  
Income from discontinued operations
              39       24         (24 )     39  

Income before accounting change
              351       413         (413 )     351  
Accounting change
                                 

Net Income
$             351       413         (413 )     351  

26


 

                                                   
      Millions of Dollars
     
      Six Months Ended June 30, 2002
     
              ConocoPhillips   ConocoPhillips   All Other   Consolidating   Total
Income Statement   ConocoPhillips   Holding Company   Company   Subsidiaries   Adjustments   Consolidated
   
 
 
 
 
 
Revenues
                                               
Sales and other operating revenues
  $               14,236       4,609             18,845  
Equity in earnings of affiliates
                  560       51       (562 )     49
Other income
                  41       10             51  
Intercompany revenues
                  1,196       1,551       (2,747 )    

 
Total Revenues
                16,033       6,221       (3,309 )     18,945  

Costs and Expenses
                                               
Purchased crude oil and products
                  12,341       2,957       (2,505 )     12,793  
Production and operating expenses
                  1,153       726       (80 )     1,799
Selling, general and administrative expenses
                  420       72       (21 )     471  
Exploration expenses
                  37       193             230
Depreciation, depletion and amortization
                  293       498             791  
Property impairments
                        18             18
Taxes other than income taxes
                  1,368       523             1,891  
Accretion on discounted liabilities
                  7       4             11
Interest and debt expense
                  324       30       (141 )     213  
Foreign currency transaction losses (gains)
                        (5 )           (5 )
Preferred dividend requirements of capital trusts and minority interests
                        25             25  

 
Total Costs and Expenses
                  15,943       5,041       (2,747 )     18,237

Income from continuing operations before income taxes and subsidiary equity transactions
                  90       1,180       (562 )     708  
Gain on subsidiary equity transactions
                                   

Income from continuing operations before income taxes
                  90       1,180       (562 )     708  
Provision for income taxes
                  (124 )     618             494

Income from continuing operations
                  214       562       (562 )     214  
Income from discontinued operations
                  35       31       (31 )     35

Income before accounting change
                  249       593       (593 )     249  
Accounting change
                                   

Net Income
  $               249       593       (593 )     249  

27


 

                                                   
      Millions of Dollars
     
      At June 30, 2003
     
              ConocoPhillips   ConocoPhillips   All Other   Consolidating   Total
Balance Sheet   ConocoPhillips   Holding Company   Company   Subsidiaries   Adjustments   Consolidated
   
 
 
 
 
 
Assets
                                               
Cash and cash equivalents
  $             178       346           524  
Accounts and notes receivable
    1       286       30,870       10,270       (36,752 )     4,675  
Inventories
                3,014       1,149             4,163  
Prepaid expenses and other current assets
    7             319       376       (45 )     657  
Assets of discontinued operations
                238       1,324             1,562  

 
Total Current Assets
    8       286       34,619       13,465       (36,797 )     11,581  
Investments and long-term receivables
    39,455       36,752       43,953       23,665       (136,758 )     7,067  
Net properties, plants and equipment
                15,566       29,698             45,264  
Goodwill*
                2,347       12,859             15,206  
Intangibles
                450       663             1,113  
Other assets
    12       17       114       355             498  

Total
  $ 39,475       37,055       97,049       80,705       (173,555 )   80,729  

Liabilities and Stockholders’ Equity
                                               
Accounts payable
  $ 10,747       152       17,057       15,309       (36,752 )   6,513  
Notes payable and long-term debt due within one year
          1,379       155       10             1,544  
Accrued income and other taxes
    (6 )     94       884       2,144             3,116  
Other accruals
    20       55       1,359       1,391             2,825  
Liabilities of discontinued operations
                68       542             610  

 
Total Current Liabilities
    10,761       1,680       19,523       19,396       (36,752 )     14,608  
Long-term debt
    2,794       2,702       6,492       4,037             16,025  
Accrued dismantlement, removal and environmental costs
                641       2,623             3,264  
Deferred income taxes
          (41 )     2,904       5,923       (8 )     8,778  
Employee benefit obligations
                1,297       1,358             2,655  
Other liabilities and deferred credits
          5,808       42,523       20,774       (66,811 )     2,294  

Total Liabilities
    13,555       10,149       73,380       54,111       (103,571 )     47,624  
Trust preferred securities and other minority interests
          (12 )           1,085             1,073  
Retained earnings
    1,098       465       7,089       8,949       (9,931 )     7,670  
Other stockholders’ equity
    24,822       26,453       16,580       16,560       (60,053 )     24,362  

Total
  $ 39,475       37,055       97,049       80,705       (173,555 )   80,729  

* ConocoPhillips has not yet determined the assignment of Conoco goodwill to specific reporting units and related subsidiaries. Currently, Conoco goodwill is reported as part of the Corporate and Other reporting segment in All Other Subsidiaries.

28


 

                                                   
      Millions of Dollars
     
      At December 31, 2002
     
              ConocoPhillips   ConocoPhillips   All Other   Consolidating   Total
Balance Sheet   ConocoPhillips   Holding Company   Company   Subsidiaries   Adjustments   Consolidated
   
 
 
 
 
 
Assets
                                               
Cash and cash equivalents
  $             116       191             307  
Accounts and notes receivable
    8             21,652       13,504       (30,784 )     4,380  
Inventories
                2,811       1,034             3,845  
Prepaid expenses and other current assets
    5             186       511       64       766  
Assets of discontinued operations
                264       1,341             1,605  

 
Total Current Assets
    13             25,029       16,581       (30,720 )     10,903  
Investments and long-term receivables
    32,301       35,538       40,654       21,897       (123,569 )     6,821  
Net properties, plants and equipment
                15,407       27,623             43,030  
Goodwill*
                2,350       12,094             14,444  
Intangibles
                457       662             1,119  
Other assets
    14       19       113       373             519  

Total
  $ 32,328       35,557       84,010       79,230       (154,289 )     76,836  

Liabilities and Stockholders’ Equity
                                               
Accounts payable
  $ 5,840       3,291       15,200       12,705       (30,784 )     6,252  
Notes payable and long-term debt due within one year
          526       314       9             849  
Accrued income and other taxes
    (1 )     53       518       1,421             1,991  
Other accruals
    21       58       1,421       1,575             3,075  
Liabilities of discontinued operations
                124       525             649  

 
Total Current Liabilities
    5,860       3,928       17,577       16,235       (30,784 )     12,816  
Long-term debt
    3,509       4,054       7,105       4,249             18,917  
Accrued dismantlement, removal and environmental costs
                452       1,214             1,666  
Deferred income taxes
          (41 )     2,560       5,850       (8 )     8,361  
Employee benefit obligations
                1,401       1,354             2,755  
Other liabilities and deferred credits
          3,729       33,260       24,997       (60,183 )     1,803  

Total Liabilities
    9,369       11,670       62,355       53,899       (90,975 )     46,318  
Trust preferred securities and other minority interests
          (12 )           1,013             1,001  
Retained earnings
    (937 )     (1,349 )     5,746       9,749       (7,588 )     5,621  
Other stockholders’ equity
    23,896       25,248       15,909       14,569       (55,726 )     23,896  

Total
  $ 32,328       35,557       84,010       79,230       (154,289 )     76,836  

* ConocoPhillips has not yet determined the assignment of Conoco goodwill to specific reporting units and related subsidiaries. Currently, Conoco goodwill is reported as part of the Corporate and Other reporting segment in All Other Subsidiaries.

29


 

                                                 
    Millions of Dollars
   
    Six Months Ended June 30, 2003
   
            ConocoPhillips   ConocoPhillips   All Other   Consolidating   Total
Statement of Cash Flows   ConocoPhillips   Holding Company   Company   Subsidiaries   Adjustments   Consolidated
   
 
 
 
 
 
Cash Flows From Operating Activities
                                               
Net cash provided by (used in) continuing operations
  $ 3,026       (770 )     1,413       4,664       (3,115 )     5,218  
Net cash provided by discontinued operations
                16       60             76  

Net Cash Provided by (Used in) Operating Activities
    3,026       (770 )     1,429       4,724       (3,115 )     5,294  

Cash Flows From Investing Activities
                                               
Capital expenditures and investments, including dry holes
          (44 )     (1,287 )     (2,105 )     553       (2,883 )
Proceeds from asset dispositions
                70       521             591  
Long-term advances to affiliates and other investments
    (1,799 )     30       (7,620 )     (2,413 )     11,766       (36 )

Net cash used in continuing operations
    (1,799 )     (14 )     (8,837 )     (3,997 )     12,319       (2,328 )
Net cash used in discontinued operations
                (40 )     (17 )           (57 )

Net Cash Used in Investing Activities
    (1,799 )     (14 )     (8,877 )     (4,014 )     12,319       (2,385 )

Cash Flows From Financing Activities
                                               
Issuance of debt
          2,073       9,051       911       (11,766 )     269  
Repayment of debt
    (717 )     (500 )     (785 )     (449 )           (2,451 )
Issuance of company common stock
    33                               33  
Redemption of preferred stock of subsidiary
                                   
Dividends paid on common stock
    (543 )     (789 )     (789 )     (1,537 )     3,115       (543 )
Other
                33       520       (553 )      

Net Cash Provided by (Used in) Financing Activities
    (1,227 )     784       7,510       (555 )     (9,204 )     (2,692 )

Net Change in Cash and Cash Equivalents
                62       155             217  
Cash and cash equivalents at beginning of year
                116       191             307  

Cash and Cash Equivalents at End of Period
  $             178       346             524  

30


 

                                                 
    Millions of Dollars
   
    Six Months Ended June 30, 2002
   
            ConocoPhillips   ConocoPhillips   All Other   Consolidating   Total
Statement of Cash Flows   ConocoPhillips   Holding Company   Company   Subsidiaries   Adjustments   Consolidated
   
 
 
 
 
 
Cash Flows From Operating Activities
                                               
Net cash provided by (used in) continuing operations
  $             (2,327 )     3,756       (370 )     1,059  
Net cash provided by (used in) discontinued operations
                (23 )     73             50  

Cash Provided by (Used in) Operating Activities
                (2,350 )     3,829       (370 )     1,109  

Cash Flows From Investing Activities
                                               
Capital expenditures and investments, including dry holes
                (410 )     (1,117 )     8       (1,519 )
Proceeds from asset dispositions
                24       60       (3 )     81  
Long-term advances to affiliates and other investments
                (651 )     (3,049 )     3,702       2  

Net cash used in continuing operations
                (1,037 )     (4,106 )     3,707       (1,436 )
Net cash used in discontinued operations
                (4 )     (20 )           (24 )

Net Cash Used in Investing Activities
                (1,041 )     (4,126 )     3,707       (1,460 )

Cash Flows From Financing Activities
                                               
Issuance of debt
                4,269       673       (3,702 )     1,240  
Repayment of debt
                (620 )     (1 )     310       (311 )
Issuance of company common stock
                33                   33  
Redemption of preferred stock of subsidiaries
                      (300 )           (300 )
Dividends paid on common stock
                (275 )     (55 )     55       (275 )
Other
                (7 )     (26 )           (33 )

Net Cash Provided by Financing Activities
                3,400       291       (3,337 )     354  

Net Change in Cash and Cash Equivalents
                9       (6 )           3  
Cash and cash equivalents at beginning of year
                20       122             142  

Cash and Cash Equivalents at End of Period
  $             29       116             145  

31


 

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS 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. The company does 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 company’s 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, 2003, is based on a comparison with the corresponding periods of 2002. The merger of Conoco Inc. (Conoco) and Phillips Petroleum Company (Phillips) on August 30, 2002, impacts the comparability of the 2003 periods with the corresponding 2002 periods.

Conoco and Phillips Merger

On August 30, 2002, Conoco and Phillips combined their businesses by merging with wholly owned subsidiaries of a new company named ConocoPhillips (the merger). The merger was accounted for using the purchase method of accounting, with Phillips designated as the acquirer for accounting purposes. Because Phillips was designated as the acquirer, it is treated as the predecessor to ConocoPhillips and its operations and results are presented in this quarterly report for all periods prior to the close of the merger. From the merger date forward, the operations and results of ConocoPhillips reflect the combined operations of the two companies. For additional information on the merger, see Note 3—Merger of Conoco and Phillips, in the Notes to Consolidated Financial Statements.

Consolidated Results

                               
    Millions of Dollars
   
    Three Months Ended     Six Months Ended
    June 30     June 30
   
   
    2003     2002     2003     2002
   
   
Income from continuing operations
  $ 1,079       312       2,349       214
Income from discontinued operations
    59       39       81       35
Cumulative effect of accounting change
                145      

Net income
  $ 1,138       351       2,575       249

32


 

A summary of net income (loss) by business segment follows:

                                 
    Millions of Dollars  
   
 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
   
   
 
    2003     2002     2003     2002  
   
   
 
Exploration and Production (E&P)
  $ 1,070       339       2,353       481  
Midstream
    25       12       56       24  
Refining and Marketing (R&M)
    301       68       671       (19 )
Chemicals
    12       7       (11 )     (4 )
Emerging Businesses
    (23 )     (3 )     (57 )     (8 )
Corporate and Other
    (247 )     (72 )     (437 )     (225 )

 
Net income
  $ 1,138       351       2,575       249  

 

Net income was $1,138 million in the second quarter of 2003, compared with net income of $351 million in the second quarter of 2002. Net income was $2,575 million in the six-month period ending June 30, 2003, compared with $249 million in the corresponding period of 2002. The improved results in both periods primarily were due to increased upstream and downstream production volumes as a result of the merger, higher crude oil and natural gas sales prices in our E&P segment, and improved refining margins and wholesale gasoline margins in our R&M segment. See the “Segment Results” section for additional information on our E&P and R&M results, as well as our other reporting segments.

Income Statement Analysis

Sales and other operating revenues increased 143 percent in the second quarter of 2003, and 177 percent in the six-month period. The increases were attributable to both higher sales volumes and sales prices of key products such as crude oil, natural gas, automotive gasoline and distillates. Most of our sales volume increases were the result of the merger, while market factors led to increased sales prices of key products.

Equity in earnings of affiliates increased 438 percent in the second quarter of 2003, and 318 percent in the six-month period. Our share of earnings from affiliates acquired in the merger accounted for the majority of the increased equity earnings. Of these, our E&P joint ventures in Canada (Petrovera) and Venezuela (Petrozuata) provided the largest equity earnings. Of those equity affiliates included in the results of both years, our equity earnings from Duke Energy Field Service, LLC improved on higher natural gas liquids prices and gains on asset sales, and our earnings from Hamaca, an E&P joint venture in Venezuela, increased due to increased crude oil production volumes.

Other income increased 318 percent in the second quarter of 2003, and 249 percent in the six-month period. The increase in the second quarter of 2003 mainly was attributable to higher net gains on asset dispositions, additional operations following the merger, and a business interruption insurance settlement. In addition, the increase in the six-month period of 2003 was also attributable to insurance demutualization benefits. See the Corporate and Other section of “Segment Results” for additional information on the insurance benefits.

Purchased crude oil and products increased 129 percent in the second quarter of 2003, and 166 percent in the six-month period. The increase in both periods was attributable to both higher purchase volumes and purchase prices of petroleum products such as automotive gasoline and distillates, as well as higher

33


 

purchase volumes and purchase prices for crude oil, which is used as a feedstock in our refineries. Most of our purchase volume increases were the result of the merger, while market factors led to increased purchase prices of key products.

Production and operating expenses increased 115 percent in the second quarter of 2003 and 97 percent in the six-month period, while selling, general and administrative expenses increased 201 percent and 141 percent, respectively. These increases primarily reflect:

    the larger size of our operations and staffing following the merger;
    merger-related costs of $201 million before-tax in the second quarter of 2003 and $235 million in the first six months of 2003;
    higher fuel and utility costs at our refineries due to increased natural gas prices; and
    accrued losses of $38 million before-tax in the second quarter of 2003 and $77 million in the first six months due to plans to terminate operating leases that provided for guaranteed residual values related to various retail sites that we plan to keep, but are planning to convert from leased sites to company-owned sites.

Exploration expenses increased 112 percent in the second quarter of 2003, and 12 percent in the six-month period. The increase in the second quarter of 2003 reflects the increased size of our exploration program following the merger, as well as higher dry hole costs. In the first quarter of 2002, we recognized a $77 million partial impairment of our leasehold investment in deepwater Block 34, offshore Angola. The absence of such a significant item in the first six months of 2003 contributed to the lower percentage increase in the six-month period.

Depreciation, depletion and amortization increased 114 percent in the second quarter and six-month period of 2003. The increases mainly were the result of our increased depreciable base of properties, plants and equipment (PP&E) after the merger. The amount of our net PP&E at June 30, 2003, was $45.3 billion, compared with $22.9 billion at June 30, 2002.

Property impairments increased significantly in the second quarter and first six months of 2003. The 2003 impairments were recorded as a result of asset status changes from held for use to held for sale, unsuccessful development drilling results, and tax law changes in Norway dealing with asset removal costs. See Note 8—Properties, Plants and Equipment, in the Notes to Consolidated Financial Statements, for additional information.

Taxes other than income taxes increased 271 percent in the second quarter of 2003, and 273 percent in the six-month period. The increase in both periods reflects higher excise taxes due to increased petroleum products sales volumes, higher production taxes due to increased crude oil production and prices, and increased property and payroll taxes, all following the merger.

Accretion on discounted liabilities increased 483 percent in the second quarter of 2003, and 518 percent in the six-month period. Both increases reflect the impact of environmental liabilities assumed in the merger. Effective January 1, 2003, this item also includes the accretion related to discounted obligations associated with the retirement and removal of long-lived assets. See Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements, for additional information.

Interest expense increased 74 percent in the second quarter of 2003, and 85 percent in the six-month period. Both increases mainly were due to our higher debt levels following the merger. Our total debt at June 30, 2003, was $17.6 billion, compared with $9.6 billion at June 30, 2002.

34


 

Our effective tax rate for the second quarter of 2003 was 38 percent, compared with 53 percent for the same period in the prior year. Our effective tax rate for the first six months of 2003 was 46 percent, compared with 70 percent for the corresponding period in 2002. The lower effective tax rates in the 2003 periods primarily were the result of the one-time impact of tax law changes in certain international jurisdictions and a higher proportion of income in lower-tax-rate jurisdictions. Contributing to the higher effective tax rate in the six-month 2002 period was the partial impairment of an exploration prospect that had no corresponding tax benefit.

Income from discontinued operations was $59 million in the second quarter of 2003, compared with $39 million in the second quarter of 2002. For the six-month periods, income from discontinued operations was $81 million in 2003, compared with $35 million in 2002. The improvement in the 2003 periods reflects the addition of assets classified as discontinued following the merger, as well as higher marketing margins and reduced depreciation expense. The improvement was partially offset by $24 million in the second quarter of 2003 and $49 million in the six-month period of losses expected from plans to terminate operating leases that provide for guaranteed residual values for retail sites that we plan to sell. For additional information about discontinued operations, see Note 4—Discontinued Operations, in the Notes to Consolidated Financial Statements.

We recognized higher foreign currency transaction gains in both the second quarter and six-month period of 2003, while preferred dividend requirements and minority interests increased slightly.

In the second quarter of 2003, we recognized a $28 million gain on subsidiary equity transactions related to our E&P Bayu-Undan development in the Timor Sea. See Note 5—Subsidiary Equity Transactions, in the Notes to Consolidated Financial Statements, for additional information.

We adopted Financial Accounting Standards Board Statement No. 143, “Accounting for Asset Retirement Obligations,” (SFAS No. 143) effective January 1, 2003. As a result, we recognized a benefit of $145 million for the cumulative effect of this accounting change in the first quarter of 2003. For additional information on this accounting change, see Note 2—Changes in Accounting Principles, in the Notes to Consolidated Financial Statements.

Restructuring Accruals

As a result of the merger, we began a restructuring program in September 2002 to capture the benefits of combining Conoco and Phillips by eliminating redundancies, consolidating assets, and sharing common services and functions across regions. We expect the restructuring program to be completed by the end of the first quarter of 2004. From September 2002 through June 30, 2003, approximately 3,800 positions worldwide had been identified for elimination. Of this total, 2,325 employees had been terminated by June 30, 2003.

35


 

A roll-forward of activity during the first six months of 2003 is provided in the table below for the non-pension portion of the accrual.

                                 
    Millions of Dollars
   
            2003    
    Reserve at  
  Reserve at
    December 31, 2002   Accrual   Payments   June 30, 2003
   
 
 
 
Conoco
  $ 106       77       (64 )     119  
Phillips
    269       65       (166 )     168  

Total
  $ 375       142       (230 )     287  

The restructuring accrual balance of $287 million at June 30, 2003, is expected to be expended by the end of the first quarter of 2004, except for $36 million, which is classified as long-term. The pension and other post-retirement benefits will be paid in conjunction with other retirement benefits over a number of future years and are reported as part of our employee benefit plan obligations. For additional information on restructuring charges, see Note 9—Restructuring, in the Notes to Consolidated Financial Statements.

36


 

Segment Results

E&P

                                 
    Three Months Ended   Six Months Ended
    June 30   June 30
   
 
    2003   2002   2003   2002
   
 
    Millions of Dollars
   
Net Income
                               
Alaska
  $ 301       223       826       346  
Lower 48
    215       57       527       89  

United States
    516       280       1,353       435  
International
    554       59       1,000       46  

 
  $ 1,070       339       2,353       481  

                                   
      Dollars Per Unit
     
Average Sales Prices
                               
Crude oil (per barrel)
                               
 
United States
  $ 27.21       24.41       29.34       21.55  
 
International
    25.62       24.58       28.30       22.74  
 
Total consolidated
    26.33       24.46       28.76       21.93  
 
Equity affiliates
    16.85       21.06       18.02       17.91  
 
Worldwide
    25.19       24.44       27.82       21.90  
Natural gas—lease (per thousand cubic feet)
                               
 
United States
    4.58       2.51       4.96       2.25  
 
International
    3.47       2.20       3.70       2.31  
 
Total consolidated
    3.92       2.40       4.21       2.27  
 
Equity affiliates
    4.89             4.85        
 
Worldwide
    3.93       2.40       4.21       2.27  

                                 
    Millions of Dollars
   
Worldwide Exploration Expenses
                               
General administrative; geological and geophysical; and lease rentals
  $ 88       34       164       88  
Leasehold impairment
    24       16       44       109  
Dry holes
    30       17       50       33  

 
  $ 142       67       258       230  

37


 

                                   
      Three Months Ended   Six Months Ended
      June 30   June 30
     
 
      2003   2002   2003   2002
     
 
      Thousands of Barrels Daily
     
Operating Statistics
                               
Crude oil produced
                               
 
Alaska
    331       339       334       346  
 
Lower 48
    57       31       58       32  

 
United States
    388       370       392       378  
 
Norway
    214       119       220       118  
 
United Kingdom
    82       18       85       18  
 
Canada
    31       1       32       1  
 
Other areas
    135       38       136       41  

 
Total consolidated
    850       546       865       556  
 
Equity affiliates
    117       4       86       5  

 
    967       550       951       561  

Natural gas liquids produced
                               
 
Alaska
    23       25       24       26  
 
Lower 48
    21       1       20       1  

 
United States
    44       26       44       27  
 
Norway
    7       4       8       5  
 
United Kingdom
    2       2       2       1  
 
Canada
    11             11        
 
Other areas
    3       2       2       2  

 
    67       34       67       35  

                                   
      Millions of Cubic Feet Daily
     
Natural gas produced*
                               
 
Alaska
    162       160       175       164  
 
Lower 48
    1,311       689       1,324       711  

 
United States
    1,473       849       1,499       875  
 
Norway
    273       131       289       133  
 
United Kingdom
    952       189       977       181  
 
Canada
    424       22       430       21  
 
Other areas
    363       95       350       107  

 
Total consolidated
    3,485       1,286       3,545       1,317  
 
Equity affiliates
    11             11        

 
    3,496       1,286       3,556       1,317  

* Represents quantities available for sale. Excludes gas equivalent of natural gas liquids shown above.
                                   
      Thousands of Barrels Daily
     
Mining operations
                               
 
Syncrude produced
    19             18        

38


 

Net income from our E&P segment increased 216 percent in the second quarter of 2003, and 389 percent in the six-month period. The increases reflect:

    higher production volumes, primarily due to the merger;
    higher crude oil, natural gas liquids and natural gas sales prices, particularly during the six-month period;
    tax benefits recognized in the second quarter of 2003; and
    the adoption of SFAS No. 143. Our E&P operations recognized a benefit of $146 million for the cumulative effect of this accounting change in the first quarter of 2003.

These items were partially offset by increased production and operating expenses; depreciation, depletion and amortization; and taxes other than income taxes following the merger, reflecting the larger size and scope of our operations.

Our average worldwide crude oil sales price was $25.19 per barrel in the second quarter of 2003, compared with $24.44 in the second quarter of 2002. Our average crude oil price was higher for the six-month period as well, averaging $27.82 per barrel in 2003, compared with $21.90 per barrel in 2002. We also benefited from higher natural gas prices, with our average worldwide price increasing from $2.40 per thousand cubic feet in the second quarter of 2002 to $3.93 in the second quarter of 2003. See the “Outlook” section for additional discussion of crude oil and natural gas prices.

U.S. E&P

Net income from our U.S. E&P operations increased 84 percent in the second quarter of 2003, and 211 percent in the six-month period. The majority of the increase in both periods resulted from higher crude oil and natural gas prices. Increased production volumes following the merger accounted for the remaining increase, after considering the corresponding increases that go along with higher production, such as higher production taxes; production and operating expenses; and depreciation, depletion and amortization. Our U.S. E&P operations recognized a benefit of $161 million for the cumulative effect of adopting SFAS No. 143 in the first quarter of 2003.

U.S. E&P production on a barrel-of-oil-equivalent basis averaged 678,000 barrels per day in the second quarter of 2003, compared with 696,000 barrels per day in the first quarter of 2003. The 3 percent decrease primarily was due to seasonal and field declines, and maintenance work at the Greater Prudhoe Bay Area in Alaska, partially offset by improved production from Palm in the Greater Kuparuk Area and from Alpine, both in Alaska.

International E&P

Net income from our international E&P operations increased significantly in the second quarter and first six months of 2003. Increased production volumes following the merger accounted for the majority of the increase in both periods, after considering the corresponding increases that go along with higher production, such as higher production taxes; production and operating expenses; and depreciation, depletion and amortization. Higher crude oil and natural gas prices contributed to the remaining increase. Our international E&P operations recognized a charge of $15 million for the cumulative effect of adopting SFAS No. 143 in the first quarter of 2003. Included in international E&P’s net income in the second quarter of 2003 were foreign currency transaction losses of $24 million, compared with losses of

39


 

$7 million in the second quarter of 2002. The six-month period of 2003 included foreign currency transaction losses of $14 million, while the corresponding period of 2002 had losses of $5 million.

International E&P’s net income in the second quarter of 2003 was also favorably impacted by two items:

    In Norway, the Norway Removal Grant Act (1986) was repealed. Prior to its repeal, this Act required the Norwegian government to contribute to the cost of removing offshore oil and gas production facilities. Now, the co-venturers in the facilities must fund all removal costs, but can deduct the removal costs as incurred under the Petroleum Tax Act at the marginal tax rate in effect at the time of removal. These changes required us: to recognize an additional liability for the government’s share, prior to repeal of the Act, of the future removal costs, with a corresponding increase in properties, plants and equipment (PP&E); and to establish a net deferred tax asset for the temporary differences between the financial basis and tax basis of all of our Norway removal assets and liabilities. Some of the increases in PP&E were on shut-in fields, which led to immediate impairments of those properties. The overall impact on second quarter results was a net after-tax benefit of $87 million.

    In the Timor Sea region, ConocoPhillips and its co-venturers received final approvals from the relevant authorities to proceed with the natural gas development phase of the Bayu-Undan project. This approval allowed a broad ownership interest re-alignment among the co-venturers to proceed, which included our sale of a 10 percent interest in the project and the issuance of equity by previously wholly owned subsidiaries. In addition, the ratification of the Australia/Timor-Lesté treaty lowered the company’s deferred tax liability position. The net result of these events was an after-tax benefit of $51 million.

International E&P production on a barrel-of-oil-equivalent basis averaged 939,000 barrels per day in the second quarter of 2003, compared with 909,000 barrels per day in the first quarter. The 3 percent increase primarily was due to increased production from our equity affiliates in Venezuela, where political unrest shut down our heavy oil production in December 2002. Full production was restored during March of 2003.

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Midstream

                                 
    Three Months Ended   Six Months Ended
    June 30   June 30
   
 
    2003   2002   2003   2002
   
 
    Millions of Dollars
   
Net income
  $ 25       12       56       24  

                                   
      Dollars Per Barrel
     
Average Sales Prices
                               
U.S. natural gas liquids*
                               
 
Consolidated
  $ 20.99             23.29        
 
Equity
    20.53       15.59       22.53       14.21  

                                 
    Thousands of Barrels Daily
   
Operating Statistics
                               
Natural gas liquids extracted**
    209       119       216       118  
Natural gas liquids fractionated—United States
    158       104       163       105  

  * 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.
** Includes our share of equity affiliates.

Our Midstream segment consists of a 30.3 percent interest 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.

Net income from our Midstream segment increased 108 percent in the second quarter of 2003, and 133 percent in the six-month period. The increases primarily were attributable to improved results from DEFS and the addition of midstream operations following the merger. DEFS’ results mainly increased because of higher natural gas liquids prices and gains on asset sales.

Included in the Midstream segment’s net income was a benefit of $9 million in the second quarter of 2003, the same as the second quarter of 2002, representing the amortization of the excess amount of our 30.3 percent equity interest in the net assets of DEFS over the book value of our investment in DEFS. The six-month periods for both years included $18 million for the basis difference.

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R&M

                                 
    Three Months Ended   Six Months Ended
    June 30   June 30
   
 
    2003   2002   2003   2002
   
 
    Millions of Dollars
   
Net Income (Loss)
                               
United States
  $ 227       73       483       (19 )
International
    74       (5 )     188        

 
  $ 301       68       671       (19 )

                                   
      Dollars Per Gallon
     
U.S. Average Sales Prices*
                               
Automotive gasoline
                               
 
Wholesale
  $ 1.02       .87       1.06       .77  
 
Retail
    1.34       1.00       1.35       .91  
Distillates
    .85       .69       .95       .64  

* Excludes excise taxes.
                                     
  Thousands of Barrels Daily
 
Operating Statistics
                               
Refining operations*
                               
 
United States
                               
   
Rated crude oil capacity
    2,168       1,660       2,168       1,651  
   
Crude oil runs
    2,128       1,576       2,068       1,496  
   
Capacity utilization (percent)
    98 %     95       95       91  
   
Refinery production
    2,357       1,732       2,305       1,654  
 
International
                               
   
Rated crude oil capacity
    442       72       442       72  
   
Crude oil runs
    376       67       386       66  
   
Capacity utilization (percent)
    85 %     93       87       92  
   
Refinery production
    407       63       421       63  
 
Worldwide
                               
   
Rated crude oil capacity
    2,610       1,732       2,610       1,723  
   
Crude oil runs
    2,504       1,643       2,454       1,562  
   
Capacity utilization (percent)
    96 %     95       94       91  
   
Refinery production
    2,764       1,795       2,726       1,717  

* Includes ConocoPhillips’ share of equity affiliates.
                                     
Petroleum products outside sales
                               
 
United States
                               
   
Automotive gasoline
    1,381       1,159       1,356       1,122  
   
Distillates
    590       424       595       432  
   
Aviation fuels
    164       185       164       174  
   
Other products
    493       341       501       368  

 
    2,628       2,109       2,616       2,096  
 
International
    448       50       438       52  

 
    3,076       2,159       3,054       2,148  

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Net income from our R&M segment increased $233 million in the second quarter of 2003, and $690 million in the six-month period. The improved results in both periods were attributable to the addition of refining and marketing assets in the merger and higher refining margins and wholesale gasoline margins. However, we accrued losses totaling $25 million after-tax in the second quarter of 2003 and $50 million after-tax in the six-month period of 2003 for plans to terminate operating leases that provide for guaranteed residual values related to various retail sites that we plan to keep, but are planning to convert from leased sites to company-owned sites.

Our worldwide crude oil refining capacity utilization rate was 96 percent in the second quarter of 2003, compared with 95 percent in the corresponding period of 2002. Our refineries produced 2,764,000 barrels per day of petroleum products in the second quarter of 2003, compared with 1,795,000 barrels per day in the second quarter of 2002. The increase reflects the addition of production from refineries acquired in the merger.

U.S. R&M

Net income from our U.S. R&M operations increased 211 percent in the second quarter of 2003. In the first six months of 2003, U.S. R&M net income was $483 million, compared with a net loss of $19 million in the first six months of 2002. The improvement in both periods was primarily due to higher refining margins, higher marketing margins and the addition of refining and marketing assets in the merger. The average cost of a barrel of crude oil feedstock for our U.S. refineries was $27.36 in the second quarter of 2003, compared with $25.00 in the second quarter of 2002.

Also impacting our U.S. R&M operations were higher fuel and utility costs due to increased natural gas prices, as well as the lease-loss provisions discussed above totaling $25 million and $50 million after-tax that we recognized in the second quarter and first six months of 2003, respectively.

Our U.S. crude oil capacity utilization rate was 98 percent in the second quarter of 2003, compared with 93 percent in the first quarter of 2003. Our first quarter 2003 utilization rate was negatively affected by scheduled maintenance turnarounds at our Sweeny, Wood River and Ferndale refineries. The Ferndale turnaround included the startup of a new fluid catalytic cracking unit designed to increase the yield of transportation fuel.

International R&M

Net income from our international R&M operations was $74 million in the second quarter of 2003, compared with a net loss of $5 million in the second quarter of 2002. In the six-month period, international R&M net income was $188 million, compared with breakeven in the corresponding period of 2002. Both improvements were due to the larger size and scope of our international refining operations following the merger. In the second quarter and six-month period of 2002, our international R&M operations consisted of our Whitegate refinery in Ireland with a crude oil capacity of 72,000 barrels per day, while in the corresponding periods of 2003 our international R&M operations consisted of five additional refineries with an additional crude capacity of 370,000 barrels per day. Following the merger, we also have an extensive marketing network throughout Europe and Asia.

Our international crude oil capacity utilization rate was 85 percent in the second quarter of 2003, compared with 90 percent in the first quarter of 2003. The decline in the second quarter was due to scheduled and unscheduled downtime at our Humber refinery in the United Kingdom.

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Chemicals

                                 
    Millions of Dollars
   
    Three Months Ended   Six Months Ended
    June 30   June 30
   
 
    2003   2002   2003   2002
   
 
Net income (loss)
  $ 12       7       (11 )     (4 )

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. Net income from our Chemicals segment increased 71 percent in the second quarter of 2003. Net loss for the first six months of 2003 was $11 million, compared with a net loss of $4 million in the same period of 2002.

The improvement in the second quarter of 2003 primarily was the result of improved margins, as higher sales prices more than offset increased feedstock and utility costs. Although the 2003 second quarter showed improvement, the chemicals industry continues to be challenged to effectively utilize capacity, manage costs and improve margins in an adverse economic environment. Global economic slowdown in the last several years has reduced overall chemical demand, which has led to excess production capacity in the industry and pressured margins on key product lines. The chemicals industry is also impacted by energy prices, which affect both utility and feedstock costs.

At a product line level, results from ethylene, polyethylene, benzene and polystyrene improved in the second quarter of 2003, primarily due to improved margins resulting from increased sales prices outpacing higher feedstock and utility costs. The improved ethylene and polyethylene margins were partly offset by lower sales volumes. Results from normal alpha olefins and styrene were lower in the second quarter of 2003 because of lower margins.

Lower margins across most key product lines resulted in an increased net loss in the first six months of 2003, compared with the corresponding period of 2002. Earnings were also negatively impacted by lower sales volumes of ethylene, polyethylene and normal alpha olefins.

Emerging Businesses

                                 
    Millions of Dollars
   
    Three Months Ended   Six Months Ended
    June 30   June 30
   
 
    2003   2002   2003   2002
   
 
Net Loss
                               
Fuels technology
  $ (6 )     (3 )     (11 )     (8 )
Gas-to-liquids
    (13 )           (33 )      
Power
    (1 )                  
Other
    (3 )           (13 )      

 
  $ (23 )     (3 )     (57 )     (8 )

The Emerging Businesses segment includes the development of new businesses outside our traditional operations. Our Emerging Businesses segment incurred a net loss of $23 million in the second quarter of 2003, compared with a net loss of $3 million in the second quarter of 2002. Emerging Businesses incurred a net loss of $57 million in the first six months of 2003, compared with a net loss of $8 million in the

44


 

corresponding period of 2002. The increased net loss in both 2003 periods was the result of the expanded size of this segment following the merger. In the first six months of 2002, this segment included only the development of new fuels technologies, while in the first six months of 2003 additional new businesses acquired in the merger related to gas-to-liquids technologies, power generation, carbon fibers, and other emerging technologies were included.

We announced in February 2003 the shutdown of our carbon fibers project, as a result of market, operating and technology uncertainties. At the time of the merger, we had identified the uncertainties facing the carbon fibers project and initiated a strategic review. In early 2003, the strategic review was completed and management approved the plan to shut down the project.

Corporate and Other

                                 
    Millions of Dollars
   
    Three Months Ended   Six Months Ended
    June 30   June 30
   
 
    2003   2002   2003   2002
   
 
Net Income (Loss)
                               
Net interest
  $ (137 )     (91 )     (304 )     (169 )
Corporate general and administrative expenses
    (38 )     (27 )     (73 )     (74 )
Discontinued operations
    59       39       81       35  
Merger-related costs
    (115 )     (1 )     (142 )     (3 )
Other
    (16 )     8       1       (14 )

 
  $ (247 )     (72 )     (437 )     (225 )

Net interest after-tax represents interest expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased 51 percent in the second quarter of 2003, and 80 percent in the six-month period. The increase in both 2003 periods mainly was due to our higher debt levels following the merger. Our total debt at June 30, 2003, was $17.6 billion, compared with $9.6 billion at June 30, 2002.

After-tax corporate general and administrative expenses increased 41 percent in the second quarter of 2003, while decreasing slightly in the six-month period. Expenses were higher in the second quarter comparison because of the impact of the merger, as well as the expensing of stock options in the second quarter of 2003. Beginning in 2003, on a prospective basis, we elected to use the fair-value accounting method provided for under SFAS No. 123, “Accounting for Stock-Based Compensation.” See Note 6—Stock-Based Compensation, in the Notes to Consolidated Financial Statements, for additional information. In the six-month period of 2003, we benefited from lower long-term compensation plan expenses. Both 2003 periods benefited from increased allocations of certain of our staff costs to the operating segments. The increased corporate allocations did not have a material impact on the operating segment’s results.

Income from discontinued operations was $59 million in the second quarter of 2003, compared with $39 million in the second quarter of 2002. For the six-month periods, income from discontinued operations was $81 million in 2003, compared with $35 million in 2002. The improvement in the 2003 periods reflects the addition of assets classified as discontinued following the merger, as well as higher marketing margins and reduced depreciation expense. The improvement was partially offset by losses of $24 million in the second quarter of 2003 and $49 million in the six-month period related to plans to terminate operating leases that provide for guaranteed residual values for retail sites that we plan to sell. For additional information about discontinued operations, see Note 4—Discontinued Operations, in the Notes to Consolidated Financial Statements.

45


 

On an after-tax basis, merger-related costs in the second quarter of 2003 were $115 million, and were $142 million in the six-month period. Included in these costs were employee relocation expenses, transition labor costs, and other charges directly associated with the merger. Also included was a charge of $39 million to accelerate the recognition of certain pension costs, due to the number of employee retirements associated with the merger who elected to take lump-sum pension settlements. Merger-related costs in the second quarter and first six months of 2002 were $1 million and $3 million, respectively.

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, dividends on the preferred securities of capital trusts, and environmental costs associated with sites no longer in operation. Results from Other were lower in the second quarter of 2003, compared with the second quarter of 2002, primarily due to increased environmental costs. Results from Other were improved in the first six months of 2003 because we recognized an after-tax gain of $34 million in the first quarter of 2003, representing beneficial interests we had in certain insurance companies as a result of the conversion of those companies from mutual companies to stock companies, a process known as demutualization. These beneficial interests arose from our prior purchase and ownership of various insurance policies and contracts issued by the mutual companies. Prior to the demutualizations, our mutual ownership interests in these insurance companies were not recognized because ownership interests in the mutual companies were neither capable of valuation nor marketable. Included in Other in the second quarter of 2003 were foreign currency transaction gains of $18 million, after-tax, compared with gains of $12 million in the second quarter of 2002. The six-month period of 2003 included foreign currency transaction gains of $19 million, while the corresponding period of 2002 had gains of $8 million.

46


 

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

                 
    Millions of Dollars
   
    At June 30   At December 31
    2003   2002
   
Current ratio
    .8       .9  
Total debt repayment obligations due within one year
  $ 1,544       849  
Total debt
  $ 17,569       19,766  
Mandatorily redeemable preferred securities of trust subsidiary
  $ 350       350  
Other minority interests
  $ 723       651  
Common stockholders’ equity
  $ 32,032       29,517  
Percent of total debt to capital*
    35 %     39  
Percent of floating-rate debt to total debt
    9 %     12  

Capital includes total debt, mandatorily redeemable preferred securities, other minority interests and common stockholders’ equity. The decrease in ConocoPhillips’ debt-to-capital ratio from December 31, 2002, to June 30, 2003, was primarily the result of debt reduction and improved earnings.

Significant Sources of Capital

During the first six months of 2003, cash of $5,294 million was provided by operating activities, an increase of $4,185 million from the same period of 2002. The increase in cash provided by operating activities was primarily due to higher crude oil, natural gas liquids and natural gas prices, combined with increased production as a result of the addition of the Conoco assets; higher refining margins; higher marketing margins; and positive working capital changes. Positive working capital changes of $1,017 million, compared with the six months of 2002, were primarily due to an increase in taxes and other accruals, a decrease in accounts and notes receivables, and a decrease in prepaid expenses and other current assets. These items were partially offset by an increase in inventories and a decrease in accounts payable. Cash from operating activities provided by discontinued operations amounted to $76 million, compared with $50 million in the first six months of 2002.

To meet our liquidity requirements, including funding our capital program, paying dividends and repaying debt, we look to a variety of funding sources, primarily cash from operating activities. In 2003 through 2004, we also anticipate raising funds of $2 billion to $3 billion from the sale of assets, including those assets required to be sold by the Federal Trade Commission (FTC), as well as a substantial portion of our U.S. retail marketing sites. See Note 4—Discontinued Operations, in the Notes to Consolidated Financial Statements, for additional information. We also plan to raise funds from the sale of non-strategic E&P properties. Through the first six months of 2003, our proceeds from the sale of assets totaled $591 million.

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 downstream margins, as well as periodic cash needs to make tax payments and purchase crude oil, natural gas and petroleum products. Our primary funding source for short-term working capital needs is a $4 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 kept within 90 days. At June 30, 2003, ConocoPhillips had $801 million of commercial paper outstanding, of which $99 million was denominated in foreign currencies, compared with $1,517 million of commercial paper outstanding at December 31, 2002, of which $206 million was denominated in foreign currencies.

47


 

Supporting our $4 billion commercial paper program are a $2 billion 364-day revolving credit facility expiring on October 14, 2003, and two revolving credit facilities totaling $2 billion expiring in October 2006. There were no outstanding borrowings under any of these facilities at June 30, 2003. One of our Norwegian subsidiaries has two $300 million revolving credit facilities that expire in June 2004, under which no borrowings were outstanding as of June 30, 2003.

In addition to the bank credit facilities, ConocoPhillips sells certain credit card and trade receivables to two Qualifying Special Purpose Entities (QSPEs) in revolving-period securitization arrangements. These arrangements provide for us to sell, and the QSPEs to purchase, certain receivables and for the QSPEs to then issue beneficial interests of up to $1.5 billion to five bank-sponsored entities. At June 30, 2003, and December 31, 2002, we had outstanding to the bank-sponsored entities $1.4 billion and $1.3 billion, respectively, of beneficial interests in the pools of receivables held by the QSPEs. We retained beneficial interests in the sold receivables, which are subordinate to the beneficial interests issued to the bank-sponsored entities. Our retained interests were $1.3 billion at June 30, 2003, and December 31, 2002. Our retained interests in sold receivables are reported on the balance sheet in accounts and notes receivable—related parties. In addition, at June 30, 2003, and December 31, 2002, we had sold $171 million and $264 million, respectively, of receivables under a factoring agreement. See Note 15—Sales of Receivables, in the Notes to Consolidated Financial Statements, for additional information.

Other Financing and Off-Balance Sheet Arrangements

At June 30, 2003, we had $350 million of mandatorily redeemable preferred trust securities issued by the Phillips 66 Capital Trust II, which are mandatorily redeemable in 2037, when the ConocoPhillips subordinated debt securities held by the trust must be repaid. At June 30, 2003, we also had outstanding $723 million of equity held by minority interest owners, including a net minority interest of $141 million in Conoco Corporate Holdings L.P. and a $502 million net minority interest in Ashford Energy. We present the mandatorily redeemable preferred securities and other minority interests in the mezzanine section of our balance sheet based on accounting rules as of the balance sheet date. However, in the third quarter of 2003, in accordance with new accounting rules issued by the Financial Accounting Standards Board in Interpretation No. 46, “Consolidation of Variable Interest Entities,” and in Statement of Financial Accounting Standard No. 150, “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity,” accounting for mandatorily redeemable preferred securities and certain minority interests will change. We expect that the Phillips 66 Capital Trust II will be deconsolidated which will eliminate the reporting of the $350 million of mandatorily redeemable preferred trust securities and will require reporting as debt $361 million in 8% Junior Subordinated Deferrable Interest Debentures due 2037, which were previously eliminated in our consolidated financial statements. We expect the $141 million net minority interest in Conoco Corporate Holdings L.P. to be reclassified to debt. The $502 million Ashford minority interest has conditions for redemption that are outside our control; so it will continue to be reported in the mezzanine section of our balance sheet. See Note 19—New Accounting Standards, in the Notes to Consolidated Financial Statements, for more information.

We lease ocean transport vessels, drillships, tank railcars, corporate aircraft, service stations, computers, office buildings, certain refining equipment, and other facilities and equipment. Several of these leasing arrangements are with special purpose entities (SPEs) that are third-party trusts established by a trustee and funded by financial institutions. Other than those leasing arrangements, we have no other direct or indirect relationships with the trusts or their investors. We have various purchase options to acquire the leased assets from the SPEs throughout the lease terms, but we are not required to exercise these options under any specific circumstances. If we do not exercise our purchase options on leased assets, we do have guaranteed residual values, which are due at the end of the lease terms, but those guaranteed amounts

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would be reduced by the fair market value of the leased assets returned. These various leasing arrangements meet all requirements under generally accepted accounting principles to be treated as operating leases. However, in January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities,” which will require consolidation in the third quarter of 2003 certain SPEs that were created prior to January 31, 2003, and that are still in existence at July 1, 2003. For those VIEs created prior to January 31, 2003, we plan to implement Interpretation No. 46 in the third quarter of 2003 with retroactive application back to January 1, 2003. This application is expected to result in an increase in debt of approximately $2.5 billion for these leasing entities. See Note 19—New Accounting Standards, in the Notes to Consolidated Financial Statements, for more information. Of the $2.5 billion in debt that will be consolidated, approximately $1.5 billion is associated with approximately 1,000 store sites, the majority of which we plan to sell, and two office buildings that are also a part of our divestiture plan.

Capital Requirements

For information about our capital expenditures and investments, see “Capital Spending” below.

In the first six months of 2003, in addition to reducing our commercial paper, we paid the following notes as they were called or matured and funded the payments with cash from operating activities and proceeds from asset dispositions:

    $250 million 8.49% notes due January 1, 2023, at 104.245 percent;

    $181 million SRW Cogeneration Limited Partnership note;

    $100 million 6.65% notes that matured on March 1, 2003;

    $250 million 7.92% notes due in 2023 at 103.96 percent;

    $500 million floating rate notes due April 15, 2003; and

    $150 million 8.25% notes due May 15, 2003.

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Capital Expenditures and Investments

                   
      Millions of Dollars
     
      Six Months Ended
      June 30
     
      2003   2002
     
E&P
               
 
United States-Alaska
  $ 289       387  
 
United States-Lower 48
    418       136  
 
International
    1,472       695  

 
    2,179       1,218  

Midstream
    4       1  

R&M
               
 
United States
    336       221  
 
International
    124       12  

 
    460       233  

Chemicals
          19  
Emerging Businesses
    164        
Corporate and Other*
    76       48  

 
  $ 2,883       1,519  

United States
  $ 1,124       812  
International
    1,759       707  

 
  $ 2,883       1,519  

Discontinued operations
  $ 57       24  

Excludes discontinued operations.

E&P

We continue with the construction of our double-hulled Endeavour Class tankers, which are used in transporting Alaskan crude oil to the U.S. West Coast. We expect the third tanker, the Polar Discovery, to enter service later in 2003. We expect to add a new Endeavour Class tanker to our fleet each year through 2005.

In the first quarter of 2003, we completed the purchase of Amerada Hess’ 1.5 percent interest in the Trans-Alaska Pipeline System (TAPS), increasing our ownership in TAPS to 28.2 percent interest.

In Alaska, we continued development drilling in the Kuparuk, Palm and West Sak fields in the Greater Kuparuk Area, the Borealis field in the Greater Prudhoe Bay Area, and the Alpine field. In addition, we plan to increase oil production capacity at the Alpine field. The Alpine Capacity Expansion Project Phase I is expected to start up in 2004. The project will increase both water and gas handling capacities, both of which are important for increasing oil production and maintaining reservoir pressure.

In the Lower 48, we continued to explore and develop our acreage positions in the deepwater Gulf of Mexico, South Texas, the San Juan Basin, the Permian Basin, and the Texas Panhandle. In the Gulf of Mexico, development drilling is ongoing in the Magnolia and Princess fields, and appraisal drilling is under way on the K-2 discovery. In January 2003, we began construction of the Magnolia tension-leg platform, and we expect completion in 12 months. In February 2003, we began drilling the Lorien exploration well in the Gulf of Mexico on Green Canyon Block 199, which was declared a discovery in July. The well has been temporarily suspended, pending further appraisal of the hydrocarbon zone. We are the operator with a 65 percent interest.

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In the U.K. and Norwegian sectors of the North Sea, we continued with several exploration and development projects, with the largest expenditures on the Clair field. We expect first production from Clair in 2004.

In Indonesia, we completed the successful test of the Suban-8 delineation well in the Suban gas field, located on the Corridor Production Sharing Contract (PSC) of South Sumatra; and drilled the North Sumpal-1 exploratory well in the Sakakemang Block also located in South Sumatra. We began testing the North Sumpal-1 well in late July. In addition, we continue to develop the offshore Belanak and other fields in the Block B PSC.

In China’s Bohai Bay, we continued with feasibility planning and design for Phase II of the Peng Lai 19-3 development. Phase II includes multiple wellhead platforms, central processing facilities, and a floating storage and offloading facility. We are developing, in conjunction with Phase II, the Peng Lai 25-6 oil field, located three miles east of Peng Lai 19-3. We also drilled exploration wells on the Peng Lai 19-9 prospect and the Peng Lai 13-1 prospect, which resulted in two discoveries. The Peng Lai 19-9-1 well is located two miles east of the Peng Lai 19-3 oil field and along with adjacent structures will be a part of the Phase II development. The Peng Lai 13-1-1 well is located 18 miles north of the Peng Lai 19-3 field. We plan to drill additional wells to appraise this discovery and the structures in the same trend.

In the Timor Sea, we continued with development activities associated with the Bayu-Undan gas recycle project. We continued to drill future production wells, to fabricate and assemble two large platform decks, and to work on the multi-product floating storage and offtake vessel. Installation of the first deck began in late June 2003, and we expect to install the second deck and take delivery of the floating storage and offtake vessel in the fourth quarter of 2003, with first gas and commissioning commencing in the fourth quarter. We have also received approval of the gas development plan for the Bayu-Undan project from the Timor Sea Designated Authority, concluded fiscal and legal provisions with the government of Timor-Lesté and executed new PSC arrangements with the Designated Authority. The gas development project includes a liquefied natural gas (LNG) plant, including a pipeline to Darwin, Australia. The first LNG cargo from the three-million-ton-per-year facility is scheduled for delivery in early 2006. In June 2003, we sold what currently equates to a 10.08 percent interest in the unitized Bayu-Undan field; purchased other interests that currently equates to a 2.65 percent interest in the field; sold a 43.3 percent interest in the Bayu-Undan pipeline under construction, and sold a 43.3 percent interest in Darwin LNG Pty Ltd (owner of the LNG plant to be constructed). The net result is that ConocoPhillips retains a 56.7 percent controlling interest in the integrated project.

In Block 15-1 in the Cuu Long Basin of Vietnam, ConocoPhillips is currently evaluating the commerciality of the northeast portion of the Su Tu Den and the Su Tu Vang fields. We continue to develop the Southwest Phase I project of the Su Tu Den field. Currently, a wellhead platform and a floating production, storage and offloading vessel are under construction. We expect the field to begin production in the fourth quarter of 2003. In Block 15-2 (Rang Dong field), while the field is in full production, field facilities are being upgraded to include a utilities-living quarters platform; a gas lift, water injection, gas export platform; and water injection pipelines to the S-1 and future C-1 platforms. These facilities are anticipated to be operational in the fourth quarter of 2003.

At our Hamaca project in Venezuela, we continued with activities required to produce, transport and upgrade 8.6-degree API extra-heavy crude into high-quality synthetic crude oil. Total current production is approximately 80,000 gross barrels of heavy crude oil per day, 26,000 net. This production level is limited by the availability of diluent. We anticipate completing the construction of the upgrader in the third quarter of 2004, with peak capacity of extra-heavy crude in the 190,000 gross barrels per day range.

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We continued with development of the Stage III expansion-mining project in the Canadian province of Alberta, which is expected to increase our Canadian Syncrude production. The Aurora Train 2 project (the new mine) is now 87 percent complete and on track to start up in the fourth quarter of 2003. The expansion project is expected to bring various units onstream during 2004, while the completion of a new coker is anticipated in the first quarter of 2005.

In the Caspian Sea, we exercised our pre-emptive rights related to British Gas’ sale of their share in the North Caspian License that includes the Kashagan field offshore Kazakhstan. The transaction is expected to close in the fourth quarter of 2003, at which time our interest in the license will increase from 8.33 percent to 10.185 percent.

R&M

The polypropylene plant at the Bayway refinery in Linden, New Jersey, began operations in March 2003, utilizing propylene feedstock from the refinery to make up to 775 million pounds of polypropylene per year.

At our Ferndale, Washington, refinery, we completed construction of a new fluid catalytic cracking unit, which commenced initial operations in March 2003. We expect the unit to improve gasoline production from each barrel of crude oil input.

In the United States, we continue to expend funds related to clean fuels, safety and environmental projects. We continue to work on refinery projects in Ponca City, Oklahoma; Ferndale, Washington; and at our Wood River refinery in Roxana, Illinois, to produce the low-sulfur gasoline required by the Environmental Protection Agency. We expect to complete these projects by year-end.

In July 2003, we completed the acquisition of certain refining assets in Hartford, Illinois. The operations of these assets will be integrated into the operations of our nearby Wood River refinery.

Internationally we continue to invest in our ongoing refining and marketing operations, including a replacement reformer at our Humber refinery in the United Kingdom and marketing growth in select countries in Europe and Asia.

Emerging Businesses

We continued to spend funds in the first half of 2003 on construction of our Immingham combined heat and power cogeneration plant near our Humber refinery in the United Kingdom. We expect the plant to become operational in 2004.

Contingencies

Legal and Tax Matters

ConocoPhillips accrues for contingencies when a loss is probable and the amounts can be reasonably estimated. Based on currently available information, we believe that the chance 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.

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Environmental

ConocoPhillips and each of our various businesses are subject to the same numerous international, federal, state, and local environmental laws and regulations, as are other companies in the petroleum exploration and production; 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;

    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 (OPA90) 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 (EPCRA) 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; and

    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.

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 are expected to continue to have an increasing impact on our operations in the United States and in most of the countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States. Under the Clean Air Act, the U.S. Environmental Protection Agency (EPA) has promulgated a number of stringent limits on air emissions and established a federally mandated

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operating permit program. Violations of the Clean Air Act and most other environmental laws and regulations are enforceable with civil and criminal sanctions.

The EPA has also promulgated specific rules governing the sulfur content of gasoline, known generically as the “Tier II Sulfur Rules,” which become applicable to our gasoline as early as 2004. To meet the requirements, we are implementing a compliance strategy that relies on the use of a combination of technologies, including our proprietary S Zorb technology. The estimated costs for implementing our strategy will be included in future budgeting for refinery compliance.

The EPA has also promulgated rules regarding the sulfur content in highway diesel fuel, which become applicable in 2006. In April 2003, the EPA proposed a rule regarding emissions from non-road diesel engines and limiting non-road diesel fuel sulfur content. If promulgated, this rule would significantly reduce non-road diesel fuel sulfur content limits as early as 2007. We are currently developing and testing an S Zorb system for removing sulfur from diesel fuel. This advanced technology is one of many under consideration for complying with these rules. Because the non-road rule is not final, we are still evaluating and developing capital strategies for future compliance and we cannot provide precise cost estimates at this time.

Additional areas of potential air-related impact are the proposed revisions to the National Ambient Air Quality Standards (NAAQS) and the Kyoto Protocol. In July 1997, the EPA promulgated more stringent revisions to the NAAQS for ozone and particulate matter. Since that time, final adoption of these revisions has been the subject of litigation (American Trucking Association, Inc. et al. v. United States Environmental Protection Agency) that eventually reached the U.S. Supreme Court during the fall of 2000. In February 2001, the U.S. Supreme Court remanded this matter, in part, to the EPA to address the implementation provisions relating to the revised ozone NAAQS. If adopted, the revised NAAQS could result in substantial future environmental expenditures for ConocoPhillips.

In 1997, an international conference on global warming concluded an agreement, known as the Kyoto Protocol, which called for reductions of certain emissions that contribute to increases in atmospheric greenhouse gas concentrations. The United States has not ratified the treaty codifying the Kyoto Protocol but may in the future. In addition, other countries where we have interests, or may have interests in the future, have made commitments to the Kyoto Protocol and are in various stages of formulating applicable regulations. Currently, it is not possible to accurately estimate the costs that we could incur to comply with such regulations, but such expenditures could be substantial.

We also are 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 releases 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 ConocoPhillips. Over the next decade, we anticipate that significant ongoing expenditures for RCRA remediation activities may be required, but such annual

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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.

We from time to time 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, 2002, we reported we had been notified of potential liability under CERCLA and comparable state laws at 58 sites around the United States. At June 30, 2003, we had resolved four of these sites but had received five new notices of potential liability, leaving approximately 59 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.

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, if assumed in a purchase business combination, we record such costs 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, 2003.

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.

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At June 30, 2003, our balance sheet included a total environmental accrual related to continuing operations of $845 million, compared with $743 million at December 31, 2002. The increase in accruals from year-end 2002, primarily resulted from the continuing assessment of Conoco environmental liabilities during the period allowed by purchase accounting rules. Final purchase price adjustments will be recognized in the third quarter of 2003. We expect to incur the majority of these expenditures within the next 30 years.

Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse affect upon our results of operations or financial position as a result of compliance with environmental laws and regulations.

OUTLOOK

In December 2002, we committed to and initiated a plan to sell a substantial portion of our U.S. retail marketing sites. With the help of an investment banking firm, we are actively marketing these assets in packages. We are in discussions with potential buyers and expect to complete the sale of the majority of these sites in 2003. During the second quarter, we reached an agreement to sell certain retail and dealer marketing sites in the Northeast. This sale is expected to be completed in the third quarter of 2003.

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. Changes in the exchange rate could have a significant impact on our Venezuelan operations.

During the second quarter, draft legislation was introduced in the Canadian Parliament regarding federal tax rate reductions for oil and gas producers. If this legislation is enacted, we expect to recognize a significant earnings benefit upon revaluation of our deferred tax liability. However, due to the complexity of the calculation, we do not anticipate providing an estimate of the benefit until a thorough evaluation and review has been completed.

In March 2003, our board of directors approved a plan to further develop the Ekofisk Area in the Norwegian North Sea. We intend to increase the recovery of oil and gas from the Ekofisk Area by increasing the area’s processing capacity and reliability. Our co-venturers have also approved the plan for the further development of PL018. The Ekofisk growth project consists of two interrelated components: the construction and installation of a new platform, named Ekofisk 2/4 M and an increase in capacity from existing facilities. The Ekofisk 2/4 M platform will be a steel wellhead and process platform that will be located southeast of the existing Ekofisk 2/4 J platform and will have 30 well slots, a high-pressure separator, equipment for produced water treatment, and risers for tie-in of future projects. We expect to complete and install the steel jacket in 2004 and the topsides in the early summer of 2005, with production anticipated to begin in the fall of 2005. We also expect to modify the existing Ekofisk Complex and four additional platforms to increase our processing capacity.

In April 2003, the Control Committee, comprised of representatives of the Venezuelan Ministry of Energy and Mines, Petroleos de Venezuela S. A. (PDVSA), and the partners, approved Phase I of the development plan for the Corocoro field in Venezuela’s Gulf of Paria West area. We are the operator in the Gulf of Paria West Block and currently hold a 50 percent working interest. Under terms of the Gulf of Paria West Block profit sharing agreement with the Venezuelan government, Corporación Venezolana de Petróleo (a subsidiary of PDVSA) has elected to acquire a 35 percent participating interest in the Corocoro discovery, which will reduce our working interest to 32.5 percent. We have started development and first production is expected in early 2006.

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In May 2003, we received regulatory approval from the Alberta Energy and Utilities Board for our Surmont oil sands project in Northern Alberta, Canada. We are finalizing the evaluation of the commercial potential of the project, and a decision regarding development is expected later this year. We are the operator of the Surmont lease with a 43.5 percent interest. If a decision is made to proceed with the project, construction of the first phase could begin this year, with first oil production in 2006.

Also, in June 2003, we and our co-venturers in the Mackenzie Gas Project in Canada announced that funding and participation agreements have been reached and a Preliminary Information Package (PIP) was submitted to relevant regulatory authorities. The Mackenzie Gas Project involves natural gas production facilities, compression and gathering pipelines in the Mackenzie Delta area, and a pipeline system in the Mackenzie River Valley. The filing of the PIP is a key step in the process leading to the submission of applications for the development of the natural gas fields and pipeline facilities. Regulatory applications could be filed in 2004.

In July 2003, we announced that we had signed a Heads of Agreement with Qatar Petroleum for the development of Qatargas 3, a large-scale LNG project located in Qatar and servicing the U.S. natural gas market. The agreement provides the framework for the necessary agreements and the completion of key feasibility studies. Qatargas 3 would be an integrated project, jointly owned by Qatar Petroleum and ConocoPhillips, consisting of facilities to produce and liquefy gas from Qatar’s North field. The LNG would be shipped from Qatar and we would be responsible for regasification and marketing it within the United States. Average daily gas sales volumes are projected to be approximately 1 billion cubic feet per day with startup anticipated to be in the 2008-2009 timeframe.

On July 21, 2003, we experienced a fire at our 194,000-barrel-per-day refinery in Ponca City, Oklahoma. The fire involved a gas processing unit, an 85,000-barrel-per-day crude distillation unit and a desulfurization unit. The units are currently shutdown, and we are assessing the causes of the fire and the necessary repairs to the unit. Based on preliminary estimates, we expect to lose about 65,000 barrels per day of crude oil throughput in the third quarter of 2003, but we expect to be able to meet the supply needs of our branded customers.

In E&P, we expect our worldwide production for the third quarter of 2003 to be below our second quarter level, primarily because of seasonal declines in the United Kingdom and Norway, as well as asset dispositions and field declines in the U.S. Lower 48.

In R&M, we expect our average refinery utilization rate for the third quarter of 2003 to be below that of the second quarter primarily due to the temporary reduction of available capacity at the Ponca City refinery.

Crude oil and natural gas prices are subject to external factors over which we have no control, such as global economic conditions, political events, demand growth, inventory levels, weather, competing fuels prices and availability of supply. Crude oil prices declined in the second quarter from the exceptionally high levels experienced in the first quarter due to the war ending quickly in Iraq and production increases in Venezuela and Nigeria, both of which had major supply disruptions in the first quarter. However, crude prices remained strong in the second quarter due to low global oil inventories and a delay in the return of Iraqi crude production following the war. Uncertainty about the timing of the full restoration of Iraqi production is likely to keep prices volatile for the remainder of the year. U.S. natural gas prices also declined in the second quarter from extremely high first quarter levels. However, prices remained strong in the second quarter due to exceptionally low natural gas inventories caused by high heating demand in the Northeast during the first quarter, and continuing supply adequacy concerns.

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Refining margins are subject to movements in the price of crude oil and other feedstocks, and the prices of petroleum products, which are subject to market factors over which we have no control, such as the U.S. and global economies; government regulations; military, political and social conditions in oil producing countries; seasonal factors that affect demand, such as the summer driving months; and the levels of refining output and product inventories. Global refining margins retreated in the second quarter from very strong first quarter levels but remained at healthy levels. They retreated in the United States because weak gasoline demand combined with high gasoline imports caused gasoline inventories to rise during the second quarter. However, margins remain at fairly healthy levels because gasoline and distillate inventories are still lower than normal. Marketing margins increased in the second quarter from reasonably strong first quarter levels as refined product prices fell faster than retail and wholesale prices. The sustainability of current refining and marketing margins depends on the continued recovery of the global economy and oil demand growth.

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 “expects,” “anticipates,” “intends,” “plans,” “projects,” “believes,” “estimates” and similar expressions.

We have based the forward-looking statements relating to ConocoPhillips’ operations on its current expectations, estimates and projections about ConocoPhillips and the industries in which it operates 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 have based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, ConocoPhillips’ 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 ConocoPhillips’ chemicals business;

    changes in the business, operations, results and prospects of ConocoPhillips;

    the operation and financing of ConocoPhillips’ midstream and chemicals joint ventures;

    potential failure to realize fully or within the expected time frame the expected cost savings and synergies from the combination of Conoco and Phillips;

    costs or difficulties related to the integration of the businesses of Conoco and Phillips, as well as the continued integration of businesses recently acquired by each of them;

    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;

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    unexpected cost increases or technical difficulties in constructing or modifying facilities for exploration and production projects, manufacturing or refining;

    unexpected difficulties in manufacturing or refining ConocoPhillips’ refined products, including synthetic crude oil, and chemicals products;

    lack of, or disruptions in, adequate and reliable transportation for ConocoPhillips’ crude oil, natural gas, natural gas liquids and refined products;

    inability to timely obtain or maintain permits, comply with government regulations or make capital expenditures required to maintain compliance;

    failure to complete definitive agreements and feasibility studies and to timely complete construction and related facilities, for announced and future LNG projects;

    potential disruption or interruption of ConocoPhillips’ facilities due to accidents, 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;

    general domestic and international economic and political conditions, including armed hostilities and governmental disputes over territorial boundaries;

    changes in tax and other laws or regulations applicable to ConocoPhillips’ business; and

    inability to obtain economical financing for exploration and development projects, construction or modification of facilities and general corporate purposes.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the three and six months ended June 30, 2003, does not differ materially from that discussed under Item 7A of ConocoPhillips’ Annual Report on Form 10-K for the year ended December 31, 2002.

Item 4. CONTROLS AND PROCEDURES

As of June 30, 2003, with the participation of our management, our 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 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, 2003.

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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 during 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

With the exception of the single matter described below, there have been no material developments with respect to the legal proceedings previously reported in our 2002 Annual Report on Form 10-K.

On September 27, 2002, the Montana Department of Environmental Quality issued a Notice of Violation to ConocoPhillips alleging that on December 13, 2000, the company discharged 52,374 gallons of gasoline from Tank 32 at its Helena, Montana, product storage terminal. The matter was settled on July 15, 2003.

We are subject to various lawsuits and claims including, but not limited to: actions challenging oil and gas royalty and severance tax payments; actions related to gas measurement and valuation methods; actions related to joint interest billings to operating agreement partners; and claims for damages resulting from leaking underground storage tanks, or other accidental releases, with related toxic tort claims. As a result of Conoco’s separation agreement with DuPont, we also have assumed responsibility for current and future claims related to certain discontinued chemicals and agricultural chemicals businesses operated by Conoco in the past. In general, the effect on future financial results is not subject to reasonable estimation because considerable uncertainty exists. The ultimate liabilities resulting from such lawsuits and claims may be material to results of operations in the period in which they are recognized.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

We held our annual stockholders’ meeting on May 6, 2003. A brief description of each proposal and the voting results follow:

     A company proposal to elect five directors.

               
    For     Withheld
   
Richard H. Auchinleck
    562,140,470       51,216,949
William K. Reilly
    562,016,658       51,340,761
Randall L. Tobias
    550,635,326       62,722,093
Victoria J. Tschinkel
    561,797,593       51,559,826
Kathryn C. Turner
    558,167,439       55,189,980

Those directors whose term of office continued were as follows: Norman R. Augustine, David L. Boren, Kenneth M. Duberstein, Archie W. Dunham, Ruth R. Harkin, Larry D. Horner, Charles C. Krulak, Frank A. McPherson, J. J. Mulva, William R. Rhodes and J. Stapleton Roy.

A company proposal to ratify the appointment of Ernst & Young LLP as independent auditors for 2003.

               
 
For
      587,473,435  
 
Against
      21,164,824  
 
Abstentions
      4,719,160  
 
Broker Non-Votes
       

All five nominated directors were elected and the appointment of the independent auditors was ratified.

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Item 5. OTHER INFORMATION

The following information is being provided under Item 11 of Form 8-K pursuant to Release Nos. 33-8216; 34-47583 of the Securities and Exchange Commission:

On July 21, 2003, ConocoPhillips received notice from the plan administrator of the Conoco Thrift Plan for Employees and the Conoco Thrift Plan for Retail Employees (collectively, the “Plans”) regarding a blackout period, as defined in Rule 100 of the Securities and Exchange Commission’s Regulation BTR. The blackout period is expected to commence October 3, 2003, and end during the week of October 5, 2003. The blackout period is being instituted to effectuate the merger of the Plans into other existing plans of ConocoPhillips. During the blackout period, participants in the Plans will be unable to make exchanges or asset allocation changes involving ConocoPhillips’ common stock, submit loan requests or make loan payments by check or money order, or request a withdrawal or final distribution. The ability of ConocoPhillips’ directors and executive officers to purchase, sell or otherwise transfer any equity security of ConocoPhillips (or derivative securities of those equity securities) acquired in connection with service to or employment with ConocoPhillips will also be suspended during the blackout period.

The person designated by ConocoPhillips to respond to inquiries about the blackout period is Elizabeth Cook, ConocoPhillips, 600 North Dairy Ashford, Houston, Texas 77079, 281-293-4966. During the blackout period, directors, executive officers and participants in the Plans can receive further information regarding the commencement or ending of the blackout period by calling 1-800-523-1888 Monday through Friday from 7:30 a.m. to 8:00 p.m. Central time or by logging on to http://cop.vanguard-education.com.

As required by Section 306 of the Sarbanes-Oxley Act of 2002 and Rule 104 of Regulation BTR, ConocoPhillips transmitted a notice of blackout period to its directors and executive officers.

Item 6. EXHIBITS AND REPORTS ON FORM 8-K

Exhibits

10   Key Employee Deferred Compensation Plan of ConocoPhillips.

12   Computation of Ratio of Earnings to Fixed Charges.

31.1   Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2   Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32   Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Reports on Form 8-K

During the three months ended June 30, 2003, ConocoPhillips furnished the following Current Reports on Form 8-K:

    Current Report furnished April 8, 2003, reporting Item 7 and Item 9.

    Current Report furnished April 30, 2003, reporting Item 7 and Item 9.

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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 12, 2003

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EXHIBIT INDEX

Exhibit
Number
   
                                           Description

10   Key Employee Deferred Compensation Plan of ConocoPhillips.

12   Computation of Ratio of Earnings to Fixed Charges.

31.1   Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2   Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32   Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
exv10
 

Exhibit 10

Amended by Corporate Approval
May 13, 2003

KEY EMPLOYEE DEFERRED COMPENSATION PLAN OF

CONOCOPHILLIPS

PURPOSE

The purpose of the Key Employee Deferred Compensation Plan of ConocoPhillips (the “Plan”) is to attract and retain key employees by providing them with an opportunity to defer receipt of cash amounts which otherwise would be paid to them under various compensation programs or plans by the Company. This Plan is the continuation of the Key Employee Deferred Compensation Plan of Phillips Petroleum Company, and all deferrals made thereunder shall continue under their terms and the terms of this Plan.

SECTION 1. Definitions.

  (a)   “Affiliated Group” shall mean the Company plus other subsidiaries and affiliates in which it owns, directly or through a subsidiary or affiliate, a 5% or more equity interest.
 
  (b)   “Award” shall mean the United States cash dollar amount (i) allotted to an Employee under the terms of an Incentive Compensation Plan or a Long Term Incentive Plan, or (ii) required to be credited to an Employee’s Deferred Compensation Account pursuant to an Incentive Compensation Plan, the Long Term Incentive Compensation Plan, the Strategic Incentive Plan, a Long Term Incentive Plan, or any similar plans, or any administrative procedure adopted pursuant thereto, or (iii) credited as a result

 


 

      of a Participant’s deferral of the receipt of the value of the Stock which would otherwise be delivered to an Employee in the event restrictions lapse on Restricted Stock or Restricted Stock Units or the settlement of Restricted Stock Units previously awarded or which may be awarded to the Participant pursuant to an Incentive Compensation Plan, the Long Term Incentive Compensation Plan, the Strategic Incentive Plan, a Long Term Incentive Plan, an Omnibus Securities Plan, or any similar plans, or any administrative procedure adopted pursuant thereto, or (iv) credited resulting from a lump sum distribution from any of the Company’s non-qualified retirement plans and/or plans which provide for a retirement supplement, or (v) resulting from the forfeiture of Restricted Stock, required by Phillips Petroleum Company, of key employees who became employees of GPM Gas Corporation, or (vi) credited as a result of an Employee’s deferral of the receipt of the lump sum cash payment from the Employee’s account in the Defined Contribution Makeup Plan, or (vii) credited as a result of an Employee’s voluntary reduction of Salary, or (viii) credited as a result of an Employee’s deferral of a Performance Based Incentive Award, or (ix) any other amount determined by the Committee to be an Award under the Plan. Sections 2 and 3 of this Plan shall not apply with respect to Awards included under (ii), (v), and (ix) above and a participant receiving such an Award shall be deemed, with respect thereto, to have elected a Section 5(b)(i) payment option — 10 annual installments commencing about one year after retirement at age 55 or above, but subject to revision under the terms of this Plan.

  (c)   “Board of Directors” shall mean the board of directors of the Company.
 
  (d)   “Chief Executive Officer” or “CEO” shall mean the Chief Executive Officer of the Company.
 
  (e)   “Committee” shall mean the Compensation Committee of the Board of Directors.
 
  (f)   “Company” shall mean ConocoPhillips.

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  (g)   “Deferred Compensation Account” shall mean an account established and maintained for each Participant in which is recorded the amounts of Awards deferred by a Participant, the deemed gains, losses and earnings accrued thereon and payments made therefrom all in accordance with the terms of the Plan.
 
  (h)   “Defined Contribution Makeup Plan” shall mean the Defined Contribution Makeup Plan of ConocoPhillips, or any similar plan or successor plans.
 
  (i)   “Disability” shall mean the inability, in the opinion of the Company’s Medical Director, of a Participant, because of an injury or sickness, to work at a reasonable occupation that is available with the Company, a Participating Subsidiary, or another subsidiary of the Company.
 
  (j)   “Employee” shall mean any individual or Rehired Participant who satisfies the conditions of Section 5(j) who is a salaried employee of the Company or of a Participating Subsidiary who is eligible to receive an Award from an Incentive Compensation Plan, has Restricted Stock and/or Restricted Stock Units, and is classified as a ConocoPhillips salary grade 19 or above or any equivalent salary grade at a Participating Subsidiary. Employee shall also include Participants who are employed by a member of the Affiliated Group and former employees of a member of the Affiliated Group who Retire or are Laid Off and are eligible to receive a lump sum distribution from non-qualified retirement plans. Employee shall also include any individual or Rehired Participant who is hired as a salaried employee of ConocoPhillips Services Inc. on or after January 1, 2003 and is classified as a ConocoPhillips salary grade 19 or above or any equivalent salary grade at a Participating Subsidiary. Notwithstanding the foregoing, Employee shall not include anyone who is classified as a Heritage Conoco Employee.
 
  (k)   “ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended from time to time, or any successor statute.

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  (l)   “Exchange Act” shall mean the Securities Exchange Act of 1934, as amended and in effect from time to time, or any successor statute.
 
  (m)   “Heritage Conoco Employee” shall mean an individual employed by Conoco Inc., Conoco Pipe Line Company, or Louisiana Gas Systems Inc. prior to January 1, 2003; provided, however, that an individual who has been terminated from employment with a member of the Affiliated Group at any time and rehired by a member of the Affiliated Group after January 1, 2003, shall not be considered a Heritage Conoco Employee for purposes of this Plan.
 
  (n)   “Incentive Compensation Plan” shall mean the ConocoPhillips Variable Cash Incentive Program, the Incentive Compensation Plan of Phillips Petroleum Company, or the Annual Incentive Compensation Plan of Phillips Petroleum Company, the Special Incentive Plan for Former Tosco Executives, or similar plan of a Participating Subsidiary, or any similar or successor plans, or all, as the context may require.
 
  (o)   “Layoff” or “Laid Off” shall mean an applicable termination of employment by reason of layoff under the Phillips Layoff Plan or the Phillips Work Force Stabilization Plan, an applicable Qualifying Event (without there being a Disqualifying Event) under the Conoco Severance Pay Plan, or layoff or redundancy under any other layoff or redundancy plan which the Company, any Participating Subsidiary, or any other member of the Affiliated Group may adopt from time to time. If all or any portion of the benefits under the layoff or redundancy plan are contingent on the employee’s signing a general release of liability, such termination shall not be considered as a Layoff for purposes of this Plan unless the employee executes and does not revoke a general release of liability, acceptable to the Company, under the terms of such layoff or redundancy plan.
 
  (p)   “Long-Term Incentive Compensation Plan” shall mean the Long-Term Incentive Compensation Plan of Phillips Petroleum Company, which was terminated December 31, 1985.

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  (q)   “Long-Term Incentive Plan” shall mean the ConocoPhillips Performance Share Program, the Phillips Petroleum Company Long-Term Incentive Plan, or a similar or successor plan of either of them, established under an Omnibus Securities Plan.
 
  (r)   “Newhire Employee” shall mean any Employee who is hired or rehired during a calendar year.
 
  (s)   “Omnibus Securities Plan” shall mean the Omnibus Securities Plan of Phillips Petroleum Company, the 2002 Omnibus Securities Plan of Phillips Petroleum Company, the 1998 Stock and Performance Incentive Plan of ConocoPhillips, the 1998 Key Employee Stock Plan of ConocoPhillips, or a similar or successor plan of any of them.
 
  (t)   “Participant” shall mean a person for whom a Deferred Compensation Account is maintained.
 
  (u)   “Participating Subsidiary” shall mean a subsidiary of the Company, of which the Company beneficially owns, directly or indirectly, more than 50% of the aggregate voting power of all outstanding classes and series of stock, where such subsidiary has adopted one or more plans making participants eligible for participation in this Plan and one or more Employees of which are Potential Participants.
 
  (v)   “Plan Administrator” shall mean the Vice President Human Resources of the Company, or his successor.
 
  (w)   “Potential Participant” shall mean a person who has received a notice specified in Section 2 or in Section 5 (h).
 
  (x)   “Rehired Participant” shall mean a Participant who, subsequent to Retirement or Layoff, is rehired by the Company, or any subsidiary of the Company, and whose employment status is classified as regular full-time or its equivalent.

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  (y)   “Restricted Stock” and “Restricted Stock Units” shall mean respectively shares of Stock and units each of which shall represent a hypothetical share of Stock, which have certain restrictions attached to the ownership thereof or the delivery of shares pursuant thereto.
 
  (z)   “Retirement” or “Retire” or “Retiring” shall mean termination of employment with the Company or any subsidiary of the Company on or after the earliest early retirement date at age 55 or above as defined in the ConocoPhillips Retirement Plan or of the applicable retirement plan of a member of the Affiliated Group.
 
  (aa)   “Retirement Income Plan” shall mean the ConocoPhillips Retirement Plan or a similar retirement plan of the Participating Subsidiary pursuant to the terms of which the Participant retires.
 
  (bb)   “Settlement Date” shall mean the date on which all acts under an Incentive Compensation Plan or the Long-Term Incentive Compensation Plan or actions directed by the Committee, as the case may be, have been taken which are necessary to make an Award payable to the Participant.
 
  (cc)   “Salary” shall mean the monthly equivalent rate of pay for an Employee before adjustments for any before-tax voluntary reductions.
 
  (dd)   “Stock” means shares of common stock of ConocoPhillips, par value $.01.
 
  (ee)   “Strategic Incentive Plan” shall mean the Strategic Incentive Plan portion of the 1986 Stock Plan of Phillips Petroleum Company, of the 1990 Stock Plan of Phillips Petroleum Company, of the Phillips Petroleum Company Omnibus Securities Plan, and of any successor plans of similar nature.

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  (ff)   “Trustee” shall mean the trustee of the grantor trust established by the Trust Agreement between the Company and Wachovia Bank, N.A. dated as of June 1, 1998, or any successor trustee.

SECTION 2. Notification of Potential Participants.

  (a)   Incentive Compensation Plan. Each year, during October, Employees who are eligible to receive an Award in the immediately following calendar year under an Incentive Compensation Plan will be notified and given the opportunity, in a manner prescribed by the Plan Administrator, to indicate a preference concerning deferral of all or part of such Award.
 
  (b)   Restricted Stock and Restricted Stock Units Lapsing.
 
      (i) Each year during October, Employees who are or will be 55 years of age or older prior to the end of the calendar year will be notified and given the opportunity, in a manner prescribed by the Plan Administrator to indicate a preference to delay the lapsing of the restrictions on part or all of the shares of Restricted Stock and/or Restricted Stock Units previously awarded or which may be awarded to the Employee under an Incentive Compensation Plan, the Long Term Incentive Compensation Plan, a Long-Term Incentive Plan, or the Strategic Incentive Plan in the event the Compensation Committee takes action in the following calendar year to lapse restrictions on Restricted Stock and/or Restricted Stock Units and/or settle Restricted Stock Units.
 
      (ii) Each year during October, Employees who have been granted a special Restricted Stock Award and/or Restricted Stock Unit Award will be notified and given the opportunity, in a manner prescribed by the Plan Administrator to indicate a preference to delay the lapsing of the restrictions on part or all of the shares of Restricted Stock and/or Restricted Stock Units when the restrictions lapse on the Special Restricted Stock and/or Restricted Stock Units or the Restricted Stock Units are settled based on

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      the terms of the Special Restricted Stock and/or Restricted Stock Unit Awards in the following year.
 
      (iii) Such indication of preference as outlined in (i) above may be made within 60 days of the amendment of this Plan providing for the notice; provided, however, that such indication of preference must be made no later than June 6, 2003 for such Awards that would otherwise be lapsed or settled later in 2003.
 
  (c)   Restricted Stock and Restricted Stock Unit Awards Deferral.
 
      (i) Each year, during October, Employees who are or will be 55 years of age or older prior to the end of the calendar year will be notified and given the opportunity, in a manner prescribed by the Plan Administrator, to indicate a preference concerning the deferral of the receipt of the value of all or part of the Stock which would otherwise be delivered to the Employees in the event, during the following calendar year, the Compensation Committee takes action to lapse restrictions on Restricted Stock and/or Restricted Stock Units and/or settle Restricted Stock Units previously awarded or which may be awarded to the Employees under an Incentive Compensation Plan, the Long Term Incentive Compensation Plan, a Long Term Incentive Plan, or the Strategic Incentive Plan.
 
      (ii) Employees who have been granted a special Restricted Stock Award and/or Restricted Stock Units Award may, in the year preceding the year in which the restrictions are scheduled to lapse or the Restricted Stock Units are to be settled, indicate a preference concerning the deferral of the value of all or part of the stock which would otherwise be delivered to the Employees in the next calendar year when the restrictions lapse on the special Restricted Stock and /or Restricted Stock Units or the Restricted Stock Units are settled based on the terms of the special Restricted Stock Awards and/or Restricted Stock Units Awards.
 
      (iii) Employees who are Laid Off during or after the year they reach age 50 may no later than 30 days after being notified of Layoff, in the manner prescribed by the Plan

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      Administrator, indicate a preference concerning the deferral of the receipt of the value of all or part of the Stock which would be otherwise be delivered to the Employees in the event Restricted Stock Units, which have been granted in exchange for Restricted Stock pursuant to the Exchange offer initiated by the Company on December 17, 2001, are settled.
 
      (iv) Such indication of preference as outlined in (i) above may be made within 60 days of the amendment of this Plan providing for the notice; provided, however, that such indication of preference must be made no later than June 6, 2003 for such Awards that would otherwise be lapsed or settled later in 2003.
 
  (d)   Lump Sum Distribution from Non-Qualified Retirement Plans. With respect to the lump sum distribution permitted from the Company’s non-qualified retirement plans and/or plans which provide for a retirement supplement, Employees may indicate, in a manner prescribed by the Plan Administrator, a preference concerning deferral of all or part of such lump sum distribution.
 
  (e)   Lump Sum from Defined Contribution Makeup Plan. Employees who will receive a lump sum cash payment from their account under the Defined Contribution Makeup Plan, may indicate, in a manner prescribed by the Plan Administrator, a preference concerning deferral of all or part of such payment.
 
  (f)   Salary Reduction. Annually, Employees and Newhire Employees on the U.S. dollar payroll may elect, in a manner prescribed by the Plan Administrator, a voluntary reduction of Salary for each pay period of the following calendar year, or for Newhire Employees the remainder of the calendar year in which they are hired, in which case the Company will credit a like amount as an Award hereunder, provided that the amount of such voluntary reduction shall not be less than 2% nor more than a percentage of the Employee’s Salary per pay period such that the resulting salary that is paid is sufficient to satisfy all benefit plan deductions, tax deductions, elective deductions, and other deductions required to be withheld by the Company.

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  (g)   Performance Based Incentive Award. Each year, during October, Employees who are eligible to receive a Performance Based Incentive Award in the immediately following calendar year will be notified and given the opportunity, in a manner prescribed by the Plan Administrator, to indicate a preference for the award to be paid as cash, deferred to their KEDCP account or issued as Restricted Stock or a combination of cash, deferred compensation and Restricted Stock.

SECTION 3. Indication of Preference or Election to Defer Award.

  (a)   Incentive Compensation Plan. If a Potential Participant prefers to defer under this Plan all or any part of the Award to which a notice received under Section 2(a) pertains, the Potential Participant must indicate such preference, in a manner prescribed by the Plan Administrator, (i) if the Potential Participant is subject to Section 16 of the Exchange Act, to the Committee, or (ii) if the Potential Participant is not subject to Section 16 of the Exchange Act, to the CEO. The Potential Participant’s preference must be received on or before October 31 of the year in which said Section 2(a) notice was received. Such indication must state the portion of the Award the Potential Participant desires to be deferred. If an indication is not received by October 31, the Potential Participant will be deemed to have elected to receive and not to defer any such Incentive Compensation Plan award.
 
      Such indication of preference, if accepted, becomes irrevocable on November 1 of the year in which the indication is submitted to the Committee or CEO, except that, in the event of any of the following:

  i) the Employee is demoted to a job classification/grade that is no longer eligible to receive an Award from an Incentive Compensation Plan,
 
  ii) the Employee’s employment status is classified to a status other than regular full-time or its equivalent, or
 
  iii) the Employee is receiving Unavoidable Absence Benefits (UAB) pay such that the pay received is less than his/her pay had been prior to being on UAB,

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      the Employee can request, subject to approval by the Plan Administrator, that his/her indication of preference to defer, whether approved or not, be revoked for that Incentive Compensation Plan Award.
 
      The Committee or CEO, as applicable, shall consider such indication of preference as submitted and shall decide whether to accept or reject the preference expressed.
 
  (b)   Restricted Stock and Restricted Stock Unit Awards Lapsing.
 
      If a Potential Participant prefers to delay the lapsing of the restrictions on part or all of the shares of Restricted Stock and/or Restricted Stock Units to which a notice received under Section 2(b) pertains, the Potential Participant must indicate such preference in a manner prescribed by the Plan Administrator, (i) if the Potential Participant is subject to Section 16 of the Exchange Act, to the Committee, or (ii) if the Potential Participant is not subject to Section 16 of the Exchange Act, to the CEO. The Potential Participant’s preference must state the percentage of the shares and/or units on which the lapsing is to be delayed. If an indication is not received by October 31, the Potential Participant will be deemed to have elected to have the restrictions lapsed if the Compensation Committee takes action to lapse restrictions or as specified under the terms of the Special Restricted Stock and/or Restricted Stock Unit Awards. If the Potential Participant prefers to delay the lapsing of the restrictions on part or all of the shares of Restricted Stock or Restricted Stock Units awarded under an Incentive Compensation Plan, the Long Term Incentive Compensation Plan, a Long Term Incentive Plan, or Strategic Incentive Plan, those shares and/or units will be subject to another indication of preference in the following year. If the Potential Participant prefers to delay the lapsing of the restrictions on part or all of the shares of Restricted Stock or Restricted Stock Units from Special Stock Awards, those shares and/or units will remain restricted and the Employee will receive a notice to indicate a preference for such shares when the Employee is or will be 55 years of age or older prior to the end of the calendar year as specified in Section 2(b)(i).

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  (c)   Restricted Stock or Restricted Stock Unit Deferral. If a Potential Participant prefers to defer under this Plan the value of all or any part of the Restricted Stock or Restricted Stock Units to which a notice received under Section 2(c) pertains, the Potential Participant must indicate such preference, in a manner prescribed by the Plan Administrator, (i) if the Potential Participant is subject to Section 16 of the Exchange Act, to the Committee, or (ii) if the Potential Participant is not subject to Section 16 of the Exchange Act, to the CEO. The Potential Participant’s preference must be received on or before October 31 of the year in which said Section 2(c) notice was received. Such indication must state the portion of the value of the Restricted Stock or Restricted Stock Units the Potential Participant desires to be deferred. If an indication is not received by October 31, the Potential Participant will be deemed to have elected to receive any shares or units for which the restrictions are lapsed. Such indication of preference becomes irrevocable on November 1 of the year in which the indication is submitted to the Committee or CEO. The Committee or CEO, as applicable, shall consider such indication of preference as submitted and shall decide whether to accept or reject the preference expressed. A deferral of the value of the Restricted Stock or Restricted Stock Units will be paid under the terms of Section 5(b)(i) hereof — 10 annual installments commencing about one year after Retirement at age 55 or above, but subject to revision under the terms of this Plan. Such approved indication of preference shall also apply to any Restricted Stock Units granted in exchange for shares of Restricted Stock pursuant to the Exchange offer initiated by the Company on December 17, 2001.
 
  (d)   Lump Sum Distribution from Non-Qualified Retirement Plans. If a Potential Participant prefers to defer under this Plan all or part of the lump sum distribution to which Section 2(d) pertains, the Potential Participant must indicate such preference, in a manner prescribed by the Plan Administrator, (i) if the Potential Participant is subject to Section 16 of the Exchange Act, to the Committee or (ii) if the Potential Participant is not subject to Section 16 of the Exchange Act, to the CEO. The Potential Participant’s preference must be received in the period beginning 90 days prior to and ending no less than 30 days prior to the date of commencement of

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      retirement benefits under such plans. Such indication must state the portion of the lump sum distribution the Potential Participant desires to be deferred. The Committee or CEO, as applicable, shall consider such indication of preference as submitted and shall decide whether to accept or reject the preference expressed as soon as practicable. Such indication of preference, if accepted, becomes irrevocable on the date of such acceptance.
 
  (e)   Lump Sum from Defined Contribution Makeup Plan. If a Potential Participant prefers to defer under this Plan all or part of the lump sum cash payment to which Section 2(e) pertains, the Potential Participant must indicate such preference, in a manner prescribed by the Plan Administrator, (i) if the Potential Participant is subject to Section 16 of the Exchange Act, to the Committee or (ii) if the Potential Participant is not subject to Section 16 of the Exchange Act, to the CEO. The Potential Participant’s preference must be received in the period beginning 365 days prior to and ending no less than 90 days prior to the Participant’s retirement date at age 55 or above except that if a Potential Participant is notified of layoff during or after the year in which the Potential Participant reaches age 50, the Potential Participant’s preference must be received no later than 30 days after being notified of layoff. Such indication must state the portion of the lump sum payment the Potential Participant desires to be deferred. The Committee or CEO, as applicable, shall consider such indication of preference as submitted and shall decide whether to accept or reject the preference expressed as soon as practicable. Such indication of preference, if accepted, becomes irrevocable on the date of such acceptance. A deferral of the lump sum from the Defined Contribution Makeup Plan will be paid under the terms of Section 5(b)(i) hereof — 10 annual installments commencing about one year after retirement at age 55 or above, but subject to revision under the terms of the Plan.
 
  (f)   Salary Reduction. If a Potential Participant elects to voluntarily reduce Salary and receive an Award hereunder in lieu thereof, the Potential Participant must make an election, in the manner prescribed by the Plan Administrator, which must be received on or before October 31 prior to the beginning of the calendar year of the elected

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      deferral or for Newhire Employees as soon as practicable within a 30-day period after their first day of employment or reemployment. Such election must be in writing signed by the Potential Participant, and must state the amount of the salary reduction the Potential Participant elects. Such election becomes irrevocable on October 31 prior to the beginning of the calendar year or for Newhire Employees after the 30-day period after their first day of employment or reemployment, except that in the event of any of the following:

  i)   the Employee is demoted to a job classification/grade that is no longer eligible to receive an Award from an Incentive Compensation Plan,
 
  ii)   the Employee’s employment status is classified to a status other than regular full-time or its equivalent, or
 
  iii)   the Employee is receiving Unavoidable Absence Benefits (UAB) pay such that the pay received is less than his/her pay had been prior to being on UAB,

      the Employee can request, subject to approval by the Plan Benefits Administrator, that his/her election to voluntarily reduce his/her salary be revoked for the remainder of the calendar year.

      An Award in lieu of voluntarily reduced salary will be paid under the terms of Section 5(b)(i) hereof — 10 annual installments commencing about one year after retirement at age 55 or above, but subject to revision under the terms of the Plan.
 
  (g)   Performance Based Incentive Award. The Potential Participant who is eligible to receive a Performance Based Incentive Award in the immediately following calendar year, must indicate a preference, in a manner prescribed by the Plan Administrator, (i) if the Potential Participant is subject to Section 16 of the Exchange Act, to the Committee, or (ii) if the Potential Participant is not subject to Section 16 of the Exchange Act, to the CEO. The Potential Participant’s preference must be received on or before October 31 of the year in which said Section 2(g) notice was received. Such indication must state the portion of the award the Potential Participant desires to be in cash, the portion to be deferred and the portion to be in Restricted Stock. If an

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      indication is not received by October 31 the Potential Participant will be deemed to have elected to receive the award as cash. Such indication of preference becomes irrevocable on November 1 of the year in which the indication is submitted to the Committee or CEO. The Committee or CEO, as applicable, shall consider such indication of preference as submitted and shall decide whether to accept or reject the preference expressed.

SECTION 4. Deferred Compensation Accounts.

  (a)   Credit for Deferral. Amounts deferred pursuant to Section 3(a) and Section 5(h)(1) will be credited to the Participant’s Deferred Compensation Account as soon as practicable, but not less than 30 days after the Settlement Date of the Incentive Compensation Plan. Amounts deferred pursuant to Section 3(c) and Section 5(h)(2) will be credited, as applicable, as soon as practicable, but not later than 30 days after the date as of which the restrictions lapse at the market value of the underlying Restricted Stock or the shares represented by the Restricted Stock Units awarded under an Incentive Compensation Plan, the Long Term Incentive Compensation Plan, a Long Term Incentive Plan or a Strategic Incentive Plan Performance Period which began prior to January 1, 2003. For this purpose, the market value of the underlying Restricted Stock or the shares represented by the Restricted Stock Units, as applicable, shall be based on the higher of (i) the average of the high and low selling prices of the Stock on the date the restrictions lapse or the last trading day before the day the restrictions lapse if such date is not a trading day or (ii) the average of the high three monthly Fair Market Values of the Stock during the twelve calendar months preceding the month in which the restrictions lapse. The monthly Fair Market Value of the Stock is the average of the daily Fair Market Value of the Stock for each trading day of the month.
 
      The market value of the underlying Restricted Stock or the shares represented by the Restricted Stock Units awarded under a Long Term Incentive Plan Performance Period or an Incentive Compensation Plan that began on or after January 1, 2003 and for the Special Stock Awards issued on October 22, 2002 shall be the monthly

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      average Fair Market Value of the Stock during the calendar month preceding the month in which the restrictions lapse or shares are to be delivered as applicable. The monthly average Fair Market Value of the Stock is the average of the daily Fair Market Value of the Stock for each trading day of the month.
 
      The daily Fair Market Value of the Stock shall be deemed equal to the average of the high and low selling prices of the Stock on the New York Stock Exchange.
 
      Amounts deferred pursuant to Section 3(e) and 3(f) and Section 5(h)(3) will be credited to the Participant’s Deferred Compensation Account as soon as practicable, but not later than 30 days after the cash payment would have been made had it not been deferred. Amounts deferred pursuant to other provisions of this Plan shall be credited as soon as practicable but not later than 30 days after the date the Award would otherwise be payable.
 
  (b)   Designation of Investments. The amount in each Participant’s Deferred Compensation Account shall be deemed to have been invested and reinvested from time to time, in such “eligible securities” as the Participant shall designate. Prior to or in the absence of a Participant’s designation, the Company shall designate an “eligible security” in which the Participant’s Deferred Compensation Account shall be deemed to have been invested until designation instructions are received from the Participant. Eligible securities are those securities designated by the Chief Financial Officer of the Company, or his successor. The Chief Financial Officer of the Company may include as eligible securities, stocks listed on a national securities exchange, and bonds, notes, debentures, corporate or governmental, either listed on a national securities exchange or for which price quotations are published in The Wall Street Journal and shares issued by investment companies commonly known as “mutual funds”. The Participant’s Deferred Compensation Account will be adjusted to reflect the deemed gains, losses, and earnings as though the amount deferred was actually invested and reinvested in the eligible securities for the Participant’s Deferred Compensation Account.

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      Notwithstanding anything to the contrary in this section 4(b), in the event the Company (or any trust maintained for this purpose) actually purchases or sells such securities in the quantities and at the times the securities are deemed to be purchased or sold for a Participant’s Deferred Compensation Account, the Account shall be adjusted accordingly to reflect the price actually paid or received by the Company for such securities after adjustment for all transaction expenses incurred (including without limitation brokerage fees and stock transfer taxes).
 
      In the case of any deemed purchase not actually made by the Company, the Deferred Compensation Account shall be charged with a dollar amount equal to the quantity and kind of securities deemed to have been purchased multiplied by the fair market value of such security on the date of reference and shall be credited with the quantity and kind of securities so deemed to have been purchased. In the case of any deemed sale not actually made by the Company, the account shall be charged with the quantity and kind of securities deemed to have been sold, and shall be credited with a dollar amount equal to the quantity and kind of securities deemed to have been sold multiplied by the fair market value of such security on the date of reference. As used in this paragraph “fair market value” means in the case of a listed security the closing price on the date of reference, or if there were no sales on such date, then the closing price on the nearest preceding day on which there were such sales, and in the case of an unlisted security the mean between the bid and asked prices on the date of reference, or if no such prices are available for such date, then the mean between the bid and asked prices to the nearest preceding day for which such prices are available.
 
      The Chief Financial Officer of the Company may also designate a third party to provide services that may include record keeping, Participant accounting, Participant communication, payment of installments to the Participant, tax reporting, and any other services specified by the Company in agreement with such third party.

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  (c)   Payments. A Participant’s Deferred Compensation Account shall be debited with respect to payments made from the account pursuant to this Plan as of the date such payments are made from the account. The payment shall be made as soon as practicable, but no later than 30 days, after the installment payment date.
 
      If any person to whom a payment is due hereunder is under legal disability as determined in the sole discretion of the Plan Administrator, the Plan Administrator shall have the power to cause the payment due such person to be made to such person’s guardian or other legal representative for the person’s benefit, and such payment shall constitute a full release and discharge of the Company, the Plan Administrator, and any fiduciary of the Plan.
 
  (d)   Statements. At least one time per year the Company or the Company’s designee will furnish each Participant a written statement setting forth the current balance in the Participant’s Deferred Compensation Account, the amounts credited or debited to such account since the last statement and the payment schedule of deferred Awards and deemed gains, losses, and earnings accrued thereon as provided by the deferred payment option selected by the Participant.

SECTION 5. Payments from Deferred Compensation Accounts.

  (a)   Election of Method of Payment for an Incentive Compensation Plan Award. At the time a Potential Participant submits an indication of preference to defer all or any part of an Award under an Incentive Compensation Plan as provided in Section 3(a) above, the Potential Participant shall also elect in a manner prescribed by the Plan Administrator, which of the payment options, provided for in Paragraph (b) of this Section, shall apply to the deferred portion of said Award adjusted for any deemed gains, losses and earnings accrued thereon credited to the

  (b)   Participant’s Deferred Compensation Account under this Plan. Subject to Paragraphs (e), (g), and (h) of this Section, if the Committee or CEO, as appropriate, accepts the

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      Potential Participant’s indication of preference, the election of the method of payment of the amount deferred shall become irrevocable.
 
  (b)   Payment Options. A Potential Participant may elect to have the deferred portion of an Incentive Compensation Plan Award adjusted for any deemed gains, losses, and earnings accrued thereon paid:

  (i)   (Post-Retirement) in 10 annual installments, the payment of the first of such installments to commence on the first day of the first calendar quarter which is on or after the first anniversary of the Potential Participant’s first day of Retirement at age 55 or above, or
 
  (ii)   (Pre-Retirement) in annual installments of not less than 5 nor more than 10, in semi-annual installments of not less than 10 nor more than 20, or in quarterly installments of not less than 20 nor more than 40. The first of such installments to commence, as soon as practicable after any date specified by the Potential Participant, so long as such date is the first day of a calendar quarter, is on or after the Settlement Date, is at least one year from the date the payout option was elected, and is prior to the date the Potential Participant will attain the Participant’s Normal Retirement Date under the terms of the Retirement Income Plan.

  (c)   Election of Method of Payment of the Value of Restricted Stock and Restricted Stock Units. As provided in Section 3(c) above, a deferral of the value of all or part of the Restricted Stock or Restricted Stock Units will be considered payment option (b)(i) of this Section subject to Paragraphs (e) and (g) of this Section.
 
  (d)   Election of Method of Payment of a Lump Sum Distribution from Non-Qualified Retirement Plans. At the time a Potential Participant submits an indication of preference to defer all or part of the lump sum distribution as provided in Section 3(d) above, the Potential Participant shall also elect in a manner prescribed by the Plan

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      Administrator which payment option shall apply to the deferred lump sum adjusted for any gains, losses and earnings to be accrued thereon credited to the Participant’s Deferred Compensation Account under this Plan. The payment options are annual installments of not less than 1 nor more than 15, semi-annual installments of not less than 2 nor more than 30, or quarterly installments of not less than 4 nor more than 60. The first installment to commence as soon as practicable after any date specified by the Potential Participant, so long as such date is the first day of a calendar quarter and is at least one year and not later than five years from the date the payout option was elected. Subject to Paragraph (g) of this Section, if the Committee or CEO, as appropriate, accepts the Potential Participant’s indication of preference, the election of the method of payment of the amount deferred shall become irrevocable.
 
  (e)   Payment Option Revisions. If a Section 5(b)(i) payment option applies to any part of the balance of a Participant’s Deferred Compensation Account, the Participant may revise such payment option as follows:

  (i)   Prior to Retirement. The Participant at any time during a period beginning 365 days prior to and ending 90 days prior to the date the Participant Retires at age 55 or above may, with respect to the total of all amounts subject to such payment option at the time of the Participant’s retirement at age 55 or above, in the manner prescribed by the Plan Administrator, revise such payment option and elect one of the payment options specified in (e)(iv) of this Section to apply to such total amount in place of such payment option.

  (ii)   Upon Layoff. If a Participant who is eligible to Retire or who is Laid Off during or after the year in which the Participant reaches age 50 is notified of Layoff, the Participant may, no later than 30 days after being notified of Layoff, in the manner prescribed by the Plan Administrator, revise such payment option and elect one of the payment options specified in (e)(iv) of this Section to apply to such total amount in place of such payment option.

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  (iii)   If Disabled. The Participant may at any time during a period from the date of the beginning of the qualifying period for the Company’s Long Term Disability Plan or similar plan to no later than 90 days prior to the end of such period, or within 30 days of the amendment of this Plan providing for such election, in the manner prescribed by the Plan Administrator, revise such payment option and elect one of the payment options specified in (e)(iv) of this Section to apply to the total of all amounts subject to such payment option; provided, however, that after the payments have begun, such payments may be made in a different manner if, the Participant due to an unanticipated emergency caused by an event beyond the control of the Participant results in financial hardship to the Participant, so request and the CEO gives written consent to the method of payment requested.
 
  (iv)   Payment Options After Revision. If a Participant revises a Section 5(b)(i) payment option as specified in (e)(i), (e)(ii) or (e)(iii) of this Section, the Participant may select payments in annual installments of not less than 1 nor more than 15, in semi-annual installments of not less than 2 nor more than 30, or in quarterly installments of not less than 4 nor more than 60 with the first installment to commence, as soon as practicable following any date specified by the Participant so long as such date is the first day of a calendar quarter, is on or after the Participant’s first day of Retirement at age 55 or above or the first day the Participant is no longer an Employee following Layoff, is at least one year and no more than five years from the date the payment option was revised.
 

  (f)   Installment Amount. The amount of each installment shall be determined by dividing the balance in the Participant’s Deferred Compensation Account as of the date the installment is to be paid, by the number of installments remaining to be paid (inclusive of the current installment).

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  (g)   Death of Participant. Upon the death of a Participant, the Participant’s beneficiary or beneficiaries designated in accordance with Section 6, or in the absence of an effective beneficiary designation, the surviving spouse, surviving children (natural or adopted) in equal shares, or the Estate of the deceased Participant, in that order of priority, shall receive payments in accordance with the payment option selected by the Participant, if death occurred after such payments had commenced; or if death occurred before payments have commenced, the beneficiary may select payments in annual installments of not less than 1 nor more than 15, in semi-annual installments of not less than 2 nor more than 30, or in quarterly installments of not less than 4 nor more than 60 with the first installment to commence, as soon as practicable following any date specified by the beneficiary so long as such date is the first day of a calendar quarter and is at least one year and no more than five years from the date the payment option is selected and is not later than the date the deceased Participant would have been age 65; provided, however, such payments may be made in a different manner if the beneficiary or beneficiaries entitled to receive or receiving such payments, due to an unanticipated emergency caused by an event beyond the control of the beneficiary or beneficiaries that results in financial hardship to the beneficiary or beneficiaries, so requests and the CEO gives written consent to the method of payment requested.
 
  (h)   Disability of Participant. In the event a Participant or Employee becomes disabled, the individual may, in the period from the date of the beginning of the qualifying period for the Company’s Long Term Disability Plan to no later than 90 days prior to the end of such period, or within 30 days of the amendment of this Plan providing for such election, indicate a preference, in a manner prescribed by the Plan Administrator, for any of the following:

  1)   to defer part or all of any Incentive Compensation Plan Award the Employee is eligible to receive in the immediately following calendar year,

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  2)   to defer part or all of the value of the Stock which would otherwise be delivered to the Employee when the restrictions lapse on any Restricted Stock or Restricted Stock Units or Restricted Stock Units are settled,
 
  3)   to defer part or all of the value from their account under the Defined Contribution Makeup Plan which would otherwise be paid as a lump sum to the Participant.

      Such indications of preference shall be subject to approval by the Committee if the Potential Participant is subject to Section 16 of the Exchange Act or by the CEO if the Potential Participant is not subject to Section 16 of the Exchange Act. The Committee or CEO, as applicable, shall consider such indication or preference as submitted and shall decide whether to accept or reject the preference expressed.
 
      Such indications of preference, if accepted, become irrevocable on the date of such acceptance. A deferral of any amount will be paid under the terms of Section 5(b)(i) hereof — ten (10) annual installments, but subject to revision as specified under the terms of this Plan.
 
  (i)   Termination of Employment.
        In the event a Participant’s employment with the Company, any Participating Subsidiary, or any other subsidiary of the Company terminates for any reason other than death, Retirement at age 55 or above, Disability, or Layoff during or after the year in which the Participant reaches age 50, the entire balance of the Participant’s Deferred Compensation Account shall be paid to the Participant in one lump sum as soon as practicable after the date the Participant terminates employment, except that a Participant who becomes employed by a member of the Affiliated Group immediately after terminating employment with the Company or Participating Subsidiary shall not receive their benefit under the Plan until the Participant terminates employment from the Affiliated Group; provided, however, the Committee, in its sole discretion, may

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      elect to make such payments in the amounts and on such schedule as it may determine.

  (j)   Rehire of Participant.
      In the event a Participant is a Rehired Participant, he/she will be eligible to receive notifications as specified in Section 2 and will be eligible to submit an Indication of Preference or Election to Defer as specified in Section 3, if the Participant agrees to the suspension of payments from his/her Deferred Compensation Account during the period of reemployment by the Company. Upon termination of reemployment, such payments shall resume on the same schedule as was in effect at the time the Participant previously Retired or was Laid Off.

SECTION 6. Special Provisions for Former ARCO Alaska Employees.

      Notwithstanding any provisions to the contrary, in order to comply with the terms of the Master Purchase and Sale Agreement (“Sale Agreement”) by which the Company acquired certain Alaskan assets of Atlantic Richfield Company (“ARCO”), a Participant who was eligible to participate in the ARCO employee benefit plans immediately prior to becoming an Employee and who was not employed by ARCO Marine, Inc. (a “former ARCO Alaska employee”) may, in a manner prescribed by the Plan Administrator, indicate a preference or make an election to:

  a)   voluntarily reduce salary and receive an Award in the amount of the reduction credited to, at the Employee’s election, (i) an account under this Plan, or (ii) for so long as the ARCO Executive Deferral Plan will accept such deferrals of salary, but not beyond December 31, 2001, an account under the ARCO Executive Deferral Plan.
 
  b)   defer any Award payable to a former ARCO employee who is involuntarily terminated prior to April 18, 2002 in lieu of a target ARCO Annual Incentive Plan (AIP) award, and at the Employee’s election credit the Award to (i) an account under this Plan, or (ii) to the ARCO Executive Deferral Plan.

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  c)   defer the Final ARCO Supplemental Executive Retirement Plan (SERP) benefit that will be calculated as of the earlier of April 17, 2002 or the date the former ARCO employee voluntarily or involuntarily terminates employment from the Company or any Participating Subsidiary to the ARCO Executive Deferral Plan.
 
  d)   defer the value of the restricted stock granted on July 31, 2000 to an account under this Plan when the restrictions lapse on July 31, 2001, July 31, 2002 and July 31, 2002. Such indications of preference shall be made in July of the year preceding the calendar year when the restrictions are scheduled to lapse or as soon as practicable after July 31, 2000 for the restrictions on the shares that are to be lapsed on July 31, 2001.
 
  e)   all indications of preference in Section 6(a), (b) and (c) are subject to approval by the Compensation Committee if the Employee is subject to Section 16 of the Exchange Act and by the CEO if the Employee is not subject to Section 16 of the Exchange Act.
 
  f)   for a former ARCO Alaska employee who was classified as a grade 7 or 8 under ARCO’s job classification system and was eligible under ARCO’s Executive Deferral Plan to voluntarily reduce salary and defer the amount of the voluntary salary reduction and who was classified as a grade 31 or below at that time under Phillips Petroleum Company’s job classification system, make an annual election to voluntarily reduce salary and defer the amount of the voluntary salary reduction for salary received from July 31, 2000 through December 31, 2000 and for the five years from 2001 through 2005 and receive a salary deferral credit under this Plan.

SECTION 7. Designation of Beneficiary.

      Each Participant shall designate a beneficiary or beneficiaries to receive the entire balance of the Participant’s Deferred Compensation Account by giving signed written notice of such designation to the Plan Administrator. The Participant may from time to time change or

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      cancel any previous beneficiary designation in the same manner. The last beneficiary designation received by the Plan Administrator shall be controlling over any prior designation and over any testamentary or other disposition. After acceptance by the Plan Administrator of such written designation, it shall take effect as of the date on which it was signed by the Participant, whether the Participant is living at the time of such receipt, but without prejudice to the Company or the CEO on account of any payment made under this Plan before receipt of such designation.

SECTION 8. Nonassignability.

      The right of a Participant, or beneficiary, or other person who becomes entitled to receive payments under this Plan, shall not be assignable or subject to garnishment, attachment or any other legal process by the creditors of, or other claimants against, the Participant, beneficiary, or other such person.

SECTION 9. Administration.

  (a)   The Plan Administrator may adopt such rules, regulations, and forms as deemed desirable for administration of the Plan and shall have the discretionary authority to allocate responsibilities under the Plan to such other persons as may be designated.
 
  (b)   Any claim for benefits hereunder shall be presented in writing to the Plan Administrator for consideration, grant or denial. In the event that a claim is denied in whole or in part by the Plan Administrator, the claimant, within ninety days of receipt of said claim by the Plan Administrator, shall receive written notice of denial. Such notice shall contain:

  (1)   a statement of the specific reason or reasons for the denial;
 
  (2)   specific references to the pertinent provisions hereunder on which such denial is based;

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  (3)   a description of any additional material or information necessary to perfect the claim and an explanation of why such material or information is necessary; and
 
  (4)   an explanation of the following claims review procedure set forth in paragraph (c) below.

  (c)   Any claimant who feels that a claim has been improperly denied in whole or in part by the Plan Administrator may request a review of the denial by making written application to the Trustee. The claimant shall have the right to review all pertinent documents relating to said claim and to submit issues and comments in writing to the Trustee. Any person filing an appeal from the denial of a claim must do so in writing within sixty days after receipt of written notice of denial. The Trustee shall render a decision regarding the claim within sixty days after receipt of a request for review, unless special circumstances require an extension of time for processing, in which case a decision shall be rendered within a reasonable time, but not later than 120 days after receipt of the request for review. The decision of the Trustee shall be in writing and, in the case of the denial of a claim in whole or in part, shall set forth the same information as is required in an initial notice of denial by the Plan Administrator, other than an explanation of this claims review procedure. The Trustee shall have absolute discretion in carrying out its responsibilities to make its decision of an appeal, including the authority to interpret and construe the terms hereunder, and all interpretations, findings of fact, and the decision of the Trustee regarding the appeal shall be final, conclusive and binding on all parties.
 
  (d)   Compliance with the procedures described in paragraphs (b) and (c) shall be a condition precedent to the filing of any action to obtain any benefit or enforce any right which any individual may claim hereunder. Notwithstanding anything to the contrary in the Plan, these paragraphs (b), (c) and (d) may not be amended without the written consent of a seventy-five percent (75%) majority of Participants and Beneficiaries and such paragraphs shall survive the termination of this Plan until all benefits accrued hereunder have been paid.

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SECTION 10. Employment not Affected by Plan.

      Participation or nonparticipation in this Plan shall neither adversely affect any person’s employment status, or confer any special rights on any person other than those expressly stated in the Plan. Participation in the Plan by an Employee of the Company or of a Participating Subsidiary shall not affect the Company’s or the Participating Subsidiary’s right to terminate the Employee’s employment or to change the Employee’s compensation or position.

SECTION 11. Determination of Recipients of Awards.

      The determination of those persons who are entitled to Awards under an Incentive Compensation Plan and any other such plans shall be governed solely by the terms and provisions of the applicable plan, and the selection of an Employee as a Potential Participant or the acceptance of an indication of preference to defer an Award hereunder shall not in any way entitle such Potential Participant to an Award.

SECTION 12. Method of Providing Payments.

  (a)   Nonsegregation. Amounts deferred pursuant to this Plan and the crediting of amounts to a Participant’s Deferred Compensation Account shall represent the Company’s unfunded and unsecured promise to pay compensation in the future. With respect to said amounts, the relationship of the Company and a Participant shall be that of debtor and general unsecured creditor. While the Company may make investments for the purpose of measuring and meeting its obligations under this Plan such investments shall remain the sole property of the Company subject to claims of its creditors generally, and shall not be deemed to form or be included in any part of the Deferred Compensation Account.
 
  (b)   Funding. It is the intention of the Company that this Plan shall be unfunded for federal tax purposes and for purposes of Title I of ERISA; provided, however, that the

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      Company may establish a grantor trust to satisfy part or all of its Plan payment obligations so long as the Plan remains unfunded for federal tax purposes and for purposes of Title I of ERISA.

SECTION 13. Amendment or Termination of Plan.

      Subject to Paragraph 9(d), the Company reserves the right to amend this Plan from time to time or to terminate the Plan entirely, provided, however, that no amendment may affect the balance in a Participant’s account on the effective date of the amendment. No Participant shall participate in a decision to amend or terminate this Plan. In the event of termination of the Plan, the Chief Executive Officer, in his sole discretion, may elect to pay to the Participant in one lump sum as soon as practicable after termination of the Plan, the balance then in the Participant’s account.

SECTION 14. Miscellaneous Provisions.

  (a)   Except as otherwise provided herein, the Plan shall be binding upon the Company, its successors and assigns, including but not limited to any corporation which may acquire all or substantially all of the Company’s assets and business or with or into which the Company may be consolidated or merged.
 
  (b)   This Plan shall be construed, regulated, and administered in accordance with the laws of the State of Texas except to the extent that said laws have been preempted by the laws of the United States.

SECTION 15. Effective Date of the Plan.

      This Plan is amended and restated effective as of April 1, 2003.

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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
     
      2003   2002**
     
 
      (Unaudited)
Earnings Available for Fixed Charges
               
 
Income from continuing operations before income taxes
  $ 4,318       708  
 
Distributions less than equity in earnings of fifty-percent-or-less-owned companies
    (64 )     (5 )
 
Fixed charges, excluding capitalized interest*
    505       303  

 
  $ 4,759       1,006  

Fixed Charges
               
 
Interest and expense on indebtedness, excluding capitalized interest
  $ 393       213  
 
Capitalized interest
    157       102  
 
Preferred dividend requirements of subsidiary and capital trusts
    14       24  
 
Interest portion of rental expense
    84       45  
 
Interest expense relating to guaranteed debt of fifty-percent-or-less-owned companies
          8  
 
Interest expense relating to guaranteed debt of greater-than-fifty-percent-owned companies
    2        
 
Capitalized interest relating to guaranteed debt of greater-than-fifty-percent-owned companies
          14  

 
  $ 650       406  

Ratio of Earnings to Fixed Charges
    7.3       2.5  

  * Includes amortization of capitalized interest totaling approximately $12 million in 2003 and $13 million in 2002.
** Restated for discontinued operations.

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

CERTIFICATIONS

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:   8/7/03      
 
    /s/ J.J. Mulva
       
        J. J. Mulva
President and Chief Executive Officer

exv31w2
 

Exhibit 31.2

CERTIFICATIONS

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:   8/7/03      
 
    /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, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Quarterly Report of ConocoPhillips (the company) on Form 10-Q for the period ending June 30, 2003, 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:

  (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:   8/7/03      
 
     
        /s/ J.J. Mulva
       
        J. J. Mulva
President and Chief Executive Officer
         
         
        /s/ John A. Carrig
       
        John A. Carrig
Executive Vice President, Finance, and
Chief Financial Officer