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

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2003
Commission file number 000-49987

ConocoPhillips
(Exact name of registrant as specified in its charter)

Delaware	01-0562944
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

600 North Dairy Ashford Road, 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 678,740,004 shares of common stock, $.01 par value, outstanding at April 30, 2003.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
	Item 1. FINANCIAL STATEMENTS
		Consolidated Statement of Operations
		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 4. CONTROLS AND PROCEDURES
PART II. OTHER INFORMATION
	Item 1. LEGAL PROCEEDINGS
	Item 6. EXHIBITS AND REPORTS ON FORM 8-K
SIGNATURE
CERTIFICATIONS
EXHIBIT INDEX
Computation of Ratio of Earnings to Fixed Charges
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

CONOCOPHILLIPS

TABLE OF CONTENTS

			Page(s)
Part I – Financial Information
	Item 1. Financial Statements
		Consolidated Statement of Operations		1
		Consolidated Balance Sheet		2
		Consolidated Statement of Cash Flows		3
		Notes to Consolidated Financial Statements		4
		Supplementary Information—Condensed Consolidating Financial Information		22
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			29
	Item 4. Controls and Procedures			52
Part II – Other Information
	Item 1. Legal Proceedings			54
	Item 6. Exhibits and Reports on Form 8-K			54
Signature				55
Certifications				56

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

Consolidated Statement of Operations ConocoPhillips

			Millions of Dollars
			Three Months Ended
			March 31
			2003			2002**
Revenues
Sales and other operating revenues*			$	26,942			8,431
Equity in earnings of affiliates				49			20
Other income				86			29
		Total Revenues		27,077			8,480
Costs and Expenses
Purchased crude oil and products				17,685			5,639
Production and operating expenses				1,650			917
Selling, general and administrative expenses				509			264
Exploration expenses				116			163
Depreciation, depletion and amortization				877			406
Taxes other than income taxes*				3,422			914
Accretion on discounted liabilities				33			5
Interest and debt expense				209			107
Foreign currency transaction losses (gains)				(3	)		1
Preferred dividend requirements of capital trusts and minority interests				14			13
		Total Costs and Expenses		24,512			8,429
Income from continuing operations before income taxes				2,565			51
Provision for income taxes				1,295			149
Income (Loss) From Continuing Operations				1,270			(98	)
Income (loss) from discontinued operations				22			(4	)
Income (Loss) Before Cumulative Effect of Change in Accounting Principle				1,292			(102	)
Cumulative effect of change in accounting principle				145			—
Net Income (Loss)			$	1,437			(102	)
Income (Loss) Per Share of Common Stock
Basic
	Continuing operations		$	1.87			(.26	)
	Discontinued operations			.03			(.01	)
	Before cumulative effect of change in accounting principle			1.90			(.27	)
	Cumulative effect of change in accounting principle			.21			—
Net Income (Loss)			$	2.11			(.27	)
Diluted
	Continuing operations		$	1.86			(.26	)
	Discontinued operations			.03			(.01	)
	Before cumulative effect of change in accounting principle			1.89			(.27	)
	Cumulative effect of change in accounting principle			.21			—
Net Income (Loss)			$	2.10			(.27	)
Dividends Paid Per Share of Common Stock			$	.40			.36
Average Common Shares Outstanding (in thousands)
	Basic			679,538			382,337
	Diluted			682,744			382,337
*    Includes excise taxes on petroleum products sales			$	3,148			764
** Restated for discontinued operations.

See Notes to Consolidated Financial Statements.

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Consolidated Balance Sheet ConocoPhillips

			Millions of Dollars
			March 31			December 31
			2003			2002
Assets
Cash and cash equivalents			$	423			307
Accounts and notes receivable (net of allowance of $48 million in 2003 and 2002)				4,061			2,904
Accounts and notes receivable—related parties				1,920			1,476
Inventories				3,988			3,845
Prepaid expenses and other current assets				664			766
Assets of discontinued operations held for sale				1,629			1,605
		Total Current Assets		12,685			10,903
Investments and long-term receivables				6,914			6,821
Net properties, plants and equipment				44,282			43,030
Goodwill				14,606			14,444
Intangibles				1,127			1,119
Other assets				504			519
Total Assets			$	80,118			76,836
Liabilities
Accounts payable			$	6,735			5,949
Accounts payable—related parties				570			303
Notes payable and long-term debt due within one year				844			849
Accrued income and other taxes				3,351			1,991
Other accruals				3,047			3,075
Liabilities of discontinued operations held for sale				578			649
		Total Current Liabilities		15,065			12,816
Long-term debt				17,396			18,917
Accrued dismantlement, removal and environmental costs				2,639			1,666
Deferred income taxes				8,550			8,361
Employee benefit obligations				2,597			2,755
Other liabilities and deferred credits				1,948			1,803
Total Liabilities				48,195			46,318
Company-Obligated Mandatorily Redeemable Preferred Securities of Phillips 66 Capital Trust II				350			350
Other Minority Interests				648			651
Common Stockholders’ Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2003—705,350,628 shares; 2002—704,354,839 shares)
	Par value			7			7
	Capital in excess of par			25,205			25,178
Compensation and Benefits Trust (CBT) (at cost: 2003 and 2002—26,785,094 shares)				(907	)		(907	)
Accumulated other comprehensive income (loss)				9			(164	)
Unearned employee compensation—Long-Term Stock Savings Plan (LTSSP)				(213	)		(218	)
Retained earnings				6,824			5,621
Total Common Stockholders’ Equity				30,925			29,517
Total			$	80,118			76,836

See Notes to Consolidated Financial Statements.

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Consolidated Statement of Cash Flows ConocoPhillips

			Millions of Dollars
			Three Months Ended
			March 31
			2003			2002*
Cash Flows From Operating Activities
Income (loss) from continuing operations			$	1,270			(98	)
Adjustments to reconcile income from continuing operations to net cash provided by continuing operations
	Non-working capital adjustments
		Depreciation, depletion and amortization		877			406
		Dry hole costs and leasehold impairments		40			109
		Accretion on discounted liabilities		33			5
		Deferred taxes		236			(81	)
		Other		67			147
	Working capital adjustments**
		Decrease in aggregate balance of accounts receivable sold		(266	)		(102	)
		Increase in other accounts and notes receivable		(1,287	)		(289	)
		Decrease (increase) in inventories		(140	)		98
		Decrease in prepaid expenses and other current assets		35			55
		Increase in accounts payable		972			214
		Increase in taxes and other accruals		1,398			108
Net cash provided by continuing operations				3,235			572
Net cash provided by (used in) discontinued operations				(56	)		7
Net Cash Provided by Operating Activities				3,179			579
Cash Flows From Investing Activities
Capital expenditures and investments, including dry hole costs				(1,309	)		(645	)
Proceeds from asset dispositions				121			45
Long-term advances to affiliates and other investments				(28	)		(12	)
Net cash used in continuing operations				(1,216	)		(612	)
Net cash used in discontinued operations				(17	)		(12	)
Net Cash Used in Investing Activities				(1,233	)		(624	)
Cash Flows From Financing Activities
Issuance of debt				269			243
Repayment of debt				(1,825	)		(39	)
Issuance of company common stock				19			25
Redemption of company common stock				(1	)		—
Dividends paid on common stock				(271	)		(138	)
Other				(21	)		(18	)
Net cash provided by (used in) continuing operations				(1,830	)		73
Net Cash Provided by (Used in) Financing Activities				(1,830	)		73
Net Change in Cash and Cash Equivalents				116			28
Cash and cash equivalents at beginning of period				307			142
Cash and Cash Equivalents at End of Period			$	423			170

*    Restated for discontinued operations.
** Net of acquisition and disposition of businesses.

See Notes to Consolidated Financial Statements.

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Notes to Consolidated Financial Statements ConocoPhillips

Note 1—Interim Financial Information

The financial information for the interim periods presented in the financial statements included in this report is unaudited and includes all known accruals and adjustments that, in the opinion of management, are necessary for a fair presentation of the consolidated financial position of ConocoPhillips and its results of operations and cash flows for such periods. All such adjustments are of a normal and recurring nature. These interim financial statements should be read in conjunction with 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 has been 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 first quarter of 2002 reflect only Phillips’ activity.

Note 2—Change in Accounting Principle

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 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 was an increase in net income in the first quarter of 2003 of $145 million. The first quarter of 2003 effect of adopting this accounting principle on net income was an increase of $8 million, or $.01 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. Our largest individual obligations are related to fixed-base offshore production platforms around the world and to production facilities and pipelines in Alaska. 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.

Most of our asset retirement obligations are related to oil and gas production operations. Most of our larger downstream and corporate facilities, such as refineries and office buildings, are not presently subject to any legal requirements to remove these facilities and so are not within the scope of SFAS No. 143.

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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 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 a very arbitrary process, we have excluded it from our SFAS No. 143 estimates.

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

	Millions of Dollars
Opening balance at January 1, 2003	$	2,110
Accretion of discount		27
New obligations		10
Spending on existing obligations		(15	)
Property dispositions		(9	)
Foreign currency remeasurement		(11	)
Other adjustments		(1	)
Ending balance at March 31, 2003	$	2,111

The pro forma effects of the retroactive application of the change in accounting principle related to asset retirement obligations are as follows:

		Millions of Dollars
		Except Per Share Amounts
		Three Months Ended
		March 31
		2003		2002
Net income (loss)		$	1,292		(93	)
Earnings (loss) per share
	Basic		1.90		(.24	)
	Diluted		1.89		(.24	)

	Millions
	of Dollars
	2002
Pro forma amount of liability for asset retirement obligation at beginning of quarter	$	1,171
Pro forma amount of liability for asset retirement obligation at end of quarter		1,247

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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 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. Over the next few months, ConocoPhillips expects to receive the final outside appraisal of the long-lived assets 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. The following table summarizes, based on the first quarter of 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		2,832
Inventories		1,603
Prepaid expenses and other current assets		326
Investments and long-term receivables		3,036
Properties, plants and equipment (including $300 million of land)		19,091
Goodwill		12,233
Intangibles		662
In-process research and development		246
Other assets		312
Total assets	$	41,591
Accounts payable	$	2,873
Notes payable and long-term debt due within one year		3,102
Accrued income and other taxes		1,333
Other accruals		1,601
Long-term debt		8,930
Accrued dismantlement, removal and environmental costs		335
Deferred income taxes		4,008
Employee benefit obligations		1,638
Other liabilities and deferred credits		1,067
Minority interests		648
Common stockholders’ equity		16,056
Total liabilities and equity	$	41,591

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.”

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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. Of the $12,233 million of goodwill, $4,237 million is attributable to recording a net liability required under purchase accounting for deferred taxes. This and the remaining goodwill of $7,996 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.

Note 4—Discontinued Operations

During 2002 and the first quarter of 2003, we disposed of, or had committed to a plan to dispose of, U.S. retail and wholesale marketing assets, 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 16—Segment Disclosures and Related Information, these operations are included in Corporate and Other.

As a condition to the merger, the FTC required the divestiture of certain assets. In the fourth quarter of 2002, we sold our propane terminal assets at Jefferson City, Missouri, and East St. Louis, Illinois. We have also signed purchase and sales agreements to sell:

• 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;

• our Commerce City, Colorado, refinery, and related crude oil pipelines, and our Colorado Phillips-branded motor fuel marketing operations (both retail and wholesale); and

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

Certain of these sales are awaiting final FTC review and approval. We expect to complete the sales of all of these assets by the end of the third quarter of 2003.

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 first quarter of 2003 included a $25 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.

7

Revenues and income (loss) from discontinued operations were as follows:

	Millions of Dollars
	Three Months Ended
	March 31
	2003		2002
Sales and other operating revenues from discontinued operations	$	2,182		1,316
Income (loss) from discontinued operations before-tax	$	38		(6	)
Income tax expense (benefit)		16		(2	)
Income (loss) from discontinued operations	$	22		(4	)

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

	Millions of Dollars
	March 31		December 31
	2003		2002
Assets
Inventories	$	231		211
Other current assets		135		136
Net properties, plants and equipment		1,182		1,178
Intangibles		23		23
Other assets		58		57
Assets of discontinued operations	$	1,629		1,605
Liabilities
Accounts payable and other current liabilities	$	321		331
Long-term debt		33		34
Accrued dismantlement, removal and environmental costs		62		86
Other liabilities and deferred credits		162		198
Liabilities of discontinued operations	$	578		649

Note 5—Stock-Based Compensation

Effective January 1, 2003, ConocoPhillips adopted the fair-value accounting method provided for under SFAS No. 123, “Accounting for Stock-Based Compensation.” We are using the prospective transition method provided under SFAS No. 123, applying the fair-value accounting method and recognizing compensation expense for all stock options granted or modified after December 31, 2002; options granted prior to 2003 will continue to be accounted for under 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.

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		Millions of Dollars
		Three Months Ended
		March 31
		2003		2002
Net income (loss), as reported		$	1,437		(102	)
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects			9		7
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effects			17		53
Pro forma net income (loss)		$	1,429		(148	)
Earnings (loss) per share:
	Basic—as reported	$	2.11		(.27	)
	Basic—pro forma		2.10		(.39	)
	Diluted—as reported		2.10		(.27	)
	Diluted—pro forma		2.09		(.39	)

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

Note 6—Inventories

Inventories consisted of the following:

	Millions of Dollars
	March 31		December 31
	2003		2002
Crude oil and petroleum products	$	3,522		3,395
Canadian Syncrude (from mining operations)		3		4
Materials, supplies and other		463		446
	$	3,988		3,845

Inventories valued on a last-in, first-out (LIFO) basis totaled $3,450 million and $3,349 million at March 31, 2003, and December 31, 2002, respectively. The excess of current replacement cost over LIFO cost of inventories amounted to $1,120 million and $1,083 million at March 31, 2003, and December 31, 2002, respectively.

9

Note 7—Properties, Plants and Equipment

Properties, plants and equipment included the following:

	Millions of Dollars
	March 31		December 31
	2003		2002
Properties, plants and equipment (at cost)	$	56,667		54,559
Less accumulated depreciation, depletion and amortization		12,385		11,529
	$	44,282		43,030

Note 8—Restructuring

In 2002, as a result of the merger, we implemented a restructuring program to capture the synergies of combining Conoco and Phillips and recognized a restructuring liability for anticipated employee severance payments and incremental pension and medical plan benefit costs associated with the work force reductions, site closings, and Conoco employee relocations. In the first quarter of 2003, we recorded accruals totaling $46 million for severance related benefits, site closings, Conoco employee relocation costs and pension and other post-retirement benefits. Of this total, $44 million was reflected as a purchase price adjustment in the consolidated financial statements and $2 million was reflected in selling, general and administrative expense and production and operating expense. Included in the total accruals of $46 million was a $7 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 and is reported as part of our employee benefit plan obligations. A roll-forward of activity during the first quarter of 2003 is provided below for the balance of the accrual, which consists of severance related benefits to be provided to approximately 3,100 employees worldwide, most of whom are in the United States, as well as other merger related expenses.

	Millions of Dollars
			First Quarter 2003
	Reserve at								Reserve at
	December 31, 2002		Accrual			Benefit Payments			March 31, 2003
Conoco	$	106		44			(31	)		119
Phillips		269		(5	)		(137	)		127
Total	$	375		39			(168	)		246

The ending restructuring liability is expected to be extinguished within one year, except for $23 million, classified as long-term. Approximately 1,150 employees were terminated during the first quarter of 2003 and approximately 1,925 employees have been terminated since the restructuring program was implemented.

Note 9—Debt

At March 31, 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

10

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 March 31, 2003, we had no debt outstanding under these credit facilities, but had $509 million in commercial paper outstanding, of which $151 million was denominated in foreign currencies. The commercial paper is supported 100 percent by the credit facilities and the amount approximates fair value. Our Norwegian subsidiary has two $300 million revolving credit facilities that expire in June 2004, under which no borrowings were outstanding as of March 31, 2003.

In the first quarter of 2003, in addition to reducing our commercial paper from $1,517 million at December 31, 2002, to $509 million at March 31, 2003, we paid the following notes as they were called or matured and funded the payments with cash from operating activities:

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

• $181 million SRW Cogeneration Limited Partnership note; and

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

In April 2003, we paid the following notes as they were called or matured:

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

• $500 million floating rate notes due April 15, 2003.

In May 2003, we will pay our $150 million 8.25% notes due May 15, 2003, when they mature.

Note 10—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 an undiscounted 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 undiscounted 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

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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 inflation and other 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 segments’, operations, capital resources or liquidity. However, settlements and costs incurred in matters that previously have been resolved have not been material to our results of operations or financial condition. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, 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 have considered this inability in estimating our potential liability and we have adjusted 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. At March 31, 2003, ConocoPhillips’ balance sheet included a total environmental accrual from continuing operations of $737 million, compared with $743 million at December 31, 2002. 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.

Other Legal Proceedings—ConocoPhillips is 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.

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Other Contingencies—ConocoPhillips has contingent liabilities resulting from throughput agreements with pipeline and processing companies. Under these agreements, ConocoPhillips 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. ConocoPhillips has various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.

Note 11—Guarantees

At March 31, 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 no recognized liability because the guarantees were issued prior to December 31, 2002.

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 $418 million assuming that completion certification is not achieved. Of this amount, $209 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 $1,821 million 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 March 31, 2003, we had guarantees of about $355 million outstanding for our portion of joint-venture debt obligations, which have terms of up to 24 years. We have recognized an $8 million liability related to these guaranteed debt obligations. Payment will be required if a joint venture defaults on its debt obligations.

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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 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 two drillships, which are operated by joint ventures. Potential payments could be required for guaranteed residual value amounts and amounts due under interest rate hedging agreements. The maximum potential future payments under the agreements are estimated to be approximately $193 million.

• 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, consisting 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 totaling $111 million. 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.

• 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. These agreements apportion future risks between the parties for 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 party 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 obligations 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 for an indemnity obligation. 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 any resulting indemnity obligation, possible actions to reduce the likelihood of a triggering event or to reduce the costs of performing an 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 10—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 12—Comprehensive Income (Loss)

ConocoPhillips’ comprehensive income (loss) was as follows:

			Millions of Dollars
			Three Months Ended
			March 31
			2003		2002
Net income (loss)			$	1,437		(102	)
After-tax changes in:
	Minimum pension liability adjustment			5		—
	Foreign currency translation adjustments			132		(1	)
	Hedging activities			3		—
	Equity affiliates:
		Foreign currency translation		32		(4	)
		Derivatives related		1		(23	)
			$	1,610		(130	)

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

		Millions of Dollars
		March 31			December 31
		2003			2002
Minimum pension liability adjustment		$	(231	)		(236	)
Foreign currency translation adjustments			230			98
Unrealized gain on securities			1			1
Deferred net hedging loss			(2	)		(5	)
Equity affiliates:
	Foreign currency translation		33			1
	Derivatives related		(22	)		(23	)
		$	9			(164	)

Note 13—Supplemental Cash Flow Information

Cash payments for the three-month periods ended March 31 included the following:

	Millions of Dollars
	2003		2002
Cash Payments
Interest	$	83		69
Income taxes		199		40

Note 14—Sales of Receivables

At March 31, 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 ConocoPhillips 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. ConocoPhillips’ retains beneficial interests in the pools of receivables held by the QSPEs, which are subordinate to the beneficial interests issued to the bank-sponsored entities. ConocoPhillips’ retained interests, which are reported on the balance sheet in accounts and notes receivable—related parties, were $1.6 billion and $1.3 billion at March 31, 2003, and December 31, 2002, respectively. ConocoPhillips also retains servicing responsibility related to the sold receivables, the fair value of which approximates adequate compensation for the servicing costs incurred.

In the first three 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		6,304			4,561	*
Cash collections remitted		(6,306	)		(4,663	)*
Receivables sold at March 31	$	1,321			838
Discounts and other fees paid on revolving balances	$	5			4

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

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At December 31, 2002, ConocoPhillips had sold $264 million of receivables under a factoring arrangement that included a recourse obligation to repurchase uncollected receivables. At March 31, 2003, no receivables were outstanding under this or similar arrangements.

Note 15—Related Party Transactions

Significant transactions with related parties were:

	Millions of Dollars
	Three Months Ended
	March 31
	2003			2002
Operating revenues (a)	$	1,087			155
Purchases (b)		885			203
Operating expenses and selling, general and administrative expenses (c)		138			34
Net interest (income) expense (d)		(13	)		2

(a)	ConocoPhillips’ 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 to CFJ Properties and GKG Mineraloelhandel GMbH & Co. KG. 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)	ConocoPhillips purchases 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)	ConocoPhillips pays processing fees to various affiliates, the most significant being MSLP. Additionally, ConocoPhillips pays contract drilling fees to two deepwater drillship affiliates, crude oil transportation fees to pipeline equity companies, and commissions to the receivable monetization companies.
(d)	ConocoPhillips pays and/or receives 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.

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Note 16—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)	E&P—This segment primarily explores for and produces crude oil, natural gas and natural gas liquids on a worldwide basis. At March 31, 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)	R&M—This segment refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. At March 31, 2003, we owned 12 refineries in the United States (excluding two refineries treated as discontinued operations and 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, carbon fibers, fuels technology and power generation.

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 of Conoco and Phillips; 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
			March 31
			2003			2002
Sales and Other Operating Revenues
E&P
	United States		$	4,771			1,037
	International			3,346			477
	Intersegment eliminations-U.S.			(716	)		(221	)
	Intersegment eliminations-international			(841	)		—
		E&P		6,560			1,293
Midstream
	Total sales			1,620			187
	Intersegment eliminations			(376	)		(107	)
		Midstream		1,244			80
R&M
	United States			14,409			7,050
	International			4,788			4
	Intersegment eliminations-U.S.			(121	)		(2	)
	Intersegment eliminations-international			—			—
		R&M		19,076			7,052
Chemicals				3			3
Emerging Businesses				56			1
Corporate and Other				3			2
Consolidated Sales and Other Operating Revenues			$	26,942			8,431
Net Income (Loss)
E&P
	United States		$	837			155
	International			446			(13	)
		Total E&P		1,283			142
Midstream				31			12
R&M
	United States			256			(92	)
	International			114			5
		Total R&M		370			(87	)
Chemicals				(23	)		(11	)
Emerging Businesses				(34	)		(5	)
Corporate and Other				(190	)		(153	)
Consolidated Net Income (Loss)			$	1,437			(102	)

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			Millions of Dollars
			March 31		December 31
			2003		2002
Total Assets
E&P
	United States		$	15,644		14,196
	International			20,693		19,541
		Total E&P		36,337		33,737
Midstream				1,729		1,931
R&M
	United States			19,850		19,553
	International			4,649		3,632
		Total R&M		24,499		23,185
Chemicals				2,057		2,095
Emerging Businesses				592		737
Corporate and Other*				14,904		15,151
Consolidated Total Assets			$	80,118		76,836

* Includes goodwill not yet allocated to reporting units of $12,233 million at March 31, 2003, and $12,079 million at December 31, 2002.

Note 17—Income Taxes

ConocoPhillips’ effective tax rate for the first quarter of 2003 was 50 percent, compared with 292 percent for the same period in the prior year. 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 of an exploration prospect without a corresponding tax benefit.

Note 18—New Accounting Standards

In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, “Consolidation of Variable Interest Entities,” (VIEs) in an effort to expand upon and strengthen existing accounting guidance that addresses when a company should include in its financial statements the assets, liabilities and activities of another entity. In general, a 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. Interpretation No. 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 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 Interpretation No. 46 applied immediately to VIEs created after January 31, 2003, and will apply to older VIEs no later than the third quarter of 2003. We are studying the impact of the interpretation on VIEs created prior to January 31, 2003, to determine if we are the primary beneficiary of the VIEs and the impact on our financial statements in the third quarter of 2003. Based upon our preliminary review, it is reasonably possible that we will consolidate certain VIEs related to leasing arrangements, which could increase debt by up to $2.4 billion.

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In April 2003, the FASB released Statement of Financial Accounting Standards 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 are still reviewing this new release, but at this time do not expect the adoption of this standard to have a material impact on ConocoPhillips’ results of operations or financial position.

In the second quarter of 2003, the FASB is expected to issue a Statement of Financial Accounting Standards titled “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 new statement is expected to provide that mandatorily redeemable instruments meet the conceptual definition of liabilities and must be presented as such on the balance sheet. The statement is expected to be effective upon issuance for all contracts created or modified after the issuance date and is expected to be effective on all previously existing contracts no later than the third quarter of 2003. We are currently evaluating the impact of the proposed standard, and it is likely that some of currently reported mandatorily redeemable preferred stock and minority interest securities will be reclassified as liabilities.

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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.

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

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		Millions of Dollars
		Three Months Ended March 31, 2003
					ConocoPhillips		ConocoPhillips			All Other		Consolidating			Total
Statement of Operations		ConocoPhillips			Holding Company		Company			Subsidiaries		Adjustments			Consolidated
Revenues
Sales and other operating revenues		$	—			—		17,762			9,180		—			26,942
Equity in earnings of affiliates			1,284			1,247		1,133			81		(3,696	)		49
Other income			—			—		(157	)		243		—			86
Intercompany revenues			7			150		984			1,553		(2,694	)		—
Total revenues			1,291			1,397		19,722			11,057		(6,390	)		27,077
Costs and Expenses
Purchased crude oil and products			—			—		15,172			4,834		(2,321	)		17,685
Production and operating expenses			—			—		970			770		(90	)		1,650
Selling, general and administrative expenses			1			—		411			99		(2	)		509
Exploration expenses			—			—		31			85		—			116
Depreciation, depletion and amortization			—			—		271			606		—			877
Taxes other than income taxes			—			—		1,257			2,165		—			3,422
Accretion on discounted liabilities			—			—		7			26		—			33
Interest and debt expense			31			93		309			57		(281	)		209
Foreign currency transaction losses (gains)			—			—		(8	)		5		—			(3	)
Preferred dividend requirements of capital trusts and minority interests			—			—		—			14		—			14
	Total Costs and Expenses		32			93		18,420			8,661		(2,694	)		24,512
Income from continuing operations before income taxes			1,259			1,304		1,302			2,396		(3,696	)		2,565
Provision for income taxes			(11	)		20		68			1,218		—			1,295
Income from continuing operations			1,270			1,284		1,234			1,178		(3,696	)		1,270
Income from discontinued operations			22			22		22			9		(53	)		22
Income before accounting change			1,292			1,306		1,256			1,187		(3,749	)		1,292
Accounting change			145			145		145			147		(437	)		145
Net Income		$	1,437			1,451		1,401			1,334		(4,186	)		1,437

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		Millions of Dollars
		Three Months Ended March 31, 2002
				ConocoPhillips		ConocoPhillips			All Other		Consolidating
Statement of Operations		ConocoPhillips		Holding Company		Company			Subsidiaries		Adjustments			Total Consolidated
Revenues
Sales and other operating revenues		$	—		—		7,037			1,394		—			8,431
Equity in earnings of affiliates			—		—		166			26		(172	)		20
Other income			—		—		7			22		—			29
Intercompany revenues			—		—		1,475			1,390		(2,865	)		—
Total revenues			—		—		8,685			2,832		(3,037	)		8,480
Costs and Expenses
Purchased crude oil and products			—		—		7,072			1,309		(2,742	)		5,639
Production and operating expenses			—		—		611			356		(50	)		917
Selling, general and administrative expenses			—		—		224			48		(8	)		264
Exploration expenses			—		—		30			138		(5	)		163
Depreciation, depletion and amortization			—		—		136			270		—			406
Taxes other than income taxes			—		—		664			250		—			914
Accretion on discounted liabilities			—		—		3			2		—			5
Interest and debt expense			—		—		154			13		(60	)		107
Foreign currency transaction losses (gains)			—		—		—			1		—			1
Preferred dividend requirements of capital trusts and minority interests			—		—		—			13		—			13
	Total Costs and Expenses		—		—		8,894			2,400		(2,865	)		8,429
Income (loss) from continuing operations before income taxes			—		—		(209	)		432		(172	)		51
Provision for income taxes			—		—		(111	)		260		—			149
Income (loss) from continuing operations			—		—		(98	)		172		(172	)		(98	)
Income (loss) from discontinued operations			—		—		(4	)		7		(7	)		(4	)
Net Income (Loss)		$	—		—		(102	)		179		(179	)		(102	)

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		Millions of Dollars
		At March 31, 2003
					ConocoPhillips			ConocoPhillips		All Other		Consolidating			Total
Balance Sheet		ConocoPhillips			Holding Company			Company		Subsidiaries		Adjustments			Consolidated
Assets
Cash and cash equivalents		$	—			—			222		201		—			423
Accounts and notes receivable			662			768			30,319		10,543		(36,311	)		5,981
Inventories			—			—			2,875		1,113		—			3,988
Prepaid expenses and other current assets			9			—			269		375		11			664
Assets of discontinued operations			—			—			320		1,309		—			1,629
	Total Current Assets		671			768			34,005		13,541		(36,300	)		12,685
Investments and long-term receivables			37,480			35,545			34,545		23,574		(124,230	)		6,914
Net properties, plants and equipment			—			—			13,975		30,307		—			44,282
Goodwill*			—			—			2,348		12,258		—			14,606
Intangibles			—			—			420		707		—			1,127
Other assets			13			18			111		365		(3	)		504
Total		$	38,164			36,331			85,404		80,752		(160,533	)		80,118
Liabilities and Stockholders’ Equity
Accounts payable		$	11,292			1,889			18,064		12,311		(36,311	)		7,245
Notes payable and long-term debt due within one year			—			530			305		9		—			844
Accrued income and other taxes			(3	)		73			813		2,468		—			3,351
Other accruals			44			123			1,339		1,541		—			3,047
Liabilities of discontinued operations			—			—			79		499		—			578
	Total Current Liabilities		11,333			2,615			20,600		16,828		(36,311	)		15,065
Long-term debt			2,501			4,053			6,755		4,087		—			17,396
Accrued dismantlement, removal and environmental costs			—			—			653		1,986		—			2,639
Deferred income taxes			—			(41	)		2,737		5,862		(8	)		8,550
Employee benefit obligations			—			—			1,278		1,319		—			2,597
Other liabilities and deferred credits			—			5,154			39,604		24,867		(67,677	)		1,948
Total Liabilities			13,834			11,781			71,627		54,949		(103,996	)		48,195
Trust Preferred Securities and other minority interests			—			(12	)		—		1,010		—			998
Retained earnings			229			(1,098	)		7,148		9,561		(9,016	)		6,824
Other stockholders’ equity			24,101			25,660			6,629		15,232		(47,521	)		24,101
Total		$	38,164			36,331			85,404		80,752		(160,533	)		80,118

* 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.

25

		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			—			22,837		13,510		(31,975	)		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			—			26,214		16,587		(31,911	)		10,903
Investments and long-term receivables			32,301			35,538			32,034		21,897		(114,949	)		6,821
Net properties, plants and equipment			—			—			13,874		29,156		—			43,030
Goodwill**			—			—			2,350		12,094		—			14,444
Intangibles			—			—			425		694		—			1,119
Other assets			14			19			112		374		—			519
Total		$	32,328			35,557			75,009		80,802		(146,860	)		76,836
Liabilities and Stockholders’ Equity
Accounts payable		$	5,840			3,291			15,231		13,866		(31,976	)		6,252
Notes payable and long-term debt due within one year			—			526			314		9		—			849
Accrued income and other taxes			(1	)		53			517		1,422		—			1,991
Other accruals			21			58			1,420		1,576		—			3,075
Liabilities of discontinued operations			—			—			123		526		—			649
	Total Current Liabilities		5,860			3,928			17,605		17,399		(31,976	)		12,816
Long-term debt			3,509			4,054			7,105		4,249		—			18,917
Accrued dismantlement, removal and environmental costs			—			—			451		1,215		—			1,666
Deferred income taxes			—			(41	)		2,557		5,853		(8	)		8,361
Employee benefit obligations			—			—			1,401		1,354		—			2,755
Other liabilities and deferred credits			—			3,729			33,260		24,996		(60,182	)		1,803
Total Liabilities			9,369			11,670			62,379		55,066		(92,166	)		46,318
Trust Preferred Securities and other minority interests			—			(12	)		—		1,013		—			1,001
Retained earnings			(937	)		(1,349	)		7,156		10,076		(9,325	)		5,621
Other stockholders’ equity			23,896			25,248			5,474		14,647		(45,369	)		23,896
Total		$	32,328			35,557			75,009		80,802		(146,860	)		76,836

*	Restated for the merger of Tosco Corporation (Tosco) into ConocoPhillips Company on January 1, 2003. As a result of this merger, Tosco ceased to exist as a legal entity, and ConocoPhillips Company assumed all of Tosco’s properties, rights and obligations.
**	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.

26

	Millions of Dollars
	Three Months Ended March 31, 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 continuing operations	$	812			776			1,462			3,362			(3,177	)		3,235
Net cash provided by (used in) discontinued operations		—			—			(74	)		18			—			(56	)
Net Cash Provided by Operating Activities		812			776			1,388			3,380			(3,177	)		3,179
Cash Flows From Investing Activities
Capital expenditures and investments, including dry holes		—			(8	)		(913	)		(926	)		538			(1,309	)
Proceeds from asset dispositions		—			—			(145	)		266			—			121
Long-term advances to affiliates and other investments		450			—			(5,149	)		(1,590	)		6,261			(28	)
Net cash provided by (used in) continuing operations		450			(8	)		(6,207	)		(2,250	)		6,799			(1,216	)
Net cash used in discontinued operations		—			—			(13	)		(4	)		—			(17	)
Net Cash Provided by (Used in) Investing Activities		450			(8	)		(6,220	)		(2,254	)		6,799			(1,233	)
Cash Flows From Financing Activities
Issuance of debt		—			21			6,096			413			(6,261	)		269
Repayment of debt		(1,009	)		—			(369	)		(447	)		—			(1,825	)
Issuance of company common stock		19			—			—			—			—			19
Redemption of company common stock		(1	)		—			—			—			—			(1	)
Dividends paid on common stock		(271	)		(789	)		(789	)		(1,591	)		3,169			(271	)
Other		—			—			—			509			(530	)		(21	)
Net Cash Provided by (Used in) Financing Activities		(1,262	)		(768	)		4,938			(1,116	)		(3,622	)		(1,830	)
Net Change in Cash and Cash Equivalents		—			—			106			10			—			116
Cash and cash equivalents at beginning of year		—			—			116			191			—			307
Cash and Cash Equivalents at End of Period	$	—			—			222			201			—			423

27

	Millions of Dollars
	Three Months Ended March 31, 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	$	—		—		(2,276	)		2,820			28			572
Net cash provided by (used in) discontinued operations		—		—		(17	)		24			—			7
Cash Provided by (Used in) Operating Activities		—		—		(2,293	)		2,844			28			579
Cash Flows From Investing Activities
Capital expenditures and investments, including dry holes		—		—		(163	)		(498	)		16			(645	)
Proceeds from asset dispositions		—		—		32			37			(24	)		45
Long-term advances to affiliates and other investments		—		—		(12	)		(2,358	)		2,358			(12	)
Net cash used in continuing operations		—		—		(143	)		(2,819	)		2,350			(612	)
Net cash used in discontinued operations		—		—		(2	)		(10	)		—			(12	)
Net Cash Used in Investing Activities		—		—		(145	)		(2,829	)		2,350			(624	)
Cash Flows From Financing Activities
Issuance of debt		—		—		2,601			—			(2,358	)		243
Repayment of debt		—		—		(39	)		(2	)		2			(39	)
Issuance of company common stock		—		—		25			—			—			25
Redemption of preferred stock of subsidiaries		—		—		—			—			—			—
Dividends paid on common stock		—		—		(138	)		—			—			(138	)
Other		—		—		(2	)		6			(22	)		(18	)
Net Cash Provided by Financing Activities		—		—		2,447			4			(2,378	)		73
Net Change in Cash and Cash Equivalents		—		—		9			19			—			28
Cash and cash equivalents at beginning of year		—		—		20			122			—			142
Cash and Cash Equivalents at End of Period	$	—		—		29			141			—			170

28

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, intentions, and resources, 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 51.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three-month period ending March 31, 2003, is based on a comparison with the corresponding period of 2002. The merger of Conoco Inc. (Conoco) and Phillips Petroleum Company (Phillips) on August 30, 2002, impacts the comparability of the 2003 quarter with the corresponding 2002 quarter.

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.

As a result of the merger, we implemented a restructuring program in September 2002 to capture the benefits of combining the two companies 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 February 2004. Through March 31, 2003, approximately 3,100 positions worldwide had been identified for elimination. Of this total, 1,925 employees were terminated by March 31, 2003. We accrued $770 million in 2002 associated with implementing this program, of which $598 million primarily related to severance benefits. After making a net adjustment of $39 million for severance benefits in the first quarter of 2003 (of which $44 million was treated as a purchase price adjustment), and payments of $223 million in 2002 and $168 million in the first quarter of 2003, the severance accrual balance was reduced to $246 million as of March 31, 2003. For additional information on restructuring charges, see Note 8—Restructuring, in the Notes to Consolidated Financial Statements.

29

Consolidated Results

	Millions of Dollars
	Three Months Ended
	March 31
	2003		2002
Income (loss) from continuing operations	$	1,270		(98	)
Income (loss) from discontinued operations		22		(4	)
Cumulative effect of accounting change		145		—
Net income (loss)	$	1,437		(102	)

A summary of the company’s net income (loss) by business segment follows:

	Millions of Dollars
	Three Months Ended
	March 31
	2003			2002
Exploration and Production (E&P)	$	1,283			142
Midstream		31			12
Refining and Marketing (R&M)		370			(87	)
Chemicals		(23	)		(11	)
Emerging Businesses		(34	)		(5	)
Corporate and Other		(190	)		(153	)
Net income (loss)	$	1,437			(102	)

Net income was $1,437 million in the first quarter of 2003, compared with a net loss of $102 million in the first quarter of 2002. The improved results primarily were due to increased 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 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.

Statement of Operations Analysis

Sales and other operating revenues increased 220 percent in the first quarter of 2003, with the increase 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 145 percent in the first quarter of 2003. Our earnings from affiliates acquired in the merger accounted for the increase. Of these, our E&P joint venture in Canada (Petrovera) and our interest in a refinery in Melaka, Malaysia, provided the largest equity earnings. Of those equity affiliates included in the results of both quarters, our equity earnings from Duke Energy Field Services, LLC improved on higher natural gas liquids prices, while our results from Chevron Phillips Chemical Company LLC declined on lower margins and our results from Hamaca decreased because of production downtime during the quarter.

30

Other income increased 197 percent in the first quarter of 2003. The increase primarily was attributable to insurance demutualization benefits recognized in the first quarter of 2003. See the Corporate and Other section of “Segment Results” for additional information on the insurance benefits.

Purchased crude oil and products increased 214 percent in the first quarter of 2003, with the increase attributable to both higher purchase volumes and purchase prices of petroleum products such as automotive gasoline and distillates, as well as higher 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 80 percent in the first quarter of 2003, while selling, general and administrative expenses increased 93 percent. These increases primarily reflect:

• the larger size of our operations and staffing following the merger;

• merger-related costs of $33 million before-tax charged to selling, general and administrative expenses and $1 million to production and operating expenses;

• higher fuel and utility costs at our refineries due to increased natural gas prices; and

• accrued losses of $39 million before-tax due to terminating 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 decreased 29 percent in the first quarter of 2003. In the first quarter of 2002, we recognized a $77 million partial impairment of our leasehold investment in deepwater Block 34, offshore Angola, after an unsuccessful exploratory well. The absence of such a significant item in the first quarter of 2003 contributed to our lower exploration expenses in the current period.

Depreciation, depletion and amortization increased 116 percent in the first quarter of 2003. The increase mainly was 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 March 31, 2002, was $22.3 billion, compared with $44.3 billion at March 31, 2003.

Taxes other than income taxes increased 274 percent in the first quarter of 2003. The increase reflects higher excise taxes due to increased petroleum products sales volumes; higher production taxes due to increased crude oil production; and increased property and payroll taxes following the merger.

Accretion on discounted liabilities increased $28 million in the first quarter of 2003, reflecting the impact of environmental liabilities assumed in the merger. Effective January 1, 2003, this item also includes the accretion related to discounted legal obligations associated with the retirement and removal of long-lived assets.

Interest expense increased 95 percent in the first quarter of 2003, mainly due to our higher debt levels following the merger. Our total debt at March 31, 2002, was $8.9 billion, compared with $18.2 billion at March 31, 2003.

ConocoPhillips’ effective tax rate for the first quarter of 2003 was 50 percent, compared with 292 percent for the same period in the prior year. The higher effective tax rate in the 2002 period was the result of a higher proportion of income in higher-tax-rate jurisdictions and losses in lower-tax-rate jurisdictions, including the partial impairment of an exploration prospect without a corresponding tax benefit.

31

Income from discontinued operations was $22 million in the first quarter of 2003, compared with a net loss of $4 million in the first quarter of 2002. This improvement reflects the addition of assets classified as discontinued following the merger, as well as higher refining margins at the Woods Cross, Utah, refinery. The improvement was partially offset by $25 million of losses expected from terminating operating leases that provided 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 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— Change in Accounting Principle, in the Notes to Consolidated Financial Statements.

Segment Results

E&P

	Three Months Ended
	March 31
	2003		2002
	Millions of Dollars
Net Income
Alaska	$	525		123
Lower 48		312		32
United States		837		155
International		446		(13	)
	$	1,283		142

		Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)
	United States	$	31.47	18.73
	International		31.09	20.86
	Total consolidated		31.26	19.41
	Equity affiliates		20.97	15.86
	Worldwide		30.72	19.37
Natural gas—lease (per thousand cubic feet)
	United States		5.34	1.99
	International		3.92	2.41
	Total consolidated		4.49	2.15
	Equity affiliates		4.82	—
	Worldwide		4.49	2.15

	Millions of Dollars
Worldwide Exploration Expenses
General administrative; geological and geophysical; and lease rentals	$	76	54
Leasehold impairment		20	93
Dry holes		20	16
	$	116	163

32

		Three Months Ended
		March 31
		2003		2002
		Thousands of Barrels Daily
Operating Statistics
Crude oil produced
	Alaska		337		353
	Lower 48		60		33
	United States		397		386
	Norway		226		118
	United Kingdom		87		17
	Canada		33		1
	Other areas		137		44
	Total consolidated		880		566
	Equity affiliates		55		5
			935		571
Natural gas liquids produced
	Alaska		25		27
	Lower 48		19		1
	United States		44		28
	Norway		8		5
	United Kingdom		2		2
	Canada		11		—
	Other areas		2		2
			67		37

		Millions of Cubic Feet Daily
Natural gas produced*
	Alaska		189	168
	Lower 48		1,338	734
	United States		1,527	902
	Norway		305	135
	United Kingdom		1,002	173
	Canada		436	19
	Other areas		335	120
	Total consolidated		3,605	1,349
	Equity affiliates		12	—
			3,617	1,349

*  Represents quantities available for sale. Excludes gas equivalent of natural gas liquids shown above.

		Thousands of Barrels Daily
Mining operations
	Syncrude produced		17	—

33

Net income from our E&P segment increased 804 percent in the first quarter of 2003. The increase reflected:

• higher production volumes, primarily due to the merger;

• higher crude oil, natural gas liquids and natural gas sales prices;

• lower exploration expenses; 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 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 $30.72 per barrel in the first quarter of 2003, compared with $19.37 in the first quarter of 2002. We also benefited from higher natural gas prices, with our average worldwide price increasing from $2.15 per thousand cubic feet in the first quarter of 2002 to $4.49 in the first quarter of 2003.

U.S. E&P

Net income from our U.S. E&P operations increased 440 percent in the first quarter of 2003. Of the $682 million increase in net income, higher crude oil and natural gas prices contributed about $550 million. Increased production volumes following the merger accounted for the majority of the remaining increase, after considering the corresponding increases that go along with higher production, such as higher production taxes and production and operating expenses. 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 696,000 barrels per day in the first quarter of 2003, compared with 684,000 barrels per day in the fourth quarter of 2002. The 2 percent increase primarily was due to higher crude oil output in Alaska, where we experienced operating interruptions in the fourth quarter of 2002 and a full quarter’s production from the Palm drill site in the first quarter of 2003.

International E&P

Net income from our international E&P operations was $446 million in the first quarter of 2003, compared with a net loss of $13 million in the first quarter of 2002. Of the $459 million increase in net income, higher crude oil and natural gas prices contributed about $140 million. Increased production volumes following the merger accounted for the majority of the remaining increase, after considering the corresponding increases that go along with higher production, such as higher production taxes and production and operating expenses. 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 first quarter of 2003 were foreign currency transaction gains of $10 million, compared with gains of $2 million in the first quarter of 2002.

34

International E&P production on a barrel-of-oil-equivalent basis averaged 926,000 barrels per day in the first quarter of 2003, compared with 939,000 barrels per day in the fourth quarter of 2002. The slight decrease primarily was due to lower 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. Partially offsetting the impact of the Venezuelan shutdown was the initial quarter’s production from the Peng Lai 19-3 field in China’s Bohai Bay, which began producing in late-December 2002. In addition, production increased in Indonesia and Vietnam.

Midstream

	Three Months Ended
	March 31
	2003		2002
	Millions of Dollars
Net Income	$	31		12

		Dollars Per Barrel
Average Sales Prices
U.S. natural gas liquids*
	Consolidated	$	25.59	—
	Equity		24.53	12.83

	Thousands of Barrels Daily
Operating Statistics
Natural gas liquids extracted		222	118
Natural gas liquids fractionated-United States		168	107

* 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.

ConocoPhillips’ Midstream segment consists of our 30.3 percent interest in Duke Energy Field Services, LLC (DEFS), as well as our company-owned natural gas gathering and processing operations and our natural gas liquids fractionation and marketing businesses.

Net income from our Midstream segment increased 158 percent in the first quarter of 2003, with the increase primarily attributable to improved results from DEFS and the addition of consolidated midstream operations following the merger. DEFS’ results mainly increased because of higher natural gas liquids prices.

Included in the Midstream segment’s net income was a benefit of $9 million in the first quarter of 2003, the same as the first quarter of 2002, representing the amortization of the basis difference between the book value of our contribution to DEFS and our 30.3 percent equity interest in the net assets of DEFS.

35

R&M

	Three Months Ended
	March 31
	2003		2002
	Millions of Dollars
Net Income (Loss)
United States	$	256		(92	)
International		114		5
	$	370		(87	)

		Dollars Per Gallon
U.S. Average Sales Prices
Automotive gasoline
	Wholesale	$	1.10	.67
	Retail		1.37	.81
Distillates			1.05	.59

			Thousands of Barrels Daily
Operating Statistics
Refining operations*
	United States
		Rated crude oil capacity		2,167		1,642
		Crude oil runs		2,008		1,416
		Capacity utilization (percent)		93	%	86
		Refinery production		2,254		1,575
	International
		Rated crude oil capacity		442		72
		Crude oil runs		396		65
		Capacity utilization (percent)		90	%	90
		Refinery production		436		62
	Worldwide
		Rated crude oil capacity		2,609		1,714
		Crude oil runs		2,404		1,481
		Capacity utilization (percent)		92	%	86
		Refinery production		2,690		1,637
*  Includes ConocoPhillips’ share of equity affiliates.
Petroleum products outside sales
	United States
		Automotive gasoline		1,331		1,084
		Distillates		600		439
		Aviation fuels		164		162
		Other products		509		398
				2,604		2,083
	International			428		54
				3,032		2,137

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Net income from our R&M segment was $370 million in the first quarter of 2003, compared with a net loss of $87 million in the first quarter of 2002. The improved results from the first quarter of 2002 were attributable to the addition of refining and marketing assets in the merger and higher refining and wholesale gasoline margins. However, we recognized lease losses totaling $25 million after-tax in the first quarter of 2003 due to terminating 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 was 92 percent in the first quarter of 2003, compared with 86 percent in the corresponding period of 2002. Our refineries produced 2,690,000 barrels per day of petroleum products in the first quarter of 2003, compared with 1,637,000 barrels per day in the first 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 was $256 million in the first quarter of 2003, compared with a net loss of $92 million in the first quarter of 2002. The improvement was primarily due to higher refining margins and, to a lesser extent, higher marketing margins and the addition of refining and marketing assets in the merger. Although the average cost of a barrel of crude oil feedstock for our U.S. refineries increased from $20.09 in the first quarter of 2002 to $31.49 in the first quarter of 2003, our average sales prices for produced petroleum products increased at a higher rate, resulting in the improved refining margins in the quarter. The improvement in our refining margins was somewhat mitigated by the lack of lower-cost crude oil from Venezuela during the first quarter, which led to a less-than-optimum crude slate in certain locations.

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

Our U.S. refineries had a crude oil capacity utilization rate of 93 percent in the first quarter of 2003, compared with 86 percent in the corresponding period of 2002. Our utilization rate in the first quarter of 2002 was affected by market-based production reductions and two scheduled maintenance turnarounds. The first quarter 2003 utilization rate was affected by scheduled maintenance turnarounds at our Sweeny, Wood River and Ferndale refineries. The Ferndale turnaround included the startup of a new fluidized catalytic cracking unit that is designed to increase the yield of transportation fuel.

International R&M

Net income from our international R&M operations was $114 million in the first quarter of 2003, compared with net income of $5 million in the first quarter of 2002. The improvement was due to the larger size and scope of our international refining operations following the merger. In the first quarter of 2002, our international R&M operations consisted of our Whitegate refinery in Ireland with a crude capacity of 72,000 barrels per day, while in the first quarter 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 refineries had a crude oil capacity utilization rate of 90 percent in the first quarter of 2003, the same as the corresponding period of 2002.

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Chemicals

	Millions of Dollars
	Three Months Ended
	March 31
	2003			2002
Net loss	$	(23	)		(11	)

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.

Our Chemicals segment incurred a net loss of $23 million in the first quarter of 2003, compared with a net loss of $11 million in the first quarter of 2002. The increased loss in the 2003 quarter was attributable to the already weak market conditions deteriorating further in the quarter, as this industry was negatively impacted by higher feedstock costs, as well as higher fuel and utility costs. Results in the first quarter of 2002 included a $6 million benefit for the partial reversal of a lower-of-cost-or-market inventory reserve initially established in 2001.

Margins were lower in the first quarter of 2003 across the ethylene, polyethylene and normal alpha olefins product lines, primarily due to higher feedstock costs and significantly higher fuel and utility costs, resulting from higher natural gas and natural gas liquids prices. Lower sales volumes for ethylene, polyethylene, and normal alpha olefins were only partially offset by higher average sales prices for these products. Earnings for the benzene and paraxylene product lines improved on higher average realized sales prices and volumes, partially offset by higher feedstock, fuel and utility costs. Earnings from the styrene product lines were lower in 2003 as increased product and utility costs more than offset higher sales prices and volumes.

Emerging Businesses

	Millions of Dollars
	Three Months Ended
	March 31
	2003			2002
Net Loss
Fuels technology	$	(5	)		(5	)
Gas-to-liquids		(20	)		—
Power		1			—
Other		(10	)		—
	$	(34	)		(5	)

The Emerging Businesses segment includes the development of new businesses beyond our traditional operations. Our Emerging Businesses segment incurred a net loss of $34 million in the first quarter of 2003, compared with a net loss of $5 million in the first quarter of 2002. The increased net loss in the first quarter of 2003 was the result of the expanded size of this segment following the merger. In the first quarter of 2002, this segment included only the development of new fuels technologies, while in the first quarter of 2003 additional new business developments related to gas-to-liquids technologies, power generation, carbon fibers and other emerging technologies were included.

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

Corporate and Other

	Millions of Dollars
	Three Months Ended
	March 31
	2003			2002
Net Loss
Net interest	$	(167	)		(78	)
Corporate general and administrative expenses		(35	)		(47	)
Discontinued operations		22			(4	)
Merger-related costs		(27	)		(2	)
Other		17			(22	)
	$	(190	)		(153	)

Net interest represents interest expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased 114 percent in the first quarter of 2003, mainly due to our higher debt levels following the merger. Our total debt at March 31, 2003, was $18.2 billion, compared with $8.9 billion at March 31, 2002.

Corporate general and administrative expenses decreased 26 percent in the first quarter of 2003. We benefited from lower long-term compensation plan expenses in the 2003 period, as well as the timing effects of the allocation of certain of our staff costs to the operating segments. Partially offsetting these items was the impact of the merger, as well as the expensing of stock options in the 2003 quarter. Beginning in 2003, we elected to use the fair-value accounting method provided for under SFAS No. 123, “Accounting for Stock-Based Compensation.” See Note 5—Stock-Based Compensation, in the Notes to Consolidated Financial Statements for additional information on this issue.

Income from discontinued operations was $22 million in the first quarter of 2003, compared with a net loss of $4 million in the first quarter of 2002. The improvement reflects higher refining and marketing margins for those refining and marketing assets we have classified as held for sale and included in discontinued operations reporting. The 2003 quarter included $25 million after-tax related to accrued lease losses expected due to terminating leases that provide for guaranteed residual values related to various 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.

Merger-related costs in the first quarter of 2003 were $27 million, and included employee relocation expenses, transition labor costs, and other charges directly associated with the merger. The corresponding amount in the first quarter of 2002 was $2 million.

The category “Other” consists primarily of items not directly associated with the operating segments on a stand-alone basis, including certain foreign currency gains and losses and dividends on the preferred securities of capital trusts. Results from Other were improved in the first quarter of 2003, compared with the first quarter of 2002, primarily due to insurance demutualization benefits and foreign currency

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transaction gains in the first quarter of 2003, compared with foreign currency losses in the corresponding quarter of 2002. During the first quarter of 2003, we recognized an after-tax gain of $34 million, 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.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

	Millions of Dollars
	At March 31, 2003			At December 31, 2002
Current ratio		.8			.9
Total debt repayment obligations due within one year	$	844			849
Total debt	$	18,240			19,766
Mandatorily redeemable preferred securities of trust subsidiaries	$	350			350
Other minority interests	$	648			651
Common stockholders’ equity	$	30,925			29,517
Percent of total debt to capital*		36	%		39
Percent of floating-rate debt to total debt		7	%		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 March 31, 2003, was primarily the result of our paying down debt.

Significant Sources of Capital

During the first three months of 2003, cash of $3,179 million was provided by operating activities, an increase of $2,600 million from the same period of 2002. Cash provided by operating activities, before changes in working capital, increased $2,035 million compared with the first three months of 2002, primarily due to higher crude oil, natural gas liquids and natural gas prices, combined with increased production resulting from the addition of the Conoco assets; higher refining margins; and to a lesser extent, higher marketing margins. Positive working capital changes of $628 million were primarily due to an increase in taxes and other accruals and an increase in accounts payable, partially offset by increased receivables and increased inventories. Cash used in discontinued operations amounted to $56 million, compared with cash provided of $7 million in the first three 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 generated from operating activities. By the end of 2004, however, we anticipate raising funds of $2 billion to $3 billion from the sale of assets, including those assets required by the FTC to be sold. In December 2002, we signed a purchase and sale agreement to sell our Woods Cross, Utah, refinery and associated assets. In April 2003, we signed a purchase and sale agreement to sell our Commerce City, Colorado, refinery and related crude oil pipelines and our Colorado motor fuel marketing operations (both retail and wholesale). We also signed purchase and sale agreements to sell certain midstream natural gas gathering and processing assets in southeast New Mexico and certain midstream natural gas gathering assets in West Texas. We are awaiting FTC final review and approval on certain of these sales and expect to have all of these assets sold by the end of the third quarter of 2003. We have also committed to, and initiated a plan to, sell a substantial portion of our U.S. company-owned retail sites.

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 finance tax payments and crude oil, natural gas and petroleum product purchases. Our primary funding source for short-term working capital needs is a $4 billion commercial paper program, a portion of which

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may be denominated in other currencies (limited to euro 3 billion equivalent), supported by $4 billion in revolving credit facilities. Commercial paper maturities are generally kept within 90 days. At March 31, 2003, ConocoPhillips had $509 million of commercial paper outstanding, of which $151 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.

We have 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 March 31, 2003. These credit facilities support our $4 billion commercial paper program. Our Norwegian subsidiary has two $300 million revolving credit facilities that expire in June 2004, under which no borrowings were outstanding as of March 31, 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 March 31, 2003, and December 31, 2002, we had outstanding to the bank-sponsored entities $1.3 billion 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 $1.6 billion and $1.3 billion at March 31, 2003, and December 31, 2002, respectively. Our retained interests in sold receivables are reported on the balance sheet in accounts and notes receivable-related parties. See Note 14—Sales of Receivables in the Notes to Consolidated Financial Statements for additional information.

Other Financing and Off-Balance Sheet Arrangements

At March 31, 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 March 31, 2003, we also had outstanding $644 million of equity held by minority interest owners, consisting of a net minority interest of $141 million in Conoco Corporate Holdings L.P. and a $503 million net minority interest in Ashford Energy. We present the mandatorily redeemable preferred securities and minority interests in the mezzanine section of our balance sheet based on current accounting rules. We expect that the mandatorily redeemable preferred trust securities issued by the Phillips 66 Capital Trust II and the net minority interest in Conoco Corporate Holdings L.P. could be required to be reported as debt in the third quarter of 2003 in accordance with accounting rules expected to be issued by the Financial Accounting Standards Board in a Statement of Financial Accounting Standards titled “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity.” See Note 18—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 at the end of 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 would be reduced by the fair market value of the leased assets returned. These various leasing

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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 July 2003 of certain SPEs that were created prior to January 31, 2003, and that are still in existence at July 1, 2003. We are evaluating the new interpretation to determine whether the assets and debt of the leasing arrangements will be consolidated. See Note 18—New Accounting Standards in the Notes to Consolidated Financial Statements for more information. If we are required to consolidate all of these entities, the assets of the entities and debt of approximately $2.4 billion would be required to be included in the consolidated financial statements. Of the $2.4 billion debt that could be consolidated, approximately $1.5 billion is associated with the marketing sites that we plan to sell. As a result of the planned divestitures, we plan to exercise purchase option provisions during 2003 and terminate various operating leases involving approximately 900 store sites and two office buildings. Depending upon the timing of our exercise of these purchase options, and the determination of whether or not the lessor entities in these operating leases are variable interest entities requiring consolidation in 2003, some or all of these lessor entities could become consolidated subsidiaries prior to the exercise of the purchase options and termination of the leases.

Capital Requirements

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

In the first quarter 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:

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

• $181 million SRW Cogeneration Limited Partnership note; and

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

In April 2003, we paid the following notes as they were called or matured:

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

• $500 million floating rate notes due April 15, 2003.

In May 2003, we will pay our $150 million 8.25% notes due May 15, 2003, when they mature.

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Capital Expenditures and Investments

		Millions of Dollars
		Three Months Ended
		March 31
		2003		2002
E&P
	United States-Alaska	$	140		205
	United States-Lower 48		186		64
	International		686		248
			1,012		517
Midstream			2		—
R&M
	United States		150		100
	International		53		4
			203		104
Chemicals			—		10
Emerging Businesses			66		—
Corporate and Other*			26		14
		$	1,309		645
United States		$	513		393
International			796		252
		$	1,309		645
Discontinued operations		$	21		12

* Excludes discontinued operations.

E&P

We continue with construction of our double-hulled Endeavour Class tankers, which we will use in transporting Alaskan crude oil to the U.S. West Coast. We expect the third tanker, the Polar Discovery, christened on April 13, 2002, to enter service 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 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. Exploration continues using the drillship Pathfinder. In January 2003, we began construction of the Magnolia tension-leg platform starting with the hull in South Korea and the topsides for the platform in Ingleside, Texas, and we expect completion in 12 months.

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.

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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. The gas is sold to Caltex’s Duri steamflood project located in central Sumatra. 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 field, located three miles east of Peng Lai 19-3. We have completed drilling two exploratory wells in the Peng Lai 19-9 and 13-1 fields.

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 in South Korea, and to work on the multi-product floating, storage and offtake vessel. We expect to install the decks and the floating, storage and offtake vessel mid-year 2003, with first gas and commissioning commencing in the fourth quarter. We also continued with preparation of approval documentation and project design for the liquefied natural gas plant, including a pipeline to Darwin, that is associated with the Bayu-Undan gas export project. We expect to begin construction by the end of the second quarter of 2003.

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, we are constructing a wellhead platform and a floating production, storage and offloading vessel. We expect the field to begin production in the second quarter of 2004.

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 available production capacity to date is approximately 75,000 barrels per day of heavy crude oil production. We anticipate completing the construction of the upgrader in 2004.

We continued with development of the Stage III expansion mining project in the Canadian province of Alberta, which is expected to increase our Canada Syncrude production. We expect various units of the expansion project to come on stream starting in December 2003 when the new mine will be in operation.

R&M

We completed construction of a polypropylene plant at the Bayway refinery in Linden, New Jersey. The plant became operational in March 2003 and utilizes propylene feedstock from the Bayway 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. The unit commenced initial operations in March 2003, and we expect it to be fully operational in the second quarter of 2003. The unit should improve gasoline production per barrel of crude oil input.

We continue to expend funds related to clean fuels, safety and environmental projects. We continued working on refinery projects in Ponca City, Oklahoma; Roxana, Illinois; and Ferndale, Washington, to produce low-sulfur gasoline as required by the Environmental Protection Agency. We expect to complete these projects by year-end. The Ferndale refinery project includes ConocoPhillips’ S Zorb process for clean gasoline. The S Zorb process significantly reduces sulfur content in gasoline or diesel fuel to meet new government standards.

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In April 2003, we signed a memorandum of understanding to acquire certain refining assets in Hartford, Illinois. The operations of these assets will be integrated with the operations of our nearby Wood River refinery.

Emerging Businesses

We continued to spend funds in the first quarter 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.

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 injections wells; and

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• 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 the lessee’s operations and 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 ConocoPhillips operates 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 ConocoPhillips’ 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 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 ConocoPhillips’ 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 ConocoPhillips’ proprietary technology known as S Zorb. The estimated costs for implementing our strategy will be included in future budgeting for refinery compliance.

The EPA has also promulgated rules regarding sulfur content in highway diesel fuel that become applicable in 2006. In April 2003, the EPA proposed a rule regarding emissions from nonroad diesel engines and limiting nonroad diesel fuel sulfur content. If promulgated, this rule would significantly reduce nonroad diesel fuel sulfur content limits as early as 2007. ConocoPhillips is currently developing and testing an S Zorb system for removing sulfur from diesel fuel. It is anticipated that S Zorb will be used as part of ConocoPhillips’ strategy for complying with these rules. Because we are still evaluating and developing capital strategies for compliance with the rule, we cannot provide precise cost estimates at this time, but will do so and report these compliance costs as required by law.

Additional areas of potential air-related impacts to ConocoPhillips 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.

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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.

ConocoPhillips also is 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.

RCRA requires permitted facilities to undertake an assessment of environmental conditions at the facility. 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 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.

ConocoPhillips from time to time receives 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 March 31, 2003, we had not resolved any of these sites and had received two new notices of potential liability, leaving approximately 60 sites where we have been notified of potential liability.

For most Superfund sites, ConocoPhillips’ 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,

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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

ConocoPhillips accrues 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 undiscounted 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 March 31, 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.

At March 31, 2003, ConocoPhillips’ balance sheet included a total environmental accrual related to continuing operations of $737 million, compared with $743 million at December 31, 2002. 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

As a condition to the merger, the U.S. Federal Trade Commission (FTC) required the divestiture of certain assets. We sold our propane terminal assets at Jefferson City, Missouri, and East St. Louis, Illinois, and signed Purchase and Sale Agreements with various purchasers to sell 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); associated assets; and a refined products terminal in Spokane, Washington; our Commerce City, Colorado, refinery, and related crude oil pipelines; our Colorado Phillips-branded motor fuel marketing operations (both retail and wholesale); certain midstream natural gas gathering and processing assets in southeast New Mexico; and certain midstream natural gas gathering assets in West Texas. We are awaiting FTC final review and approval on certain of these sales and expect to have all of these assets sold by the end of the third quarter of 2003.

In December 2002, we committed to and initiated a plan to sell a substantial portion of our company-owned marketing sites. We are actively marketing the assets in packages with the help of an investment banking firm. We are in discussions with potential buyers, and we expect to complete the sale of the sites in 2003.

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In January 2003, the Venezuela government established temporary measures aimed at restricting the convertibility of the Venezuelan Bolivar and the transfer of funds out of the country, and closed the foreign exchange market. The Venezuelan government has begun publishing the legal instruments regulating the new foreign exchange market, one of which establishes official exchange rates for the U.S. dollar. Based on the few regulations published to date, ConocoPhillips does not believe our Venezuelan operations will be significantly impacted, but there are more regulations to come and we will not know the full impact until the system is put into place.

In March 2003, ConocoPhillips’ 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 in the fall of 2005. We also expect to modify the existing Ekofisk Complex and four additional platforms to increase our process 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, CVP (a subsidiary of PDVSA) has elected to acquire a 35 percent participating interest in the block, which will reduce our working interest to 32.5 percent. In addition, Venezuelan legislation enacted in 2001 introduced a new 30 percent flat royalty regime and reduced the income tax rate on light oil projects from 67.7 percent to 50 percent. The Corocoro Project’s Royalty Agreement, which provides for a sliding scale royalty between 1 percent and 16.67 percent, depending upon project returns, was in effect prior to the 2001 legislation and is expected to continue to apply to the project. We expect to begin development immediately with first production expected in 2005.

We expect our worldwide production for the second quarter of 2003 to follow typical seasonal declines. While these declines are expected to be partially offset by a full quarter of output from Venezuela, we anticipate slightly lower overall production when compared with the first quarter of 2003.

In R&M, we expect refinery utilization rates to average in the mid-90 percent range for the second quarter of 2003.

Crude oil and natural gas prices are subject to external factors over which ConocoPhillips has no control, such as global economic conditions, political events, demand growth, inventory levels, weather, competing fuels prices and availability of supply. Crude oil prices increased significantly during the first quarter of 2003 due to a surge in demand resulting from exceptionally cold weather and crude oil supply disruptions in Iraq, Venezuela and Nigeria. Crude oil prices also benefited from uncertainty related to events in the Middle East. Although major combat in Iraq is over, uncertainties surrounding the global economic recovery, the amount of time required to restore Iraqi production, and other conflicts in oil-producing countries are likely to keep prices volatile for the remainder of this year. U.S. natural gas prices rose considerably in the first quarter of 2003 and were nearly three times higher than they were in the first quarter of 2002. Exceptionally cold weather in the Northeast boosted natural gas demand and lowered inventories to historically low levels, while the muted increase in drilling raised concerns about supply adequacy.

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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 ConocoPhillips has 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 improved during the first quarter of 2003 from the depressed levels experienced during much of 2002 because exceptionally cold weather boosted heating oil demand causing refiners to increase heating oil production at the expense of gasoline production. Gasoline production was also reduced by heavy refinery turnarounds in the first quarter of 2003. The combination of lower domestic gasoline production and reduced gasoline imports from Venezuela due to refinery strikes resulted in low gasoline inventories and improved refinery margins. Marketing margins also improved from weak levels in 2002, although they remained below the historical average except for California, where margins increased in part due to tightened gasoline supplies resulting from the transition from MTBE to ethanol as a blendstock. The sustainability of the improvement in 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;

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• unsuccessful exploratory drilling activities;

• failure of new products and services to achieve market acceptance;

• 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 and refined products;

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

• 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 4. CONTROLS AND PROCEDURES

Within the 90 days prior to the date of this report, we carried out an evaluation, under the supervision, and with the participation of, our management, including our President and Chief Executive Officer, and our Executive Vice President, Finance, and Chief Financial Officer, of the effectiveness of ConocoPhillips’ disclosure controls and procedures pursuant to Rule 13a-14 under 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 are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Securities and Exchange Commission’s rules and forms, of information required to be disclosed by the issuer in the reports that it files or submits under the Exchange Act.

There have been no significant changes in our internal controls, or in other factors that could significantly affect internal controls, subsequent to the date of the evaluation referred to above.

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As currently proposed, we think it is likely that Section 404 of the Sarbanes-Oxley Act of 2002 will require us to include an internal controls report with our 2003 annual report on Form 10-K. The internal controls report must assert (i) management’s responsibilities to establish and maintain adequate internal controls and procedures for financial reporting and (ii) management’s conclusions as to the effectiveness of these internal controls and procedures, based on management’s evaluation of them at year end. Our auditors will be required to attest to, and report on, these assertions. In order to achieve compliance with Section 404 within the statutory period, management has formed a steering committee and adopted a detailed project work plan to assess the adequacy of our internal controls, remediate any control weaknesses that may be identified, validate through testing that controls are functioning as documented, and implement a continuous reporting and improvement process for internal controls. As a result of this initiative, we may make changes in our internal controls from time to time during the period prior to December 31, 2003.

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

There have been no material developments with respect to the legal proceedings previously reported in our 2002 Annual Report on Form 10-K.

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 6. EXHIBITS AND REPORTS ON FORM 8-K

Exhibits

12	Computation of Ratio of Earnings to Fixed Charges.
99.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Reports on Form 8-K

During the three months ended March 31, 2003, ConocoPhillips filed the following Current Reports on Form 8-K:

• Current Report filed January 9, 2003, reporting Item 5 and Item 7.

• Current Report filed January 30, 2003, reporting Item 5 and Item 7.

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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)
May 13, 2003

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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 quarterly 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 quarterly report;
3.	Based on my knowledge, the financial statements, and other financial information included in this quarterly 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 quarterly report;
4.	The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a)	designed such disclosure controls and procedures 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 quarterly report is being prepared;
b)	evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and
c)	presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 8, 2003

/s/ J. J. Mulva

J. J. Mulva
President and Chief Executive Officer

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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 quarterly 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 quarterly report;
3.	Based on my knowledge, the financial statements, and other financial information included in this quarterly 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 quarterly report;
4.	The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a)	designed such disclosure controls and procedures 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 quarterly report is being prepared;
b)	evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and
c)	presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a)	all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 8, 2003

/s/ John A. Carrig

John A. Carrig
Executive Vice President, Finance, and
Chief Financial Officer

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EXHIBIT INDEX

Exhibits

12	Computation of Ratio of Earnings to Fixed Charges.
99.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.