ConocoPhillips (COP) 10-Q 2007 Q1 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2007

or

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

For the transition period from                    to                    

Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filerþ              Accelerated filero              Non-accelerated filero

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

The registrant had 1,634,399,909 shares of common stock, $.01 par value, outstanding at March 31, 2007.

CONOCOPHILLIPS

TABLE OF CONTENTS

	Page
Part I – Financial Information
Item 1. Financial Statements
Consolidated Income Statement		1
Consolidated Balance Sheet		2
Consolidated Statement of Cash Flows		3
Notes to Consolidated Financial Statements		4
Supplementary Information—Condensed Consolidating Financial Information		26
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		33
Item 3. Quantitative and Qualitative Disclosures About Market Risk		58
Item 4. Controls and Procedures		58
Part II – Other Information
Item 1. Legal Proceedings		59
Item 1A. Risk Factors		61
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		61
Item 6. Exhibits		62
Signature		63
First and Second Amendments to the Executive Severance Plan
Computation of Ratio of Earnings to Fixed Charges
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Certifications Pursuant to Section 1350

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

Consolidated Income Statement ConocoPhillips

	Millions of Dollars
	Three Months Ended
	March 31
	2007			2006
Revenues and Other Income
Sales and other operating revenues*	$	41,320			46,906
Equity in earnings of affiliates		929			960
Other income		618			61
Total Revenues and Other Income		42,867			47,927
Costs and Expenses
Purchased crude oil, natural gas and products		26,715			33,455
Production and operating expenses		2,492			2,215
Selling, general and administrative expenses		527			566
Exploration expenses		262			112
Depreciation, depletion and amortization		2,024			1,180
Impairments		(1	)		—
Taxes other than income taxes*		4,374			4,387
Accretion on discounted liabilities		79			60
Interest and debt expense		307			115
Foreign currency transaction losses		1			22
Minority interests		21			18
Total Costs and Expenses		36,801			42,130
Income before income taxes		6,066			5,797
Provision for income taxes		2,520			2,506
Net Income	$	3,546			3,291
Net Income Per Share of Common Stock(dollars)
Basic	$	2.15			2.38
Diluted		2.12			2.34
Dividends Paid Per Share of Common Stock(dollars)	$	.41			.36
Average Common Shares Outstanding(in thousands)
Basic		1,647,352			1,382,925
Diluted		1,668,847			1,404,704
* Includes excise taxes on petroleum products sales:	$	3,841			3,990
See Notes to Consolidated Financial Statements.

1

Consolidated Balance Sheet ConocoPhillips

	Millions of Dollars
	March 31			December 31
	2007			2006
Assets
Cash and cash equivalents	$	860			817
Accounts and notes receivable (net of allowance of $43 million in 2007 and $45 million in 2006)		11,964			13,456
Accounts and notes receivable—related parties		1,936			650
Inventories		5,685			5,153
Prepaid expenses and other current assets		4,296			4,990
Total Current Assets		24,741			25,066
Investments and long-term receivables		30,415			19,595
Loans and advances—related parties		1,304			1,118
Net properties, plants and equipment		83,904			86,201
Goodwill		31,531			31,488
Intangibles		919			951
Other assets		395			362
Total Assets	$	173,209			164,781
Liabilities
Accounts payable	$	15,023			14,163
Accounts payable—related parties		1,735			471
Notes payable and long-term debt due within one year		1,707			4,043
Accrued income and other taxes		5,532			4,407
Employee benefit obligations		628			895
Other accruals		2,400			2,452
Total Current Liabilities		27,025			26,431
Long-term debt		21,961			23,091
Asset retirement obligations and accrued environmental costs		5,629			5,619
Joint venture acquisition obligation—related party		6,742			—
Deferred income taxes		20,051			20,074
Employee benefit obligations		3,567			3,667
Other liabilities and deferred credits		2,251			2,051
Total Liabilities		87,226			80,933
Minority Interests		1,201			1,202
Common Stockholders’ Equity
Common stock (2,500,000,000 shares authorized at $.01 par value) Issued (2007—1,708,876,039 shares; 2006—1,705,502,609 shares)
Par value		17			17
Capital in excess of par		42,052			41,926
Grantor trusts (at cost: 2007—44,285,475 shares; 2006—44,358,585 shares)		(762	)		(766	)
Treasury stock (at cost: 2007—30,190,655 shares; 2006—15,061,613 shares)		(1,969	)		(964	)
Accumulated other comprehensive income		1,437			1,289
Unearned employee compensation		(143	)		(148	)
Retained earnings		44,150			41,292
Total Common Stockholders’ Equity		84,782			82,646
Total	$	173,209			164,781

See Notes to Consolidated Financial Statements.

2

Consolidated Statement of Cash Flows ConocoPhillips

	Millions of Dollars
	Three Months Ended
	March 31
	2007			2006
Cash Flows From Operating Activities
Net income	$	3,546			3,291
Adjustments to reconcile net income to net cash provided by operating activities
Non-working capital adjustments
Depreciation, depletion and amortization		2,024			1,180
Impairments		(1	)		—
Dry hole costs and leasehold impairments		148			38
Accretion on discounted liabilities		79			60
Deferred taxes		77			168
Undistributed equity earnings		(557	)		(67	)
Gain on asset dispositions		(499	)		(3	)
Other		(94	)		(203	)
Working capital adjustments
Decrease in accounts and notes receivable		289			550
Increase in inventories		(686	)		(1,304	)
Decrease in prepaid expenses and other current assets		67			—
Increase in accounts payable		1,539			108
Increase in taxes and other accruals		941			982
Net Cash Provided by Operating Activities		6,873			4,800
Cash Flows From Investing Activities
Acquisition of Burlington Resources Inc.*		—			(14,190	)
Capital expenditures and investments, including dry hole costs*		(2,847	)		(4,514	)
Proceeds from asset dispositions		1,343			5
Long-term advances/loans to affiliates		(179	)		(126	)
Collection of advances/loans to affiliates		28			11
Other		7			—
Net Cash Used in Investing Activities		(1,648	)		(18,814	)
Cash Flows From Financing Activities
Issuance of debt		81			15,340
Repayment of debt		(3,572	)		(16	)
Issuance of company common stock		40			40
Repurchase of company common stock		(1,000	)		—
Dividends paid on company common stock		(674	)		(496	)
Other		(49	)		(27	)
Net Cash Provided by (Used in) Financing Activities		(5,174	)		14,841
Effect of Exchange Rate Changes on Cash and Cash Equivalents		(8	)		(33	)
Net Change in Cash and Cash Equivalents		43			794
Cash and cash equivalents at beginning of period		817			2,214
Cash and Cash Equivalents at End of Period	$	860			3,008

*Net of cash acquired.

See Notes to Consolidated Financial Statements.

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Notes to Consolidated Financial Statements ConocoPhillips

Note 1—Interim Financial Information

The interim-period financial information presented in the financial statements included in this report is unaudited and includes all known accruals and adjustments, in the opinion of management, necessary for a fair presentation of the consolidated financial position of ConocoPhillips and its results of operations and cash flows for such periods. All such adjustments are of a normal and recurring nature. The acquisition of Burlington Resources Inc. was reflected in our balance sheet beginning at March 31, 2006, and was reflected in our results of operations beginning April 1, 2006.

To enhance your understanding of these interim financial statements, see the consolidated financial statements and notes included in our 2006 Annual Report on Form 10-K.

Note 2—Accounting Policies

Revenue Recognition

Effective April 1, 2006, we implemented Emerging Issues Task Force Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” Issue No. 04-13 requires purchases and sales of inventory with the same counterparty and entered into “in contemplation” of one another to be combined and reported net (i.e., on the same income statement line). Exceptions to this are exchanges of finished goods for raw materials or work-in-progress within the same line of business, which are only reported net if the transaction lacks economic substance. The implementation of Issue No. 04-13 did not have a material impact on net income.

The table below shows the actual three months ended March 31, 2007, sales and other operating revenues, and purchased crude oil, natural gas and products under Issue No. 04-13, and the respective pro forma amounts had this new guidance been effective for the period included in this report prior to April 1, 2006.

	Millions of Dollars
	Three Months Ended
	March 31
	Actual		Pro Forma
	2007		2006
Sales and other operating revenues	$	41,320		40,249
Purchased crude oil, natural gas and products		26,715		26,798

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Note 3—Changes in Accounting Principles

In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). This Interpretation provides guidance on recognition, classification and disclosure concerning uncertain tax liabilities. The evaluation of a tax position requires recognition of a tax benefit if it is more likely than not it will be sustained upon examination. We adopted this Interpretation effective January 1, 2007. The adoption did not have a material impact on our consolidated financial statements.

At January 1, 2007, we had unrecognized tax benefits of $912 million. Included in this balance was $537 million which, if recognized, would affect our effective tax rate.

We and our subsidiaries file tax returns in the U.S. Federal jurisdiction and in many foreign and state jurisdictions. Audits in major jurisdictions, including the United States, Canada, Norway and the United Kingdom, are generally complete through 2001. Issues in dispute from audited years and audits for subsequent years are ongoing and in various stages of completion in the many jurisdictions in which we operate around the world.

We recognize accrued interest related to unrecognized tax benefits in interest expense, and penalties in operating expense. Accrued liabilities for interest and penalties as of January 1, 2007, totaled $99 million, net of accrued income taxes.

Note 4—Acquisition of Burlington Resources Inc.

On March 31, 2006, ConocoPhillips completed the $33.9 billion acquisition of Burlington Resources Inc., an independent exploration and production company that held a substantial position in North American natural gas proved reserves, production and exploratory acreage.

The final allocation of the purchase price to specific assets and liabilities was completed in the first quarter of 2007. It was based on the final outside appraisal of the fair value of Burlington Resources long-lived assets and the conclusion of the fair value determination of all other Burlington Resources assets and liabilities.

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The following table summarizes the final purchase price allocation of the fair value of the assets acquired and liabilities assumed as of March 31, 2006:

	Millions
	of Dollars
Cash and cash equivalents	$	3,238
Accounts and notes receivable		1,476
Inventories		229
Prepaid expenses and other current assets		108
Investments and long-term receivables		268
Properties, plants and equipment		28,176
Goodwill		16,789
Intangibles		107
Other assets		46
Total Assets	$	50,437
Accounts payable	$	1,487
Notes payable and long-term debt due within one year		1,009
Accrued income and other taxes		762
Employee benefit obligations—current		248
Other accruals		254
Long-term debt		3,330
Asset retirement obligations		730
Accrued environmental costs		174
Deferred income taxes		7,835
Employee benefit obligations		347
Other liabilities and deferred credits		397
Common stockholders’ equity		33,864
Total Liabilities and Equity	$	50,437

All of the goodwill was assigned to the Worldwide Exploration and Production reporting unit. Of the $16,789 million of goodwill, $7,939 million relates to net deferred tax liabilities arising from differences between the allocated financial bases and deductible tax bases of the acquired assets. None of the goodwill is deductible for tax purposes.

The following table presents pro forma information for the three months ended March 31, 2006, as if the acquisition had occurred at the beginning of 2006.

	Millions
	of Dollars
Pro Forma
Sales and other operating revenues	$	48,811
Net income		3,746
Net income per share of common stock(dollars)
Basic		2.27
Diluted		2.23

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The pro forma information is not intended to reflect the actual results that would have occurred if the companies had been combined during the period presented, nor is it intended to be indicative of the results of operations that may be achieved by ConocoPhillips in the future.

Note 5—Restructuring

In connection with the acquisition of Burlington Resources, we implemented a restructuring program as part of the effort to capture the synergies of combining the two companies. Under this program, we recorded accruals totaling $230 million in 2006 for employee severance payments, site closings, incremental pension benefit costs associated with workforce reductions, and employee relocations. Approximately 600 positions were identified for elimination, most of which were in the United States.

Of the total accrual, $224 million was reflected in the Burlington Resources purchase price allocation as an assumed liability, and $6 million related to ConocoPhillips was reflected in selling, general and administrative expenses in 2006. The following table summarizes activity related to the non-pension portion of the accrual in the first quarter of 2007:

	Millions
	of Dollars
Balance at December 31, 2006	$	120
Benefit payments		(26	)
Adjustments		10
Balance at March 31, 2007*	$	104

*Includes current liabilities of $64 million. All workforce reductions are expected to be completed by March 2008. Some costs for site closings, continuation of employee benefits, and employee relocations are expected to extend beyond one year.

Note 6—Variable Interest Entities (VIEs)

In June 2005, ConocoPhillips and OAO LUKOIL (LUKOIL) created the OOO Naryanmarneftegaz (NMNG) joint venture to develop resources in the Timan-Pechora province of Russia. The NMNG joint venture is a VIE, but we are not the primary beneficiary. We use the equity method of accounting for this investment. At March 31, 2007, the book value of our investment in the venture was $1,111 million.

In 1997, Phillips 66 Capital II (Trust II) was created for the sole purpose of issuing mandatorily redeemable preferred securities to third-party investors and investing the proceeds thereof in an approximate amount of subordinated debt securities of ConocoPhillips. At December 31, 2006, we reported debt of $361 million of 8% Junior Subordinated Deferrable Interest Debentures due 2037. Trust II is a VIE, but we do not consolidate it in our financial statements because we are not the primary beneficiary. Effective January 15, 2007, we redeemed the 8% Junior Subordinated Deferrable Interest Debentures due 2037 at a premium of $14 million, plus accrued interest. Upon redemption of the Debentures, Trust II was liquidated. See Note 12—Debt, for additional information about Trust II.

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Note 7—Inventories

Inventories consisted of the following:

	Millions of Dollars
	March 31		December 31
	2007		2006
Crude oil and petroleum products	$	4,921		4,351
Materials, supplies and other		764		802
	$	5,685		5,153

Inventories valued on the last-in, first-out (LIFO) basis totaled $4,684 million and $4,043 million at March 31, 2007, and December 31, 2006, respectively. The remainder of our inventories is valued under various methods, including first-in, first-out and weighted average. The excess of current replacement cost over LIFO cost of inventories amounted to $4,495 million and $4,178 million at March 31, 2007, and December 31, 2006, respectively.

Note 8—Assets Held for Sale

In 2006, we commenced asset rationalization efforts that led to the classification of certain assets as “held for sale” under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Accordingly, at December 31, 2006, we reclassified $3,051 million of non-current assets and $604 million of non-current liabilities into current assets and current liabilities, respectively.

During the first quarter of 2007, a portion of these held-for-sale assets were sold, and additional assets met the held-for-sale criteria. As a result, at March 31, 2007, we had classified $2,358 million of non-current assets as “Prepaid expenses and other current assets” on our consolidated balance sheet and we had classified $287 million of non-current liabilities as current liabilities, consisting of $102 million in “Accrued income and other taxes” and $185 million in “Other accruals.”

8

The major classes of non-current assets and non-current liabilities held for sale at March 31, 2007, reclassified to current were:

	Millions
	of Dollars
Assets
Investments and long-term receivables	$	156
Net properties, plants and equipment		1,806
Goodwill		255
Intangibles		13
Other assets		128
Total assets reclassified	$	2,358
Exploration and Production (E&P)	$	451
Refining and Marketing (R&M)		1,907
	$	2,358
Liabilities
Asset retirement obligations and accrued environmental costs	$	168
Deferred income taxes		102
Other liabilities and deferred credits		17
Total liabilities reclassified	$	287
E&P	$	103
R&M		184
	$	287

Note 9—Investments and Long-Term Receivables

EnCana Business Ventures

In October 2006, we announced a business venture with EnCana Corporation (EnCana) to create an integrated North American heavy-oil business. The transaction closed on January 3, 2007. The venture consists of two 50/50 operating business ventures, a Canadian upstream general partnership, FCCL Oil Sands Partnership (FCCL), and a U.S. downstream limited liability company, WRB Refining LLC (WRB). We use the equity method of accounting for both business ventures, with the operating results of our investment in FCCL reflecting its use of the full-cost method of accounting for oil and gas exploration and development activities.

FCCL’s operating assets consist of the Foster Creek and Christina Lake steam-assisted gravity drainage bitumen projects, both located in the eastern flank of the Athabasca oil sands in northeast Alberta. EnCana is the operator and managing partner of FCCL. We are obligated to contribute $7.5 billion, plus accrued interest, to FCCL over a 10-year period beginning in 2007. For additional information on this obligation, see Note 18—Joint Venture Acquisition Obligation.

WRB’s operating assets consist of the Wood River and Borger refineries, located in Roxana, Illinois, and Borger, Texas, respectively. As a result of our contribution of these two assets to the business venture, we recognized a basis difference of $5.0 billion based on the fair value of the contributed assets compared to their historic book value. The difference will be amortized and recognized as a benefit evenly over a period of 25 years starting from the closing date. This business venture plans to expand heavy-oil processing capacity at these facilities from 60,000 barrels per day to approximately 550,000 barrels per day by 2015. Total crude oil throughput at these two facilities is expected to increase from the current

9

452,000 barrels per day to approximately 600,000 barrels per day over the same time period. We are the operator and managing partner of WRB. EnCana is obligated to contribute $7.5 billion, plus accrued interest, to WRB over a 10-year period beginning in 2007. For the Wood River refinery, operating results are shared 50/50 starting upon formation. For the Borger refinery, we are entitled to 85 percent of the operating results in 2007, 65 percent in 2008, and 50 percent in all years thereafter.

LUKOIL

Our ownership interest in LUKOIL was 20 percent at March 31, 2007, based on 851 million shares authorized and issued. For financial reporting under U.S. generally accepted accounting principles, treasury shares held by LUKOIL are not considered outstanding for determining our equity-method ownership interest in LUKOIL. Our ownership interest, based on estimated shares outstanding, was 20.6 percent at March 31, 2007.

At March 31, 2007, the book value of our ordinary share investment in LUKOIL was $9,832 million. Our share of the net assets of LUKOIL was estimated to be $7,114 million. This basis difference of $2,718 million is primarily being amortized on a unit-of-production basis. On March 31, 2007, the closing price of LUKOIL shares on the London Stock Exchange was $86.50 per share, making the total market value of our LUKOIL investment $14,715 million.

Loans to Related Parties

As part of our normal ongoing business operations and consistent with industry practice, we invest and enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. Included in such activity are loans made to certain affiliated companies. Significant loans to affiliated companies at March 31, 2007, included the following:

• $560 million in loan financing, including accrued interest, to Freeport LNG for the construction of an LNG facility. We expect to provide loan financing of approximately $630 million for the construction of the facility.

• $234 million in loan financing, including accrued interest, to Varandey Terminal Company associated with the costs of a terminal expansion. We expect our total obligation for the terminal expansion to be approximately $465 million at current exchange rates, including interest to be accrued during construction.

• $473 million of project financing, including accrued interest, to Qatargas 3, an integrated project to produce and liquefy natural gas from Qatar’s North field. Our maximum exposure to this financing structure is $1.2 billion.

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Note 10—Properties, Plants and Equipment

The company’s investment in properties, plants and equipment (PP&E), with accumulated depreciation, depletion and amortization (Accum. DD&A), was:

	Millions of Dollars
	March 31, 2007						December 31, 2006
	Gross		Accum.		Net		Gross		Accum.		Net
	PP&E		DD&A		PP&E		PP&E		DD&A		PP&E
E&P	$	90,626		22,915		67,711		88,592		21,102		67,490
Midstream		330		160		170		330		157		173
R&M		18,487		4,047		14,440		22,115		5,199		16,916
LUKOIL Investment		—		—		—		—		—		—
Chemicals		—		—		—		—		—		—
Emerging Businesses		1,035		107		928		1,006		98		908
Corporate and Other		1,276		621		655		1,229		515		714
	$	111,754		27,850		83,904		113,272		27,071		86,201

Suspended Wells

The following table reflects the net changes in suspended exploratory well costs during the first three months of 2007:

	Millions of Dollars
	Three Months Ended
	March 31, 2007
Beginning balance at January 1	$	537
Additions pending the determination of proved reserves		40
Reclassifications to proved properties		(13	)
Charged to dry hole expense		—
Ending balance at March 31	$	564

The following table provides an aging of suspended well balances at March 31, 2007, and December 31, 2006:

	Millions of Dollars
	March 31		December 31
	2007		2006
Exploratory well costs capitalized for a period of one year or less	$	207		225
Exploratory well costs capitalized for a period greater than one year		357		312
Ending balance	$	564		537
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		28		22

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The following table provides a further aging of those exploratory well costs that have been capitalized for more than one year after drilling is completed, as of March 31, 2007:

	Millions of Dollars
			Suspended Since
Project	Total		2006		2005		2004		2003		2002		2001
Alpine satellite—Alaska(2)	$	21		—		—		—		—		21		—
Kashagan—Kazakhstan(1)		18		—		—		—		9		—		9
Aktote—Kazakhstan(2)		19		—		—		7		12		—		—
Kairan—Kazakhstan(1)		13		—		—		13		—		—		—
Gumusut—Malaysia(2)		30		—		6		11		13		—		—
Malikai—Malaysia(2)		29		—		19		10		—		—		—
Plataforma Deltana—Venezuela(2)		21		—		6		15		—		—		—
Hejre—Denmark(3)		22		—		14		—		—		—		8
Uge—Nigeria(1)		16		—		16		—		—		—		—
Su Tu Trang—Vietnam(2)		22		7		7		—		8		—		—
Caldita—Australia(1)		33		—		33		—		—		—		—
Enochdhu/Finlaggen—UK(1)		11		11		—		—		—		—		—
Humphrey—UK(2)		12		12		—		—		—		—		—
Fifteen projects of less than $10 million each(1)(2)		90		26		40		4		11		9		—
Total of 28 projects	$	357		56		141		60		53		30		17

(1)	Additional appraisal wells planned.
(2)	Appraisal drilling complete; costs being incurred to assess development.
(3)	This amount is included in assets held for sale.

Note 11—Impairments

During the first quarter of 2007, we recognized the following net impairments:

	Millions of Dollars
	Three Months Ended
	March 31
	2007			2006
Asset write-downs
E&P—International	$	94			—
R&M—United States		33			—
Increase in fair value of previously impaired assets—R&M		(128	)		—
	$	(1	)		—

In the first quarter of 2007, we recorded PP&E impairments of $94 million associated with planned asset dispositions in the E&P segment, reflecting write-downs of assets to fair value less cost to sell.

In the R&M segment, we also recorded impairments of PP&E of $33 million associated with planned asset dispositions in the first quarter of 2007. In addition and in accordance with SFAS No. 144, “Accounting

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for the Impairment or Disposal of Long-Lived Assets,” we recognized a $128 million gain for a subsequent increase in the fair value of certain assets impaired in the prior year to reflect finalized sales agreements. This gain was netted with write-downs into the “Impairments” line of the consolidated income statement.

Note 12—Debt

At March 31, 2007, we had two revolving credit facilities totaling $5 billion that expire in October 2011. Also, we had a $2.5 billion revolving credit facility that originally expired in April 2011. The term of this facility has recently been extended to expire April 2012 at a reduced commitment level of $2.3 billion during the one-year extension period. These facilities may be used as direct bank borrowings, as support for the ConocoPhillips $7.5 billion commercial paper program, as support for the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, or as support for issuances of letters of credit totaling up to $750 million. The facilities are broadly syndicated among financial institutions and do not contain any material adverse change provisions or covenants requiring maintenance of specified financial ratios or ratings. The credit facilities contain a cross-default provision relating to our, or any of our consolidated subsidiaries’, failure to pay principal or interest on other debt obligations of $200 million or more. At March 31, 2007 and December 31, 2006, we had no outstanding borrowings under these credit facilities, but $41 million in letters of credit had been issued at both dates. Under both commercial paper programs there was $1,006 million of commercial paper outstanding at March 31, 2007, compared with $2,931 million at December 31, 2006.

At March 31, 2007, we had classified approximately $400 million of short-term debt as long-term debt, based on our ability and intent to refinance the obligation on a long-term basis under our revolving credit facilities.

At December 31, 2006, Phillips 66 Capital II (Trust II) had outstanding $350 million of 8% Capital Securities (Capital Securities). The sole asset of Trust II was $361 million of the company’s 8% Junior Subordinated Deferrable Interest Debentures due 2037 (Subordinated Debt Securities II). Effective January 15, 2007, we redeemed the Subordinated Debt Securities II at a premium of $14 million, plus accrued interest, resulting in the immediate redemption of the Capital Securities.

Also, in January 2007, we redeemed our $153 million 7.25% Notes due 2007 upon their maturity, and in February 2007, we reduced our Floating Rate Five-Year Term Note due 2011 from $5 billion to $4 billion.

In April 2007, we redeemed our $1 billion Floating Rate Notes due 2007 upon their maturity through the issuance of commercial paper.

Note 13—Contingencies and Commitments

In the case of all known non-income-tax-related contingencies, we accrue a liability when the loss is probable and the amount is reasonably estimable. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48), effective January 1, 2007. FIN 48 requires a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain. See Note 3—Changes in Accounting Principles, for additional information.

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Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates that are particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.

Environmental

We are subject to federal, state and local environmental laws and regulations. These may result in obligations to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various sites. When we prepare our financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into consideration the likely effects of societal and economic factors. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities and we accrue them in the period that they are both probable and reasonably estimable.

Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all of the cleanup costs related to any site at which we have been designated as a potentially responsible party. If we were solely responsible, the costs, in some cases, could be material to our, or one of our segments’, results of operations, capital resources or liquidity. However, settlements and costs incurred in matters that previously have been resolved have not been material to our results of operations or financial condition. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability and adjust our accruals accordingly.

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

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except for those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable that future costs will be incurred and these costs can be reasonably estimated. At March 31, 2007, our balance sheet included a total environmental accrual of $1,000 million, compared with

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$1,062 million at December 31, 2006. We expect to incur the majority of these expenditures within the next 30 years. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings.

Legal Proceedings

Our legal department applies its knowledge, experience, and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases which have been scheduled for trial, as well as the pace of settlement discussions in individual matters. Based on our professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal department believes there is only a remote likelihood that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our financial statements.

Other Contingencies

We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at March 31, 2007, we had performance obligations secured by letters of credit totaling $1,042 million (of which $41 million was issued under the provisions of our revolving credit facilities, and the remainder was issued as direct bank letters of credit) and various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.

Venezuela

On January 31, 2007, Venezuela’s National Assembly passed a law allowing the president of Venezuela to pass laws on certain matters by decree. On February 26, 2007, the president of Venezuela issued a decree (the Nationalization Decree) mandating a number of unilateral changes to the present contractual structures related to heavy-oil ventures and oil production risk contracts, including the following:

• The national oil company of Venezuela, Petróleos de Venezuela, S.A. (PDVSA) would be required to assume operational control of all assets subject to the decree effective May 1, 2007.

• All of the rights currently vested in the Orinoco Oil Belt heavy-oil Associations and oil production risk contract joint ventures, including the ones in which we currently participate, would be terminated and those rights vested in a number of Venezuelan-controlledEmpresa Mixtalegal entities.

• PDVSA would be required to hold a minimum 60 percent ownership interest in all of the newly formedEmpresa Mixtalegal entities.

• PDVSA would assume complete ownership of the heavy-oil projects and production risk contracts if agreements regarding the terms and conditions for reduced ownership interests under theEmpresa Mixtaentity structure are not reached by June 26, 2007.

The Nationalization Decree directly impacts our interests in each of the Petrozuata and Hamaca heavy-oil projects and the Corocoro oil production risk contract currently under development. Pursuant to the Nationalization Decree, PDVSA has assumed operational control of these three projects effective May 1, 2007, and ConocoPhillips cooperated with PDVSA, as required by the decree, to facilitate a safe and orderly transition of operations.

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In the event we are able to reach agreement with respect to the takeover of these projects by theEmpresa Mixtalegal entities and assuming PDVSA takes a 60 percent interest under the terms of the Nationalization Decree and our ownership interest is reduced pro rata, our ownership interests in Petrozuata, Hamaca and Corocoro would decrease from 50.1 percent, 40.0 percent and 32.2 percent to 40.0 percent, 22.9 percent and 19.8 percent, respectively. If we are unable to reach an agreement, our ownership interests could be eliminated, potentially without any immediate compensation.

As a result, the ultimate impact of the Nationalization Decree, if fully implemented, on our results of operations and financial position is not determinable at this time, but could result in future reductions to our anticipated operating results, production volumes, and proved reserves and could lead to a material asset impairment charge. However, due to the indeterminable status of the outcome of negotiations presently under way, management has not concluded such an impairment of our investment and associated goodwill exists under U.S. generally accepted accounting principles. ConocoPhillips continues to preserve all of its rights under contracts, investment treaties, and international law and will continue to evaluate its options in realizing the value of its investments and operations in Venezuela.

The historical cost-based carrying value of our total investment in Venezuela was approximately $2.6 billion at March 31, 2007. Also, any sale or expropriation of our interests would be viewed as a partial disposition of our Worldwide Exploration and Production reporting unit and, under the guidance in SFAS No. 142, “Goodwill and Other Intangible Assets,” would require an allocation of goodwill to the sale or expropriation event. In the event of a sale or expropriation of our entire interest in Venezuela, we estimate approximately $1.9 billion of goodwill would be allocated to such an event. If only a partial sale or expropriation occurs, the amount of allocated goodwill would be proportionally reduced.

We believe the fair market value of our Venezuelan operations substantially exceeds the historical cost-based carrying value plus goodwill allocable to those operations. However, if compensation for our interests in Venezuela is less than the applicable carrying value plus allocable goodwill, we would record an impairment equal to the difference. Similarly, if we are unable to reach agreement in negotiations, we could record an impairment prior to pursuing our other rights, if the amount and collectibility of any future compensation is not certain.

At December 31, 2006, we had recorded 1,088 million barrels of oil equivalent of proved reserves related to Petrozuata and Hamaca, and first-quarter 2007 production from these two joint ventures, after application of disproportionate OPEC reductions imposed by the Venezuelan government, averaged 82,000 net barrels per day of crude oil. First-quarter 2007 net income attributable to our Venezuelan operations was $27 million.

Note 14—Guarantees

At March 31, 2007, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial.

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Construction Completion Guarantees

• In June 2006, we issued a guarantee for 24 percent of the $2 billion in credit facilities of Rockies Express Pipeline LLC (Rockies Express), which will be used to construct a natural gas pipeline across a portion of the United States. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $480 million, which could become payable if the credit facility is fully utilized and Rockies Express fails to meet its obligations under the credit agreement. It is anticipated that construction completion will be achieved mid-2009, and refinancing will take place at that time, making the debt non-recourse. At March 31, 2007, the carrying value of the guarantee to third-party lenders was $11 million.

• In December 2005, we issued a construction completion guarantee for 30 percent of the $4.0 billion in loan facilities of Qatargas 3, which will be used to construct an LNG train in Qatar. Of the $4.0 billion in loan facilities, ConocoPhillips has committed to provide $1.2 billion. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $850 million, which could become payable if the full debt financing is utilized and completion of the Qatargas 3 project is not achieved. The project financing will be non-recourse upon certified completion, which is expected by December 31, 2009. At March 31, 2007, the carrying value of the guarantee to the third-party lenders was $11 million. For additional information, see Note 9—Investments, Loans and Long-Term Receivables.

Guarantees of Joint-Venture Debt

• At March 31, 2007, we had guarantees outstanding for our portion of joint-venture debt obligations, which have terms of up to 17 years. The maximum potential amount of future payments under the guarantees is approximately $140 million. Payment would be required if a joint venture defaults on its debt obligations.

Other Guarantees

• The Merey Sweeny, L.P. (MSLP) joint-venture project agreement requires the partners in the venture to pay cash calls to cover operating expenses in the event the venture does not have enough cash to cover operating expenses after setting aside the amount required for debt service over the next 18 years. Although there is no maximum limit stated in the agreement, the intent is to cover short-term cash deficiencies should they occur. Our maximum potential future payments under the agreement are currently estimated to be $100 million, assuming such a shortfall exists at some point in the future due to an extended operational disruption.

• In February 2003, we entered into two agreements establishing separate guarantee facilities of $50 million each for two LNG ships. Subject to the terms of each such facility, we will be required to make payments should the charter revenue generated by the respective ship fall below certain specified minimum thresholds, and we will receive payments to the extent that such revenues exceed those thresholds. The net maximum future payments that we may have to make over the 20-year terms of the two agreements could be up to $100 million in total. To the extent we receive any such payments, our actual gross payments over the 20 years could exceed that amount. In the event either ship is sold or a total loss occurs, we also may have recourse to the sales or insurance proceeds to recoup payments made under the guarantee facilities.

• We have guarantees of the residual value of leased corporate aircraft. The maximum potential payment under these guarantees at March 31, 2007, was $200 million.

• We have other guarantees with maximum future potential payment amounts totaling $270 million, which consist primarily of dealer and jobber loan guarantees to support our marketing business, a guarantee to fund the short-term cash liquidity deficits of a lubricants joint venture, three small construction completion guarantees, a guarantee associated with a pending lawsuit, guarantees relating to the startup of a refining joint venture, and guarantees of the lease payment obligations of a

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joint venture. The carrying amount recorded for these other guarantees, at March 31, 2007, was $50 million. These guarantees generally extend up to 15 years and payment would be required only if the dealer, jobber or lessee goes into default, if the lubricants or refining joint ventures have cash liquidity issues, if construction projects are not completed, if guaranteed parties default on lease payments, or if an adverse decision occurs in the pending lawsuit.

Indemnifications

Over the years, we have entered into various agreements to sell ownership interests in certain corporations and joint ventures and have sold several assets, including downstream and midstream assets, certain exploration and production assets, and downstream retail and wholesale sites that gave rise to qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, environmental liabilities, permits and licenses, employee claims, real estate indemnity against tenant defaults, and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications at March 31, 2007, was $459 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the carrying amount recorded were $285 million of environmental accruals for known contamination that is included in asset retirement obligations and accrued environmental costs at March 31, 2007. For additional information about environmental liabilities, see Note 13—Contingencies and Commitments.

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Note 15—Financial Instruments and Derivative Contracts

Derivative assets and liabilities were:

	Millions of Dollars
	March 31		December 31
	2007		2006
Derivative Assets
Current	$	729		924
Long-term		97		82
	$	826		1,006
Derivative Liabilities
Current	$	662		681
Long-term		93		126
	$	755		807

These derivative assets and liabilities appear as prepaid expenses and other current assets, other assets, other accruals, or other liabilities and deferred credits on the balance sheet.

Note 16—Comprehensive Income

ConocoPhillips’ comprehensive income was as follows:

	Millions of Dollars
	Three Months Ended
	March 31
	2007			2006
Net income	$	3,546			3,291
After-tax changes in:
Defined benefit pension plans
Net prior service cost		5			—
Net actuarial loss		16			—
Non-sponsored plans		(3	)		—
Foreign currency translation adjustments		131			171
Hedging activities		(1	)		1
Comprehensive income	$	3,694			3,463

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

	Millions of Dollars
	March 31 2007			December 31 2006
Defined benefit pension plans	$	(647	)		(665	)
Foreign currency translation adjustments		2,089			1,958
Deferred net hedging loss		(5	)		(4	)
Accumulated other comprehensive income	$	1,437			1,289

Note 17—Supplemental Cash Flow Information

	Millions of Dollars
	Three Months Ended
	March 31
	2007		2006
Non-Cash Investing and Financing Activities
Issuance of stock and options for the acquisition of Burlington Resources Inc.	$	—		16,386
Investment in an upstream business venture through issuance of an acquisition obligation		7,313		—
Investment in a downstream business venture through contribution of non-cash assets and liabilities		2,415		—
Cash Payments
Interest	$	115		12
Income taxes		1,199		1,393

Note 18—Joint Venture Acquisition Obligation

On January 3, 2007, we closed on the previously announced business venture with EnCana Corporation. As part of this transaction, we expect to add approximately 400 million barrels of oil equivalent to our proved reserves in 2007. In addition, we are obligated to contribute $7.5 billion, plus accrued interest, over a 10-year period, beginning in 2007, to the upstream business venture, FCCL Oil Sands Partnership, formed as a result of the transaction. An initial cash contribution of $188 million was made upon closing in January.

The remaining $7.3 billion acquisition obligation is reflected as a liability on our March 31, 2007, consolidated balance sheet. Of this principal obligation amount, approximately $570 million is short-term and is included in the “Accounts payable—related parties” line on our consolidated balance sheet. Principal and interest payments of $237 million will be made each quarter, beginning in the second quarter of 2007, and continuing until the balance is paid. In early April 2007, we made the principal and interest payment for the second quarter, reducing the remaining principal obligation to approximately $7.2 billion. The principal portion of these payments will be presented on our consolidated statement of cash flows as a financing activity. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance.

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Note 19—Employee Benefit Plans

Pension and Postretirement Plans

	Millions of Dollars
	Pension Benefits												Other Benefits
Three Months Ended	March 31												March 31
	2007						2006						2007			2006
	U.S.			Int’l.			U.S.			Int’l.
Components of Net Periodic Benefit Cost
Service cost	$	44			24			42			21			3			4
Interest cost		57			38			50			31			11			11
Expected return on plan assets		(51	)		(35	)		(40	)		(29	)		—			—
Amortization of prior service cost		3			2			2			2			3			5
Recognized net actuarial loss (gain)		15			11			22			10			(4	)		(4	)
Net periodic benefit costs	$	68			40			76			35			13			16

During the first three months of 2007, we contributed $109 million to our domestic qualified and non-qualified plans and $51 million to our international benefit plans. We currently expect to contribute $430 million to our domestic plans and $180 million to our international plans in 2007.

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Note 20—Related Party Transactions

Significant transactions with related parties were:

	Millions of Dollars
	Three Months Ended
	March 31
	2007		2006
Operating revenues (a)	$	2,618		1,784
Purchases (b)		3,210		1,518
Operating expenses and selling, general and administrative expenses (c)		108		79
Net interest expense (d)		30		5

(a)	We sell natural gas to DCP Midstream and crude oil to the Malaysian Refining Company Sdn. Bhd (MRC), among others, for processing and marketing. Natural gas liquids, solvents and petrochemical feedstocks are sold to Chevron Phillips Chemical Company LLC (CPChem), gas oil and hydrogen feedstocks are sold to Excel Paralubes, and refined products are sold primarily to CFJ Properties and Getty Petroleum Marketing, Inc. (a subsidiary of LUKOIL). We also sell blendstock and other intermediate products to WRB Refining LLC, as well as natural gas and crude oil. In addition, we charge several of our affiliates, including CPChem, Merey Sweeny L.P. (MSLP), and Hamaca Holding LLC, for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.
(b)	We purchase refined products from WRB Refining. We purchase natural gas and natural gas liquids from DCP Midstream and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchase upgraded crude oil from Petrozuata C.A. and refined products from MRC. We also pay fees to various pipeline equity companies for transporting finished refined products and a price upgrade to MSLP for heavy crude processing. We purchase base oils and fuel products from Excel Paralubes for use in our refinery and specialty businesses.
(c)	We pay processing fees to various affiliates. Additionally, we pay crude oil transportation fees to pipeline equity companies.
(d)	We pay and/or receive interest to/from various affiliates, including FCCL Oil Sands Partnership.

Elimination amounts related to our equity percentage share of profit or loss on the above transactions were not material.

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Note 21—Segment Disclosures and Related Information

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

1)	E&P—This segment primarily explores for, produces and markets crude oil, natural gas and natural gas liquids on a worldwide basis. At March 31, 2007, our E&P operations were producing in the United States, Norway, the United Kingdom, the Netherlands, Canada, Nigeria, Venezuela, Ecuador, Argentina, offshore Timor Leste in the Timor Sea, Australia, China, Indonesia, Algeria, Libya, the United Arab Emirates, Vietnam, and Russia. The E&P segment’s U.S. and international operations are disclosed separately for reporting purposes.
2)	Midstream—This segment gathers, processes and markets natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in the United States and Trinidad. The Midstream segment primarily consists of our 50 percent equity investment in DCP Midstream.
3)	R&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. At March 31, 2007, we owned or had an interest in 12 refineries in the United States, one in the United Kingdom, one in Ireland, one in Germany, and had equity interests in one refinery in Germany, two in the Czech Republic, and one in Malaysia. The R&M segment’s U.S. and international operations are disclosed separately for reporting purposes.
4)	LUKOIL Investment—This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia. At March 31, 2007, our ownership interest was 20 percent, based on authorized and issued shares, and 20.6 percent, based on estimated shares outstanding.
5)	Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in CPChem.
6)	Emerging Businesses—The Emerging Businesses segment represents our investment in new technologies or businesses outside our normal scope of operations. Activities within this segment are currently focused on power generation; carbon-to-liquids; technology solutions, such as sulfur removal technologies; and alternative energy and programs, such as advanced hydrocarbon processes, energy conversion technologies, new petroleum-based products, and renewable fuels.

Corporate and Other includes general corporate overhead, interest income and expense, restructuring charges, and various other corporate activities. Corporate assets include all cash and cash equivalents.

We evaluate performance and allocate resources based on net income. Intersegment sales are at prices that approximate market.

See Note 2—Accounting Policies, for information affecting the comparability of sales and other operating revenues presented in the following tables of our segment disclosures.

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Analysis of Results by Operating Segment

	Millions of Dollars
	Three Months Ended
	March 31
	2007			2006
Sales and Other Operating Revenues
E&P
United States	$	8,272			9,319
International		6,013			7,444
Intersegment eliminations—U.S.		(1,156	)		(1,205	)
Intersegment eliminations—international		(1,441	)		(1,254	)
E&P		11,688			14,304
Midstream
Total sales		1,105			1,021
Intersegment eliminations		(59	)		(284	)
Midstream		1,046			737
R&M
United States		20,039			23,541
International		8,635			8,356
Intersegment eliminations—U.S.		(144	)		(200	)
Intersegment eliminations—international		(2	)		(4	)
R&M		28,528			31,693
LUKOIL Investment		—			—
Chemicals		3			3
Emerging Businesses
Total sales		169			181
Intersegment eliminations		(114	)		(124	)
Emerging Businesses		55			57
Corporate and Other		—			—
Other adjustments*		—			112
Consolidated sales and other operating revenues	$	41,320			46,906

*Sales and other operating revenues for 2006 in the Emerging Businesses segment have been restated to reflect intersegment eliminations on sales from the Immingham power plant (Emerging Businesses segment) to the Humber refinery (R&M segment). Since these amounts were not material to the consolidated income statement, the “Other adjustments” line above is required to reconcile the restated Emerging Businesses revenues to the consolidated income statement.

Net Income (Loss)
E&P
United States	$	916		1,181
International		1,413		1,372
Total E&P		2,329		2,553
Midstream		85		110
R&M
United States		896		297
International		240		93
Total R&M		1,136		390
LUKOIL Investment		256		249
Chemicals		82		149
Emerging Businesses		(1	)	8
Corporate and Other		(341	)	(168	)
Consolidated net income	$	3,546		3,291

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	Millions of Dollars
	March 31		December 31
	2007		2006
Total Assets
E&P
United States	$	35,167		35,523
International		54,945		48,143
Goodwill		27,750		27,712
Total E&P		117,862		111,378
Midstream		1,956		2,045
R&M
United States		24,284		22,936
International		9,880		9,135
Goodwill		3,781		3,776
Total R&M		37,945		35,847
LUKOIL Investment		9,832		9,564
Chemicals		2,293		2,379
Emerging Businesses		996		977
Corporate and Other		2,325		2,591
Consolidated total assets	$	173,209		164,781

Note 22—Income Taxes

Our effective tax rates for the first quarters of 2007 and 2006 were 42 percent and 43 percent, respectively. The change in the effective tax rate for the first quarter of 2007, versus the same period of 2006, was primarily due to the effect of our asset rationalization efforts, partially offset by a higher proportion of income in higher tax rate jurisdictions. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.

Effective January 1, 2007, we adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109.” See Note 3—Changes in Accounting Principles, for additional information.

Note 23—New Accounting Standards

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115.” This Statement permits an entity to choose to measure financial instruments and certain other items similar to financial instruments at fair value. All subsequent changes in fair value for the financial instrument would be reported in earnings. By electing the fair value option, an entity can also achieve consistent accounting for related assets and liabilities without having to apply complex hedge accounting. This Statement is effective January 1, 2008. We are currently evaluating the impact on our consolidated financial statements.

25

Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to publicly held debt securities. ConocoPhillips Company is wholly owned by ConocoPhillips. ConocoPhillips Australia Funding Company is an indirect, wholly owned subsidiary of ConocoPhillips Company. ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding Company II are indirect, wholly owned subsidiaries of ConocoPhillips. ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to their publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. Conoco Funding Company, a wholly owned Nova Scotia finance subsidiary, also has senior unsecured debt securities fully and unconditionally guaranteed by ConocoPhillips. All guarantees are joint and several. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:

• ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).

• All other non-guarantor subsidiaries of ConocoPhillips.

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

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

26

	Millions of Dollars
	Three Months Ended March 31, 2007
							ConocoPhillips
							Australia		ConocoPhillips			ConocoPhillips
				ConocoPhillips			Funding		Canada Funding			Canada Funding			All Other			Consolidating			Total
Income Statement	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries			Adjustments			Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—			25,977			—		—			—			15,343			—			41,320
Equity in earnings of affiliates		3,563			3,022			—		—			—			545			(6,201	)		929
Other income		—			(110	)		—		—			—			728			—			618
Intercompany revenues		89			698			30		19			12			3,813			(4,661	)		—
Total Revenues and Other Income		3,652			29,587			30		19			12			20,429			(10,862	)		42,867
Costs and Expenses
Purchased crude oil, natural gas and products		—			22,022			—		—			—			8,631			(3,938	)		26,715
Production and operating expenses		—			1,108			—		—			—			1,427			(43	)		2,492
Selling, general and administrative expenses		3			291			—		—			—			229			4			527
Exploration expenses		—			22			—		—			—			240			—			262
Depreciation, depletion and amortization		—			362			—		—			—			1,662			—			2,024
Impairments		—			(24	)		—		—			—			23			—			(1	)
Taxes other than income taxes		—			1,503			—		—			—			2,938			(67	)		4,374
Accretion on discounted liabilities		—			14			—		—			—			65			—			79
Interest and debt expense		112			355			28		19			13			397			(617	)		307
Foreign currency transaction (gains) losses		—			—			—		7			10			(16	)		—			1
Minority interests		—			—			—		—			—			21			—			21
Total Costs and Expenses		115			25,653			28		26			23			15,617			(4,661	)		36,801
Income before income taxes		3,537			3,934			2		(7	)		(11	)		4,812			(6,201	)		6,066
Provision for income taxes		(9	)		584			1		(7	)		(8	)		1,959			—			2,520
Net Income (Loss)	$	3,546			3,350			1		—			(3	)		2,853			(6,201	)		3,546

27

	Millions of Dollars
	Three Months Ended March 31, 2006
				ConocoPhillips		All Other		Consolidating			Total
Income Statement	ConocoPhillips			Company		Subsidiaries		Adjustments			Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—			29,802		17,104		—			46,906
Equity in earnings of affiliates		3,323			2,811		735		(5,909	)		960
Other income		—			44		17		—			61
Intercompany revenues		—			562		2,462		(3,024	)		—
Total Revenues and Other Income		3,323			33,219		20,318		(8,933	)		47,927
Costs and Expenses
Purchased crude oil, natural gas and products		—			25,812		10,377		(2,734	)		33,455
Production and operating expenses		—			1,192		1,049		(26	)		2,215
Selling, general and administrative expenses		5			366		211		(16	)		566
Exploration expenses		—			14		98		—			112
Depreciation, depletion and amortization		—			415		765		—			1,180
Impairments		—			—		—		—			—
Taxes other than income taxes		—			1,448		3,003		(64	)		4,387
Accretion on discounted liabilities		—			14		46		—			60
Interest and debt expense		44			145		110		(184	)		115
Foreign currency transaction losses		—			—		22		—			22
Minority interests		—			—		18		—			18
Total Costs and Expenses		49			29,406		15,699		(3,024	)		42,130
Income before income taxes		3,274			3,813		4,619		(5,909	)		5,797
Provision for income taxes		(17	)		490		2,033		—			2,506
Net Income	$	3,291			3,323		2,586		(5,909	)		3,291

28

	Millions of Dollars
	At March 31, 2007
							ConocoPhillips
							Australia		ConocoPhillips			ConocoPhillips
				ConocoPhillips			Funding		Canada Funding			Canada Funding			All Other		Consolidating			Total
Balance Sheet	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries		Adjustments			Consolidated
Assets
Cash and cash equivalents	$	—			14			—		—			1			1,094		(249	)		860
Accounts and notes receivable		126			13,800			32		12			4			18,976		(19,050	)		13,900
Inventories		—			3,167			—		—			—			2,518		—			5,685
Prepaid expenses and other current assets		9			797			—		10			7			3,473		—			4,296
Total Current Assets		135			17,778			32		22			12			26,061		(19,299	)		24,741
Investments, loans and long-term receivables*		85,318			70,731			2,000		1,269			858			45,059		(173,516	)		31,719
Net properties, plants and equipment		—			16,813			—		—			—			67,083		8			83,904
Goodwill		—			15,010			—		—			—			16,521		—			31,531
Intangibles		—			828			—		—			—			91		—			919
Other assets		9			105			5		28			14			233		1			395
Total Assets	$	85,462			121,265			2,037		1,319			884			155,048		(192,806	)		173,209
Liabilities and Stockholders’ Equity
Accounts payable	$	16			19,056			—		7			4			16,725		(19,050	)		16,758
Notes payable and long-term debt due within one year		1,000			618			—		—			—			89		—			1,707
Accrued income and other taxes		—			1,257			—		(2	)		(3	)		4,194		86			5,532
Employee benefit obligations		—			341			—		—			—			287		—			628
Other accruals		63			743			34		33			23			1,504		—			2,400
Total Current Liabilities		1,079			22,015			34		38			24			22,799		(18,964	)		27,025
Long-term debt		5,926			5,419			1,999		1,250			848			6,519		—			21,961
Asset retirement obligations and accrued environmental costs		—			987			—		—			—			4,642		—			5,629
Joint venture acquisition obligation		—			—			—		—			—			6,742		—			6,742
Deferred income taxes		(3	)		2,943			—		14			5			17,075		17			20,051
Employee benefit obligations		—			2,332			—		—			—			1,235		—			3,567
Other liabilities and deferred credits*		28			33,205			—		—			—			27,953		(58,935	)		2,251
Total Liabilities		7,030			66,901			2,033		1,302			877			86,965		(77,882	)		87,226
Minority interests		—			(19	)		—		—			—			1,220		—			1,201
Retained earnings		37,628			26,278			4		29			23			30,816		(50,628	)		44,150
Other stockholders’ equity		40,804			28,105			—		(12	)		(16	)		36,047		(64,296	)		40,632
Total	$	85,462			121,265			2,037		1,319			884			155,048		(192,806	)		173,209

*Includes intercompany loans.

29

	Millions of Dollars
	At December 31, 2006
								ConocoPhillips
								Australia		ConocoPhillips			ConocoPhillips
					ConocoPhillips			Funding		Canada Funding			Canada Funding			All Other		Consolidating			Total
Balance Sheet	ConocoPhillips				Company			Company		Company I			Company II			Subsidiaries		Adjustments			Consolidated
Assets
Cash and cash equivalents		$	—			116			—		—			1			1,042		(342	)		817
Accounts and notes receivable			65			13,233			22		10			2			17,224		(16,450	)		14,106
Inventories			—			2,906			—		—			—			2,247		—			5,153
Prepaid expenses and other current assets			11			895			—		10			7			4,067		—			4,990
Total Current Assets			76			17,150			22		20			10			24,580		(16,792	)		25,066
Investments, loans and long-term receivables*			86,292			58,530			2,000		1,241			841			28,372		(156,563	)		20,713
Net properties, plants and equipment			—			19,072			—		—			—			67,122		7			86,201
Goodwill			—			15,226			—		—			—			16,262		—			31,488
Intangibles			—			852			—		—			—			99		—			951
Other assets			10			141			5		35			24			195		(48	)		362
Total Assets		$	86,378			110,971			2,027		1,296			875			136,630		(173,396	)		164,781
Liabilities and Stockholders’ Equity
Accounts payable		$	68			16,641			—		5			3			14,367		(16,450	)		14,634
Notes payable and long-term debt due within one year			3,431			525			—		—			—			87		—			4,043
Accrued income and other taxes			—			732			—		—			—			3,577		98			4,407
Employee benefit obligations			—			464			—		—			—			431		—			895
Other accruals			50			804			24		16			10			1,565		(17	)		2,452
Total Current Liabilities			3,549			19,166			24		21			13			20,027		(16,369	)		26,431
Long-term debt			6,521			6,036			1,999		1,250			848			6,437		—			23,091
Asset retirement obligations and accrued environmental costs			—			1,095			—		—			—			4,524		—			5,619
Deferred income taxes			(8	)		2,969			—		16			10			17,086		1			20,074
Employee benefit obligations			—			2,379			—		—			—			1,288		—			3,667
Other liabilities and deferred credits*			29			28,306			—		—			—			22,300		(48,584	)		2,051
Total Liabilities			10,091			59,951			2,023		1,287			871			71,662		(64,952	)		80,933
Minority interests			—			(19	)		—		—			—			1,221		—			1,202
Retained earnings			34,756			22,939			4		29			26			28,029		(44,491	)		41,292
Other stockholders’ equity			41,531			28,100			—		(20	)		(22	)		35,718		(63,953	)		41,354
Total		$	86,378			110,971			2,027		1,296			875			136,630		(173,396	)		164,781

*Includes intercompany loans.

30

	Millions of Dollars
	Three Months Ended March 31, 2007
							ConocoPhillips
							Australia			ConocoPhillips		ConocoPhillips
				ConocoPhillips			Funding			Canada Funding		Canada Funding		All Other			Consolidating			Total
Statement of Cash Flows	ConocoPhillips			Company			Company			Company I		Company II		Subsidiaries			Adjustments			Consolidated
Net Cash Provided by Operating Activities	$	4,678			21			1			—		—		2,142			31			6,873
Cash Flows From Investing Activities
Acquisition of Burlington Resources Inc.		—			—			—			—		—		—			—			—
Capital expenditures and investments, including dry hole costs		—			(444	)		—			—		—		(2,368	)		(35	)		(2,847	)
Proceeds from asset dispositions		—			92			—			—		—		1,251			—			1,343
Long-term advances/loans to affiliates		—			(48	)		—			—		—		(932	)		801			(179	)
Collection of advances/loans to affiliates		—			33			—			—		—		—			(5	)		28
Other		1			5			—			—		—		1			—			7
Net Cash Provided by (Used in) Investing Activities		1			(362	)		—			—		—		(2,048	)		761			(1,648	)
Cash Flows From Financing Activities
Issuance of debt		(16	)		801			—			—		—		97			(801	)		81
Repayment of debt		(3,028	)		(538	)		—			—		—		(11	)		5			(3,572	)
Issuance of company common stock		40			—			—			—		—		—			—			40
Repurchase of company common stock		(1,000	)		—			—			—		—		—			—			(1,000	)
Dividends paid on company common stock		(674	)		—			(1	)		—		—		(61	)		62			(674	)
Other		(1	)		(24	)		—			—		—		(59	)		35			(49	)
Net Cash Provided by (Used in) Financing Activities		(4,679	)		239			(1	)		—		—		(34	)		(699	)		(5,174	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			—			—		—		(8	)		—			(8	)
Net Change in Cash and Cash Equivalents		—			(102	)		—			—		—		52			93			43
Cash and cash equivalents at beginning of year		—			116			—			—		1		1,042			(342	)		817
Cash and Cash Equivalents at End of Year	$	—			14			—			—		1		1,094			(249	)		860

31

	Millions of Dollars
	Three Months Ended March 31, 2006
				ConocoPhillips			All Other			Consolidating			Total
	ConocoPhillips			Company			Subsidiaries			Adjustments			Consolidated
Statement of Cash Flows
Net Cash Provided by Operating Activities	$	20,142			1,806			3,237			(20,385	)		4,800
Cash Flows From Investing Activities
Acquisition of Burlington Resources Inc.		—			—			(14,190	)		—			(14,190	)
Capital expenditures and investments, including dry holes		(17,494	)		(1,819	)		(3,415	)		18,214			(4,514	)
Proceeds from asset dispositions		—			3			2			—			5
Long-term advances/loans to affiliates		(14,989	)		(71	)		(3,152	)		18,086			(126	)
Collection of advances/loans to affiliates		—			2,505			1,004			(3,498	)		11
Net Cash Provided by (Used in) Investing Activities		(32,483	)		618			(19,751	)		32,802			(18,814	)
Cash Flows From Financing Activities
Issuance of debt		15,298			18,086			42			(18,086	)		15,340
Repayment of debt		(2,500	)		(1,002	)		(12	)		3,498			(16	)
Issuance of company common stock		40			—			—			—			40
Repurchase of company common stock		—			—			—			—			—
Dividends paid on company common stock		(496	)		(20,000	)		(385	)		20,385			(496	)
Other		(1	)		(36	)		18,224			(18,214	)		(27	)
Net Cash Provided by (Used in) Financing Activities		12,341			(2,952	)		17,869			(12,417	)		14,841
Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			(33	)		—			(33	)
Net Change in Cash and Cash Equivalents		—			(528	)		1,322			—			794
Cash and cash equivalents at beginning of year		—			613			1,601			—			2,214
Cash and Cash Equivalents at End of Period	$	—			85			2,923			—			3,008

32

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis contains forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations, and intentions, that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “intends,” “believes,” “expects,” “plans,” “scheduled,” “anticipates,” “estimates,” and similar expressions identify forward-looking statements. We do not undertake to update, revise or correct any of the forward-looking information. Readers are cautioned that such forward-looking statements should be read in conjunction with the disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995” beginning on page 57.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

On January 3, 2007, we closed on the previously announced business venture with EnCana Corporation to create an integrated North American heavy-oil business. The venture consists of two 50/50 operating business ventures, a Canadian upstream general partnership, FCCL Oil Sands Partnership, and a U.S. downstream limited liability company, WRB Refining LLC. We use the equity method of accounting for both business ventures, and the transaction is reflected in our results of operations beginning in the first quarter of 2007.

Our Exploration and Production (E&P) segment had net income of $2,329 million in the first quarter of 2007, which accounted for 66 percent of our total net income in the quarter. This compares with E&P net income of $2,087 million in the fourth quarter of 2006, and $2,553 million in the first quarter of 2006. Net income in the first quarter of 2007 was impacted by a decrease in crude oil prices. Industry crude oil prices for West Texas Intermediate averaged $57.99 per barrel in the first quarter of 2007, or $1.95 per barrel lower than the fourth quarter of 2006, and $5.29 per barrel lower than in the same period a year earlier. Crude oil prices were influenced by excess supplies at the Cushing, Oklahoma, hub associated with various refinery outages and transportation constraints.

Industry natural gas prices for Henry Hub increased during the first quarter of 2007 to $6.77 per million British thermal units (MMBTU), up $0.21 per MMBTU from the fourth quarter of 2006. Natural gas prices trended higher during the first quarter due to winter heating demand and expanding economic activity.

On March 31, 2006, we completed the $33.9 billion acquisition of Burlington Resources Inc. (Burlington Resources), an independent exploration and production company that held a substantial position in North American natural gas proved reserves, production and exploratory acreage. This acquisition added approximately 2 billion barrels of oil equivalent to our proved reserves. The acquisition is reflected in our results of operations beginning in the second quarter of 2006.

Our Refining and Marketing segment had net income of $1,136 million in the first quarter of 2007, compared with $919 million in the fourth quarter of 2006, and $390 million in the first quarter of 2006. First-quarter 2007 realized refining margins were higher than the previous period. Although domestic WTI-based market crack spreads improved significantly during the quarter, realized margins only improved slightly. This primarily was due to narrowing crude differentials, the periodic pricing of Brent and other crudes at a premium to WTI during the quarter, and the company’s refining configuration.

33

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three-month period ending March 31, 2007, is based on a comparison with the corresponding period of 2006.

Consolidated Results

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

	Millions of Dollars
	Three Months Ended
	March 31
	2007			2006
Exploration and Production (E&P)	$	2,329			2,553
Midstream		85			110
Refining and Marketing (R&M)		1,136			390
LUKOIL Investment		256			249
Chemicals		82			149
Emerging Businesses		(1	)		8
Corporate and Other		(341	)		(168	)
Net income	$	3,546			3,291

Net income was $3,546 million in the first quarter of 2007, compared with $3,291 million in the first quarter of 2006. The improved results in the first quarter of 2007 were primarily the result of:

• The net benefit from asset rationalization efforts in our E&P and R&M segments.

• Improved worldwide refining and marketing margins and higher worldwide refining volumes in our R&M segment.

• The inclusion of Burlington Resources in our results of operations for the E&P segment.

These items were partially offset by:

• Lower crude oil, natural gas and natural gas liquids prices in the E&P segment.

• Higher taxes in the E&P segment.

• Decreased net income from the Chemicals segment, reflecting lower earnings from Chevron Phillips Chemical Company LLC (CPChem), primarily due to lower olefins and polyolefins margins.

• Higher interest and debt expense resulting from higher average debt levels from the Burlington Resources acquisition.

See the “Segment Results” section for additional information on our segment results.

34

Income Statement Analysis

Sales and other operating revenues decreased 12 percent in the first quarter of 2007, while purchased crude oil, natural gas and products decreased 20 percent in the same period. These decreases were mainly the result of the implementation of Emerging Issues Task Force (EITF) Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” See Note 2—Accounting Policies, in the Notes to Consolidated Financial Statements, for additional information on the impact of this Issue on our consolidated income statement for the first quarter of 2007. In addition, decreases in revenues and purchased products resulted from lower crude oil, natural gas and natural gas liquids prices. These decreases were partially offset by higher sales volumes associated with the Burlington Resources acquisition.

Equity in earnings of affiliates decreased 3 percent in the first quarter of 2007, reflecting lower results from:

• Our heavy-oil joint ventures in Venezuela (Hamaca and Petrozuata), due to lower crude oil prices and lower production volumes. The decrease in volumes primarily resulted from OPEC reductions.

• Our chemicals joint venture, CPChem, as a result of lower margins from olefins and polyolefins and a 2006 business interruption insurance claim recognized in 2006.

• DCP Midstream, our midstream joint venture, reflecting lower natural gas liquids prices, reduced marketing results and higher costs. In addition, the earnings for the first quarter of 2006 included a gain on DCP Midstream’s sale of two processing plants and an NGL pipeline.

These decreases were partially offset by earnings from WRB Refining LLC, our downstream business venture with EnCana.

Other income increased significantly during the first quarter of 2007. The increase was primarily due to higher gains on asset dispositions associated with first-quarter 2007 asset rationalization efforts.

Production and operating expenses increased 13 percent during the first quarter of 2007, primarily due to the acquired Burlington Resources assets and general industry-wide cost increases.

Exploration expenses increased significantly during the first quarter of 2007, primarily due to the Burlington Resources acquisition.

Depreciation, depletion and amortization increased 72 percent in the first quarter of 2007, primarily resulting from the addition of Burlington Resources assets in the E&P segment’s depreciable asset base.

Interest and debt expense increased significantly during the first quarter of 2007, primarily due to higher average debt levels as a result of the financing required to partially fund the Burlington Resources acquisition.

35

Segment Results

E&P

	Three Months Ended
	March 31
	2007		2006
	Millions of Dollars
Net Income
Alaska	$	507		692
Lower 48		409		489
United States		916		1,181
International		1,413		1,372
	$	2,329		2,553

	Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)
United States	$	53.78	57.70
International		56.29	60.08
Total consolidated		55.17	58.97
Equity affiliates*		40.02	43.38
Worldwide E&P		53.38	56.63
Natural gas (per thousand cubic feet)
United States		6.19	7.42
International		6.49	7.16
Total consolidated		6.36	7.26
Equity affiliates*		.48	.23
Worldwide E&P		6.35	7.24
Natural gas liquids (per barrel)
United States		37.86	43.00
International		39.38	43.25
Total consolidated		38.56	43.13
Equity affiliates*		—	—
Worldwide E&P		38.56	43.13

	Millions of Dollars
Worldwide Exploration Expenses
General administrative; geological and geophysical; and lease rentals	$	114	74
Leasehold impairment		86	19
Dry holes		62	19
	$	262	112

*Excludes our equity share of LUKOIL reported in the LUKOIL Investment segment.

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	Three Months Ended
	March 31
	2007		2006
	Thousands of Barrels Daily
Operating Statistics
Crude oil produced
Alaska		276		283
Lower 48		104		64
United States		380		347
Europe		234		250
Asia Pacific		98		109
Canada		21		22
Middle East and Africa		96		49
Other areas		11		—
Total consolidated		840		777
Equity affiliates*
Canada		23		—
Russia and Caspian		15		16
Venezuela		82		110
		960		903
Natural gas liquids produced
Alaska		22		22
Lower 48		68		29
United States		90		51
Europe		14		15
Asia Pacific		12		20
Canada		31		9
Middle East and Africa		3		2
		150		97

	Millions of Cubic Feet Daily
Natural gas produced**
Alaska		122	163
Lower 48		2,190	1,264
United States		2,312	1,427
Europe		1,085	1,120
Asia Pacific		600	462
Canada		1,152	424
Middle East and Africa		142	121
Other areas		22	—
Total consolidated		5,313	3,554
Equity affiliates*
Canada		—	—
Russia and Caspian		—	—
Venezuela		9	11
		5,322	3,565

   *Excludes our equity share of LUKOIL reported in the LUKOIL Investment segment.

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

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	Three Months Ended
	March 31
	2007		2006
	Thousands of Barrels Daily
Mining operations Syncrude produced		23		16

The E&P segment explores for, produces and markets crude oil, natural gas, and natural gas liquids on a worldwide basis. It also mines deposits of oil sands in Canada to extract the bitumen and upgrade it into a synthetic crude oil. At March 31, 2007, our E&P operations were producing in the United States, Norway, the United Kingdom, the Netherlands, Canada, Nigeria, Venezuela, Ecuador, Argentina, offshore Timor Leste in the Timor Sea, Australia, China, Indonesia, Algeria, Libya, the United Arab Emirates, Vietnam, and Russia.

Net income for the E&P segment decreased 9 percent in the first quarter of 2007. The decrease was mainly the result of lower crude oil, natural gas and natural gas liquids prices, as well as higher taxes. The decrease was partially offset by the net benefit of asset rationalization efforts recognized in the first quarter of 2007, as well as higher production, primarily due to the addition of Burlington Resources assets. See the “Business Environment and Executive Overview” section for additional information on industry crude oil and natural gas prices.

U.S. E&P

Net income from our U.S. E&P operations decreased 22 percent in the first quarter of 2007, primarily due to lower crude oil, natural gas and natural gas liquids prices, as well as lower production levels and higher production taxes in Alaska. These decreases were partially offset by higher volumes in the Lower 48, primarily due to the inclusion of Burlington Resources results in our results of operations. In addition, the results for the first quarter of 2007 included gains on the sale of assets in Alaska and the Gulf of Mexico.

U.S. E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 855,000 BOE per day in the first quarter of 2007, an increase of 34 percent from 636,000 BOE per day in the first quarter of 2006. Production was favorably impacted by the addition of volumes from the Burlington Resources assets, offset partially by lower production in Alaska due to normal decline as well as the temporary shut-in of gas producing wells in the Cook Inlet, and lower production from the Magnolia field in the Gulf of Mexico.

International E&P

Net income from our international E&P operations increased 3 percent in the first quarter of 2007. The increase primarily was due to higher crude oil, natural gas and natural gas liquids volumes, due to the inclusion of Burlington Resources results in our results of operations, as well as a net benefit associated with our asset rationalization efforts. These increases were partially offset by lower crude oil, natural gas and natural gas liquids prices, as well as lower earnings from our equity investments in Venezuela as a result of higher extraction taxes and lower production levels. Net income was also negatively impacted by an increase in the rate of supplementary corporation tax enacted in the United Kingdom.

International E&P production averaged 1,142,000 BOE per day in the first quarter of 2007, an increase of 19 percent from 958,000 BOE per day in the first quarter of 2006. Production was favorably impacted in 2007 by the Burlington Resources acquisition, the 2005 reentry into Libya, where we did not lift until April of 2006, and our upstream business venture with EnCana Corporation. These increases were

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partially offset by lower production due to production sharing contract impacts in the Timor Sea, normal field decline and unplanned downtime in the United Kingdom and Norway, OPEC reductions in Venezuela, and the effect of asset dispositions in Canada. Effective in April 2007, we exited Dubai, United Arab Emirates, where our first-quarter 2007 production averaged 21,000 barrels per day.

Our Syncrude mining operations produced 23,000 barrels per day in the first quarter of 2007, compared with 16,000 barrels per day in the first quarter of 2006.

Midstream

	Three Months Ended
	March 31
	2007		2006
	Millions of Dollars
Net Income*	$	85		110
*Includes DCP Midstream-related net income:	$	50		93

	Dollars Per Barrel
Average Sales Prices
U.S. natural gas liquids*
Consolidated	$	37.73	37.64
Equity		36.55	37.29

*Prices are based on index prices from the Mont Belvieu and Conway market hubs that are weighted by natural gas liquids component and location mix.

	Thousands of Barrels Daily
Operating Statistics
Natural gas liquids extracted*		197	207
Natural gas liquids fractionated**		174	152

   *Includes our share of equity affiliates.

**Excludes DCP Midstream.

The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract natural gas liquids from the raw gas stream. The remaining “residue” gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are fractionated—separated into individual components like ethane, butane and propane—and marketed as chemical feedstock, fuel, or blendstock. The Midstream segment consists of our equity investment in DCP Midstream, LLC, as well as our other natural gas gathering and processing operations, and natural gas liquids fractionation and marketing businesses, primarily in the United States and Trinidad.

Net income from the Midstream segment decreased 23 percent in the first quarter of 2007. The decrease was primarily due to lower earnings from DCP Midstream, resulting mainly from lower natural gas liquids prices, reduced marketing results, and higher costs. In addition, our equity earnings from DCP Midstream for the first quarter of 2006 included our share of a gain on DCP Midstream’s sale of two processing plants and an NGL pipeline.

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R&M

	Three Months Ended
	March 31
	2007		2006
	Millions of Dollars
Net Income
United States	$	896		297
International		240		93
	$	1,136		390

	Dollars Per Gallon
U.S. Average Sales Prices*
Gasoline
Wholesale	$	1.86	1.79
Retail		2.03	1.90
Distillates—wholesale		1.94	1.89

* Excludes excise taxes.

	Thousands of Barrels Daily
Operating Statistics
Refining operations*
United States
Crude oil capacity		2,033		2,208
Crude oil runs		1,938		1,840
Capacity utilization (percent)		95	%	83
Refinery production		2,152		1,988
International
Crude oil capacity		696		523
Crude oil runs		623		490
Capacity utilization (percent)		90	%	94
Refinery production		644		500
Worldwide
Crude oil capacity		2,729		2,731
Crude oil runs		2,561		2,330
Capacity utilization (percent)		94	%	85
Refinery production		2,796		2,488
* Includes our share of equity affiliates, except for our share of LUKOIL, which is reported in the LUKOIL Investment segment.
Petroleum products sales volumes
United States
Gasoline		1,258		1,258
Distillates		862		813
Other products		480		517
		2,600		2,588
International		713		695
		3,313		3,283

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The R&M segment’s operations encompass refining crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels); buying, selling and transporting crude oil; and buying, transporting, distributing and marketing petroleum products. R&M has operations mainly in the United States, Europe and Asia Pacific.

Net income from the R&M segment increased significantly in the first quarter of 2007, primarily due to higher worldwide refining and marketing margins, higher worldwide refining volumes, a reduction of previously reported impairments on held-for-sale assets, and lower domestic turnaround costs.

U.S. R&M

Net income from our U.S. R&M operations was $896 million in the first quarter of 2007, compared with $297 million in the first quarter of 2006. The significant increase resulted primarily from higher refining and marketing margins and volumes, as well as lower turnaround costs, slightly offset by asset impairments recorded on assets held for sale.

Our U.S. refining capacity utilization rate was 95 percent in the first quarter of 2007, compared with 83 percent in the first quarter of 2006. The prior year rate was impacted by turnaround activity and unplanned downtime at several refineries.

International R&M

Net income from our international R&M operations was $240 million in the first quarter of 2007, compared with $93 million in the first quarter of 2006. The increase in net income was mainly the result of a reduction of previously estimated impairments of certain held-for-sale marketing assets based on finalized sales agreements. In addition, net income increased due to higher refining and marketing margins and higher refining volumes.

Our international refining capacity utilization rate was 90 percent in the first quarter of 2007, compared with 94 percent in the first quarter of 2006. The utilization rate was impacted by turnaround and maintenance activities and reduced crude throughput at our Wilhelmshaven, Germany facility to optimize refinery performance.

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LUKOIL Investment

	Millions of Dollars
	Three Months Ended
	March 31
	2007		2006
Net Income	$	256		249
Operating Statistics*
Net crude oil production (thousands of barrels daily)		393		306
Net natural gas production (millions of cubic feet daily)		309		98
Net refinery crude oil processed (thousands of barrels daily)		219		163

*Represents our net share of our estimate of LUKOIL’s production and processing.

This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia, which we account for under the equity method. As of March 31, 2007, our ownership interest in LUKOIL was 20 percent based on 851 million shares authorized and issued. Our ownership interest based on estimated shares outstanding, used for equity-method accounting, was 20.6 percent at March 31, 2007.

Because LUKOIL’s accounting cycle close and preparation of U.S. generally accepted accounting principles financial statements occur subsequent to our reporting deadline, our equity earnings and statistics for our LUKOIL investment are estimated, based on current market indicators, historical production and cost trends of LUKOIL, and other objective data. Once the difference between actual and estimated results is known, an adjustment is recorded. This estimate-to-actual adjustment will be a recurring component of future period results.

In addition to our estimate of our equity share of LUKOIL’s earnings, this segment reflects the amortization of the basis difference between our equity interest in the net assets of LUKOIL and the historical cost of our investment in LUKOIL, and also includes the costs associated with our employees seconded to LUKOIL and accruals for dividend withholding taxes.

Net income from the LUKOIL Investment segment increased 3 percent in the first quarter of 2007, primarily due to higher estimated volumes and an increase in our equity ownership, partially offset by an alignment of estimated net income to reported results and a decrease due to lower estimated prices.

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Chemicals

	Millions of Dollars
	Three Months Ended
	March 31
	2007		2006
Net Income	$	82		149

The Chemicals segment consists of our 50 percent interest in Chevron Phillips Chemical Company LLC (CPChem), which we account for under the equity method. CPChem uses natural gas liquids and other feedstocks to produce petrochemicals. These products are then marketed and sold, or used as feedstocks to produce plastics and commodity chemicals.

Net income from the Chemicals segment decreased 45 percent in the first quarter of 2007, reflecting lower margins from olefins and polyolefins and a business interruption insurance claim recognized in 2006, slightly offset by higher margins from aromatics and styrenics.

Emerging Businesses

	Millions of Dollars
	Three Months Ended
	March 31
	2007			2006
Net Income (Loss)
Power	$	13			31
Technology solutions		(3	)		(12	)
Other		(11	)		(11	)
	$	(1	)		8

The Emerging Businesses segment represents our investment in new technologies or businesses outside our normal scope of operations. Activities within this segment are currently focused on power generation; carbon-to-liquids; technology solutions, such as sulfur removal technologies; and alternative energy and programs, such as advanced hydrocarbon processes, energy conversion technologies, new petroleum-based products, and renewable fuels.

The Emerging Businesses segment reported a net loss of $1 million in the first quarter of 2007, compared with net income of $8 million in the first quarter of 2006, primarily reflecting lower margins from the Immingham power plant in the United Kingdom.

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Corporate and Other

	Millions of Dollars
	Three Months Ended
	March 31
	2007			2006		*
Net Loss
Net interest	$	(244	)		(93	)
Corporate general and administrative expenses		(23	)		(26	)
Acquisition/merger-related costs		(13	)		(5	)
Other		(61	)		(44	)
	$	(341	)		(168	)

*Certain amounts have been reclassified to conform to current period presentation.

Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased significantly in the first quarter of 2007, primarily due to higher average debt levels as a result of the financing required to partially fund the acquisition of Burlington Resources. In addition, net interest increased due to a $14 million premium on the early retirement of debt paid in the first quarter of 2007. These increases were partially offset by higher amounts of interest being capitalized.

Corporate general and administrative expenses decreased 12 percent in the first quarter of 2007, primarily due to reduced benefit-related expenses.

Acquisition/merger-related costs included seismic relicensing and other transition costs associated with the Burlington Resources acquisition.

The category “Other” includes certain foreign currency transaction gains and losses, and environmental costs associated with sites no longer in operation. Included in the lower results from Other in the first quarter of 2007 was a foreign currency loss and certain tax items not directly attributable to the operating segments.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

	Millions of Dollars
	At March 31			At December 31
	2007			2006
Notes payable and long-term debt due within one year	$	1,707			4,043
Total debt*	$	23,668			27,134
Minority interests	$	1,201			1,202
Common stockholders’ equity	$	84,782			82,646
Percent of total debt to capital**		22	%		24
Percent of floating-rate debt to total debt		35	%		41

   *Total debt includes notes payable and long-term debt due within one year, and long-term debt, as shown on our consolidated balance sheet.

**Capital includes total debt, minority interests and common stockholders’ equity.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from operating activities is the primary source of funding. In addition, during the first quarter of 2007, we raised $1,343 million from the sale of assets. During the quarter, available cash was used to support our ongoing capital expenditures and investments program, repurchase shares of our common stock, repay debt, provide loan financing to certain equity affiliates, pay dividends, and meet the funding requirements related to the business venture with EnCana Corporation (EnCana), which closed January 3, 2007. Total dividends paid on our common stock during the first quarter were $674 million. During the first quarter of 2007, cash and cash equivalents increased $43 million to $860 million.

In addition to cash flows from operating activities and proceeds from asset sales, we rely on our cash balance, commercial paper and credit facility programs, and our shelf registration statements, to support our short- and long-term liquidity requirements. We anticipate these sources of liquidity will be adequate to meet our funding requirements through 2008, including our capital spending program, our share repurchase programs, dividend payments, required debt payments and the funding requirements related to our business venture with EnCana.

Significant Sources of Capital

Operating Activities

During the first quarter of 2007, cash of $6,873 million was provided by operating activities, a 43 percent increase from cash from operations of $4,800 million in the corresponding period of 2006. Contributing to the increase was the impact of the Burlington Resources acquisition late in the first quarter of 2006, as well as higher refining and marketing margins. Cash from operations in the second quarter of 2007 will be impacted by U.S. federal income tax payments, a semi-annual Norwegian income tax payment and payment for the incremental 2006 production taxes accrued under the new Alaska production tax structure.

While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, natural gas and natural gas liquids, as well as refining and marketing margins. During the first three months of 2007 and 2006, we benefited from favorable crude oil and natural gas prices, as well as refining margins. The sustainability of these prices and margins is driven by

45

market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.

The level of our production volumes of crude oil, natural gas and natural gas liquids also impacts our cash flows. These production levels are impacted by such factors as acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiency, weather conditions, the addition of proved reserves through exploratory success, and the timely and cost-effective development of those proved reserves. While we actively manage certain factors that affect production, they can cause variability in cash flows, although historically this variability has not been as significant as that experienced with commodity prices and refining margins.

In addition, the level and quality of output from our refineries impacts our cash flows. The output at our refineries is impacted by such factors as operating efficiency, maintenance turnarounds, feedstock availability and weather conditions. We actively manage the operations of our refineries and typically any variability in their operations has not been as significant to cash flows as that experienced with refining margins.

In 2006, we received approximately $1.1 billion in distributions from our two heavy-oil projects in Venezuela. The majority of these distributions represented operating results from previous years. We did not receive a distribution related to these projects in the first quarter of 2007. See the “Outlook” section for additional discussion concerning the conditions for future distributions from our operations in Venezuela.

Asset Sales

Proceeds from asset sales during the first quarter of 2007 were $1,343 million, compared with $5 million for the same period of 2006.

Commercial Paper and Credit Facilities

At March 31, 2007, we had two revolving credit facilities totaling $5 billion that expire in October 2011. Also, we had a $2.5 billion revolving credit facility that originally expired in April 2011. The term of this facility has recently been extended to expire April 2012 at a reduced commitment level of $2.3 billion during the one-year extension period. These facilities may be used as direct bank borrowings, as support for the ConocoPhillips $7.5 billion commercial paper program, as support for the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, or as support for issuances of letters of credit totaling up to $750 million. The facilities are broadly syndicated among financial institutions and do not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The credit agreements contain a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ourselves, or by any of our consolidated subsidiaries. At March 31, 2007 and December 31, 2006, we had no outstanding borrowings under the credit facilities, but $41 million in letters of credit had been issued at both dates. Under both commercial paper programs, there was $1,006 million of commercial paper outstanding at March 31, 2007, compared with $2,931 million at December 31, 2006.

At March 31, 2007, our primary funding source for short-term working capital needs was the ConocoPhillips $7.5 billion commercial paper program, a portion of which may be denominated in other currencies (limited to euro 3 billion equivalent). Commercial paper maturities are generally limited to 90 days. Based on $1,006 million of commercial paper outstanding and $41 million of issued letters of credit, we had access to $6.5 billion in unused borrowing capacity under the three revolving credit facilities at March 31, 2007.

46

Shelf Registrations

We have a universal shelf registration statement on file with the SEC under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

We also have on file with the SEC a shelf registration statement under which ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding Company II, both wholly owned subsidiaries, could issue an indeterminate amount of senior debt securities, fully and unconditionally guaranteed by ConocoPhillips and ConocoPhillips Company.

Minority Interests

At March 31, 2007, we had outstanding $1,201 million of equity in less than wholly owned consolidated subsidiaries held by minority interest owners, including a minority interest of $508 million in Ashford Energy Capital S.A. The remaining minority interest amounts are primarily related to operating joint ventures we control. The largest of these, $668 million, was related to Darwin LNG located in northern Australia.

Off-Balance Sheet Arrangements

As part of our normal ongoing business operations and consistent with industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. At March 31, 2007, we were liable for certain contingent obligations under the following contractual arrangements:

• Qatargas 3:Qatargas 3 is an integrated project to produce and liquefy natural gas from Qatar’s North field. We own a 30 percent interest in the project. Our interest is held through a jointly owned company, Qatar Liquefied Gas Company Limited (3), for which we use the equity method of accounting. Qatargas 3 secured project financing of $4 billion in December 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA and commercial bank facilities. Prior to project completion certification, all loans, including the ConocoPhillips loan facilities, are guaranteed by the participants, based on their respective ownership interests. Accordingly, our maximum exposure to this financing structure is $1.2 billion. Upon completion certification, which is expected to be December 31, 2009, all project loan facilities, including the ConocoPhillips loan facilities, will become non-recourse to the project participants. At March 31, 2007, Qatargas 3 had $1.6 billion outstanding under all the loan facilities, of which ConocoPhillips provided $473 million, including accrued interest.

• Rockies Express Pipeline LLC:In June 2006, we issued a guarantee for 24 percent of the $2.0 billion in credit facilities of Rockies Express Pipeline LLC (Rockies Express), which will be used to construct a natural gas pipeline across a portion of the United States. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $480 million, which could become payable if the credit facility is fully utilized and Rockies Express fails to meet its obligations under the credit agreement. It is anticipated that construction completion will be achieved mid-2009, and refinancing will take place at that time, making the debt non-recourse.

• Other:At March 31, 2007, we had guarantees outstanding for our portion of joint-venture debt obligations, which have terms of up to 17 years. The maximum potential amount of future payments under the guarantees was approximately $140 million. Payment would be required if a joint venture defaults on its debt obligations.

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For additional information about guarantees, see Note 14—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Capital Requirements

Our debt balance at March 31, 2007, was $23.7 billion, a decrease of $3.5 billion during the first quarter of 2007.

On February 9, 2007, we announced plans to purchase $4 billion of our common stock in 2007. During the first quarter of 2007, we purchased 15.1 million shares of our common stock at a cost of $1 billion, including 73,000 shares at a cost of $5 million from a consolidated Burlington Resources grantor trust. Purchases in 2007, through April 30, 2007, totaled 19.2 million shares at a cost of $1.3 billion.

In December 2005, we entered into a credit agreement with Qatargas 3 to provide loan financing of approximately $1.2 billion for the construction of an LNG train in Qatar. This financing will represent 30 percent of the project’s total debt financing. Through March 31, 2007, we had provided $473 million in loan financing, including accrued interest. See the “Off-Balance Sheet Arrangements” section for additional information on Qatargas 3.

In 2004, we finalized our transaction with Freeport LNG Development, L.P. (Freeport LNG) to participate in an LNG receiving terminal in Quintana, Texas. We entered into a credit agreement with Freeport LNG to provide loan financing of approximately $630 million for the construction of the facility, which began in early 2005. Through March 31, 2007, we had provided $560 million in loan financing, including accrued interest.

In the fall of 2004, ConocoPhillips and LUKOIL agreed to the expansion of the Varandey terminal as part of our investment in the OOO Naryanmarneftegaz (NMNG) joint venture. We have an obligation to provide loan financing to Varandey Terminal Company for 30 percent of the costs of the terminal expansion, but we will have no governance or ownership interest in the terminal. We estimate our total loan obligation for the terminal expansion to be approximately $465 million at current exchange rates, including interest to be accrued during construction. This amount will be adjusted as the project’s cost estimate and schedule are updated and the ruble exchange rate fluctuates. Through March 31, 2007, we had provided $234 million in loan financing, including accrued interest.

Our loans to Qatargas 3, Freeport LNG and Varandey Terminal Company are included in the “Loans and advances—related parties” line on our consolidated balance sheet.

On January 3, 2007, we closed on the previously announced business venture with EnCana. As part of this transaction, we are obligated to contribute $7.5 billion, plus accrued interest, over a 10-year period, beginning in 2007, to the upstream business venture formed as a result of the transaction. An initial cash contribution of $188 million was made upon closing in January. The remaining $7.3 billion acquisition obligation is reflected as a liability on our March 31, 2007, consolidated balance sheet. Of this principal obligation amount, approximately $570 million is short-term and is included in the “Accounts payable—related parties” line on our consolidated balance sheet. Principal and interest payments of $237 million will be made each quarter, beginning in the second quarter of 2007, and continuing until the balance is

48

paid. In early April 2007, we made the principal and interest payment for the second quarter, reducing the remaining principal obligation to approximately $7.2 billion. The principal portion of these payments will be presented on our consolidated statement of cash flows as a financing activity. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance.

Effective January 15, 2007, we redeemed the 8% Junior Subordinated Deferrable Interest Debentures due 2037, at a premium of $14 million, plus accrued interest. This redemption resulted in the immediate redemption by Phillips 66 Capital II of $350 million of 8% Capital Securities. See Note 12—Debt, in the Notes to Consolidated Financial Statements, for additional information.

Also, in January 2007, we redeemed our $153 million 7.25% Notes due 2007 upon their maturity, and in February 2007, we reduced our Floating Rate Five-Year Term Note due 2011 from $5 billion to $4 billion.

In April 2007, we redeemed our $1 billion Floating Rate Notes due 2007 upon their maturity through the issuance of commercial paper.

In February 2007, we announced a quarterly dividend of 41 cents per share, representing a 14 percent increase over the previous quarter’s dividend of 36 cents per share. The dividend was paid March 1, 2007, to stockholders of record at the close of business February 20, 2007.

Contractual Obligations

Our contractual purchase obligations at March 31, 2007, were estimated to be $105 billion, an increase of $12 billion from the amount reported at December 31, 2006. The increase results primarily from the joint venture acquisition obligation with EnCana Corporation, as well as mostly higher natural gas volumes and crude and products derivative positions, all partially offset by lower power trading activity.

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Capital Spending

Capital Expenditures and Investments

	Millions of Dollars
	Three Months Ended
	March 31
	2007		2006
E&P
United States—Alaska	$	158		233
United States—Lower 48		685		186
International		1,727		1,787
		2,570		2,206
Midstream		—		1
R&M
United States		168		424
International		37		1,211
		205		1,635
LUKOIL Investment		—		612
Chemicals		—		—
Emerging Businesses		31		12
Corporate and Other		41		48
	$	2,847		4,514
United States	$	1,052		902
International		1,795		3,612
	$	2,847		4,514

E&P

UNITED STATES

Alaska

During the first quarter of 2007, we continued development drilling in the Greater Kuparuk Area (including the West Sak development), the Greater Prudhoe Area, and the Alpine field and Alpine satellite fields. Work on a project to upgrade the Trans-Alaska Pipeline System pump stations continued with the first pump station placed on line in February 2007.

Lower 48 States

In the Lower 48, we continued to develop our acreage positions and made investments in our deepwater Gulf of Mexico properties.

Onshore, we focused on natural gas developments in the San Juan Basin of New Mexico, the Lobo Trend of South Texas, the Bossier and Cotton Valley Trends of East Texas and North Louisiana, the Barnett Shale Trend of North Texas, and the Anadarko Basin of western Oklahoma. We focused on oil development in the Williston Basin of Montana and North Dakota, as well as oil and gas developments in southern Louisiana and in the Permian Basin of West Texas. In addition, we expended funds on a new gas development project in the Piceance Basin of northwest Colorado.

Offshore, expenditures were primarily focused on the Ursa development in the Gulf of Mexico.

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CANADA

During the first quarter of 2007, we continued with the development of our Surmont heavy-oil project, where initial production is expected in the first half of 2007, with sales beginning in the later part of the year. We also continued the development of our conventional oil and gas reserves in western Canada. In addition, we paid approximately $188 million related to our initial cash contribution to the upstream business venture with EnCana. See Note 18—Joint Venture Acquisition Obligation, in the Notes to Consolidated Financial Statements, for additional information.

SOUTH AMERICA

In the Gulf of Paria, off the coast of Venezuela, work continued on the development of the Corocoro project, where field production is expected to commence in the third quarter of 2008. See the “Outlook” section for additional information on our Venezuela operations.

EUROPE

In the U.K. and Norwegian sectors of the North Sea, funds were invested during the first quarter of 2007 for development of the Britannia satellite fields, Callanish and Brodgar, where production is expected in 2008; the Alvheim project, where production is scheduled to begin later in 2007; the Statfjord Late-Life Project, where production is targeted to startup in late 2007; and continued development of the Ekofisk Area.

MIDDLE EAST AND AFRICA

Libya

During the first quarter of 2007, funds were expended to continue the development of the Waha concessions.

Qatar

In Qatar, work continued on Qatargas 3, an integrated project to produce and liquefy natural gas from Qatar’s North field.

Algeria

In Algeria, during the first quarter of 2007, funds were invested in three fields in Block 405A, the Menzel Lejmat North field, the Ourhoud field, and the EMK (El Merk) oil field unit, which extends into the southeastern area of Block 405A.

RUSSIA AND CASPIAN

Russia

Through OOO Naryanmarneftegaz, a joint venture with LUKOIL, we are working to develop the Yuzhno Khylchuyu field in the northern part of Russia’s Timan-Pechora province.

Caspian

We continued to participate in construction activities to develop the Kashagan field on the Kazakhstan shelf in the Caspian Sea. We have a 9.26 percent interest in the North Caspian Sea Production Sharing Agreement, which includes the Kashagan field.

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ASIA PACIFIC

Indonesia

During the first quarter of 2007, we continued to invest funds on the development of the Belanak, Kerisi, Hiu, Belut, Ujung Pangkah, and Suban Phase II projects.

China

Work continued on the development of Phase II of the Peng Lai 19-3 field, as well as concurrent development of the nearby Peng Lai 25-6 field in 2007. The development of Peng Lai 19-3 and Peng Lai 25-6 will include multiple wellhead platforms and a larger floating production, storage and offloading facility.

R&M

In the United States, we expended funds during the first quarter of 2007 related to sustaining and improving the existing business with a focus on reliability, energy efficiency, capital maintenance and regulatory compliance. Work continued on projects to increase crude oil capacity, expand conversion capability and increase clean product yield.

Internationally, our focus during the quarter was on projects related to reliability, safety and the environment.

Contingencies

Legal and Tax Matters

We accrue for non-income-tax-related contingencies when a loss is probable and the amounts can be reasonably estimated. In the case of income-tax-related contingencies, we adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48), effective January 1, 2007. FIN 48 requires a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain. Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our financial statements.

Environmental

We 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, refining and crude oil and refined product marketing and transportation 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.

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• Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage, and disposal of solid waste.

• Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States.

• Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories with local emergency planning committees and responses departments.

• Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells.

• U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages.

These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time-consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.

Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.

The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States.

We are also subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks located at numerous past and present ConocoPhillips-owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require that contamination caused by such underground storage tank releases be assessed and remediated to meet applicable standards. In addition to other cleanup standards, many states have adopted cleanup criteria for methyl tertiary-butyl ether (MTBE) for both soil and groundwater. MTBE standards continue to evolve, and future environmental expenditures associated with the remediation of MTBE-contaminated underground storage tank sites could be substantial.

At RCRA permitted facilities, we are required to assess environmental conditions. If conditions warrant, we may be required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as “Superfund,” the cost of corrective action activities under RCRA corrective action programs typically is borne solely by us. Over the next decade, we anticipate that significant ongoing expenditures for RCRA remediation activities may be required, but such annual expenditures for

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the near term are not expected to vary significantly from the range of such expenditures we have experienced over the past few years. Longer term, expenditures are subject to considerable uncertainty and may fluctuate significantly.

We, from time to time, receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2006, we reported we had been notified of potential liability under CERCLA and comparable state laws at 64 sites around the United States. At March 31, 2007, we had resolved two of these sites and had received three new notices of potential liability, leaving 65 unresolved sites where we have been notified of potential liability.

For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.

We accrue for remediation activities when it is probable a liability has been incurred and reasonable estimates of the liability can be made. These accrued liabilities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).

Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we have identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA. Considerable uncertainty exists with respect to these costs, and under adverse changes in circumstances, potential liability may exceed amounts accrued as of March 31, 2007.

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, 2007, our balance sheet included a total environmental accrual of $1,000 million, compared with $1,062 million at December 31, 2006. We expect to incur a substantial majority of these expenditures within the next 30 years.

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

NEW ACCOUNTING STANDARDS

In February 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115.” This Statement permits an entity to choose to measure financial instruments and certain other items similar to financial instruments at fair value. All subsequent changes in fair value for the financial instrument would be reported in earnings. By electing the fair value option, an entity can also achieve consistent accounting for related assets and liabilities without having to apply complex hedge accounting. This Statement is effective January 1, 2008. We are currently evaluating the impact on our consolidated financial statements.

OUTLOOK

Alaska

On March 2, 2007, the governor of Alaska introduced a bill in the state legislature for the enactment of the Alaska Gasline Inducement Act (AGIA). The stated purpose of AGIA is to encourage the construction of a gas pipeline that would facilitate commercialization of Alaska’s North Slope gas resources, promote exploration and development of North Slope oil and gas resources, maximize benefits to Alaskans, and encourage commitment of natural gas to the gas pipeline. AGIA would establish a process for soliciting and evaluating proposals for a gas pipeline project, and establish certain conditions, requirements and inducements. We are seeking amendments to the AGIA bill we believe would foster greater competition and allow applicants to propose an integrated proposal to address the risks and interests of all parties, including current and future upstream owners, pipeline owners, and the state of Alaska. We expect to be actively involved in the AGIA legislative process and its results throughout 2007.

Venezuela

On January 31, 2007, Venezuela’s National Assembly passed a law allowing the president of Venezuela to pass laws on certain matters by decree. On February 26, 2007, the president of Venezuela issued a decree (the Nationalization Decree) mandating a number of unilateral changes to the present contractual structures related to heavy-oil ventures and oil production risk contracts, including the following:

• The national oil company of Venezuela, Petróleos de Venezuela, S.A. (PDVSA) would be required to assume operational control of all assets subject to the decree effective May 1, 2007.

• All of the rights currently vested in the Orinoco Oil Belt heavy-oil Associations and oil production risk contract joint ventures, including the ones in which we currently participate, would be terminated and those rights vested in a number of Venezuelan-controlledEmpresa Mixtalegal entities.

• PDVSA would be required to hold a minimum 60 percent ownership interest in all of the newly formedEmpresa Mixtalegal entities.

• PDVSA would assume complete ownership of the heavy-oil projects and production risk contracts if agreements regarding the terms and conditions for reduced ownership interests under theEmpresa Mixtaentity structure are not reached by June 26, 2007.

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The Nationalization Decree directly impacts our interests in each of the Petrozuata and Hamaca heavy-oil projects and the Corocoro oil production risk contract currently under development. Pursuant to the Nationalization Decree, PDVSA has assumed operational control of these three projects effective May 1, 2007, and ConocoPhillips cooperated with PDVSA, as required by the decree, to facilitate a safe and orderly transition of operations.

In the event we are able to reach agreement with respect to the takeover of these projects by theEmpresa Mixtalegal entities and assuming PDVSA takes a 60 percent interest under the terms of the Nationalization Decree and our ownership interest is reduced pro rata, our ownership interests in Petrozuata, Hamaca and Corocoro would decrease from 50.1 percent, 40.0 percent and 32.2 percent to 40.0 percent, 22.9 percent and 19.8 percent, respectively. If we are unable to reach an agreement, our ownership interests could be eliminated, potentially without any immediate compensation.

As a result, the ultimate impact of the Nationalization Decree, if fully implemented, on our results of operations and financial position is not determinable at this time, but could result in future reductions to our anticipated operating results, production volumes, and proved reserves and could lead to a material asset impairment charge. However, due to the indeterminable status of the outcome of negotiations presently under way, management has not concluded such an impairment of our investment and associated goodwill exists under U.S. generally accepted accounting principles. ConocoPhillips continues to preserve all of its rights under contracts, investment treaties, and international law and will continue to evaluate its options in realizing the value of its investments and operations in Venezuela.

The historical cost-based carrying value of our total investment in Venezuela was approximately $2.6 billion at March 31, 2007. Also, any sale or expropriation of our interests would be viewed as a partial disposition of our Worldwide Exploration and Production reporting unit and, under the guidance in SFAS No. 142, “Goodwill and Other Intangible Assets,” would require an allocation of goodwill to the sale or expropriation event. In the event of a sale or expropriation of our entire interest in Venezuela, we estimate approximately $1.9 billion of goodwill would be allocated to such an event. If only a partial sale or expropriation occurs, the amount of allocated goodwill would be proportionally reduced.

We believe the fair market value of our Venezuelan operations substantially exceeds the historical cost-based carrying value plus goodwill allocable to those operations. However, if compensation for our interests in Venezuela is less than the applicable carrying value plus allocable goodwill, we would record an impairment equal to the difference. Similarly, if we are unable to reach agreement in negotiations, we could record an impairment prior to pursuing our other rights, if the amount and collectibility of any future compensation is not certain.

At December 31, 2006, we had recorded 1,088 million BOE of proved reserves related to Petrozuata and Hamaca, and first-quarter 2007 production from these two joint ventures, after application of disproportionate OPEC reductions imposed by the Venezuelan government, averaged 82,000 net barrels per day of crude oil. First-quarter 2007 net income attributable to our Venezuelan operations was
$27 million.

The construction of the Petrozuata and Hamaca projects was funded in part with debt financing that is now non-recourse to the co-venturers. The implementation of the actions called for in the decree will require modifications in the terms of the financing associated with the projects. It is unlikely that any cash distributions will be made to any of the project co-venturers until these financings are modified or replaced.

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Other

In E&P, we expect our second quarter 2007 production to be lower than the level in the first quarter of 2007 due to scheduled maintenance, normal seasonality in Alaska, our exit from Dubai and asset dispositions.

In R&M, we expect our crude oil capacity utilization in the second quarter of 2007 to be in the mid-90-percent range.

CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “estimate,” “believe,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “should,” “will,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions.

We based the forward-looking statements relating to our operations on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you that these statements are not guarantees of future performance and involve risks, uncertainties and assumptions that we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including the following:

• Fluctuations in crude oil, natural gas and natural gas liquids prices, refining and marketing margins and margins for our chemicals business.

• The operation and financing of our midstream and chemicals joint ventures.

• Potential failure or delays in achieving expected reserve or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks and the inherent uncertainties in predicting oil and gas reserves and oil and gas reservoir performance.

• Unsuccessful exploratory drilling activities.

• Failure of new products and services to achieve market acceptance.

• Unexpected changes in costs or technical requirements for constructing, modifying or operating facilities for exploration and production projects, manufacturing or refining.

• Unexpected technological or commercial difficulties in manufacturing, refining, or transporting our products, including synthetic crude oil and chemicals products.

• Lack of, or disruptions in, adequate and reliable transportation for our crude oil, natural gas, natural gas liquids, LNG and refined products.

• Inability to timely obtain or maintain permits, including those necessary for construction of LNG terminals or regasification facilities, comply with government regulations, or make capital expenditures required to maintain compliance.

• Failure to complete definitive agreements and feasibility studies for, and to timely complete construction of, announced and future LNG and refinery projects and related facilities.

• Potential disruption or interruption of our operations due to accidents, extraordinary weather events, civil unrest, political events or terrorism.

• International monetary conditions and exchange controls.

• Liability for remedial actions, including removal and reclamation obligations, under environmental regulations.

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• Liability resulting from litigation.

• General domestic and international economic and political developments, including armed hostilities, expropriation of assets, changes in governmental policies relating to crude oil, natural gas, natural gas liquids or refined product pricing and taxation, other political, economic or diplomatic developments, and international monetary fluctuations.

• Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules applicable to our business.

• Inability to obtain economical financing for projects, construction or modification of facilities and general corporate purposes.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the three months ended March 31, 2007, does not differ materially from that discussed under Item 7A of ConocoPhillips’ Annual Report on Form 10-K for the year ended December 31, 2006.

Item 4. CONTROLS AND PROCEDURES

As of March 31, 2007, with the participation of our management, our Chairman, President and Chief Executive Officer (principal executive officer) and our Executive Vice President, Finance, and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the Act), of the effectiveness of the design and operation of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman, President and Chief Executive Officer and our Executive Vice President, Finance, and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of March 31, 2007.

There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Act, in the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the first quarter of 2007 and any material developments with respect to those matters previously reported in ConocoPhillips’ 2006 Form 10-K. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to the U.S. Securities and Exchange Commission’s regulations.

New Matters

On January 22, 2007, the Ferndale refinery received a Notice of Violation (NOV) from the Northwest Clean Air Agency, which alleges that the vapor recovery equipment at the refinery’s truck loading terminal exceeded the maximum pressure limit during loading. The NOV also alleges that notification of the underlying source test was reported late. We are working with the Northwest Clean Air Agency to resolve this matter.

On February 7, 2007, Gulf Coast Fractionators, a gas processing facility operated by ConocoPhillips in which we have a 22.5 percent interest, received a draft order from the Texas Commission on Environmental Quality (TCEQ) proposing to settle alleged violations of air emission permit limits at the plant. The order proposes a penalty of $135,538. We are working with the TCEQ to resolve this matter.

The Sweeny refinery received a series of Notices of Enforcement (NOEs) from the TCEQ in March, 2007. These NOEs generally relate to emission events such as flaring and other unplanned releases. TCEQ has not yet specified a penalty amount for these alleged violations. We expect to work with the TCEQ toward a resolution of these NOEs.

In the fall of 2006, the Wood River refinery experienced two incidents where coker oil mist was released from the Distilling West coker. In a February 9, 2007, letter the state of Illinois demanded $50,000 for each release. We are currently working with the state toward a final resolution of this matter. Effective January 1, 2007, ownership of the Wood River refinery was transferred to a business venture formed by ConocoPhillips Company and EnCana US Refining LLC. The new owner is named WRB Refining LLC. Penalties associated with operations of the refinery prior to the closing date will be the responsibility of ConocoPhillips, whereas those associated with operations after the closing date will be the responsibility of WRB Refining LLC.

On November 28, 2006, the state of Alaska, Department of Environmental Conservation (ADEC), notified ConocoPhillips Alaska, Inc. (CPAI) of an alleged violation of the Air Quality Control permit for the Central Production Facility #1, Kuparuk River Unit Topping Plant at the Kuparuk field on the North Slope of Alaska. The NOV resulted from information, self-reported by CPAI to ADEC, that CPAI had not operated an emissions monitoring unit at the topping plant. The NOV specifies that CPAI may be liable to the state for damages or a fine. We are currently working with ADEC to resolve this matter.

Matters Previously Reported

In September 2006, the San Luis Obispo Air Pollution Control District (SLOAPCD) provided a demand to settle four NOVs issued between May and August 2006 with respect to our Santa Maria facility, a part of our San Francisco area refinery. The NOVs allege the facility exceeded green coke feed limit on 17 separate days, failed to timely submit a second quarter 2006 report, failed to sample and analyze certain air

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emissions, and exceeded carbon plant pressure limits for three days. We have settled these NOVs by paying $75,000 to SLOAPCD.

On March 28, 2006, the TCEQ issued a revised draft agreed order relating to alleged air quality violations at the Borger refinery. The order addresses several categories of air quality violations including emission events, violation of permit conditions, and failure to pay emission fees, and a single solid waste violation for improper classification and disposal of waste. The order proposed a penalty of $160,406. We are continuing to work with the TCEQ to resolve this matter. Effective January 1, 2007, ownership of the Borger refinery was transferred to a business venture formed by ConocoPhillips Company and EnCana US Refining LLC. The new owner is named WRB Refining LLC. Penalties associated with operations of the refinery prior to the closing date will be the responsibility of ConocoPhillips, whereas those associated with operations after the closing date will be the responsibility of WRB Refining LLC.

On December 16, 2005, our Bayway refinery experienced a hydrocarbon spill to the Rahway River and Arthur Kill. As a result of this spill, we have signed an Order on Consent (Order) with the state of New York, and are also negotiating similar settlements with the state of New Jersey and the federal government. Under the final New York Order, COPC paid a penalty of $50,000 and conducted a beach cleanup.

In December 2005, ConocoPhillips Canada, Limited (COPC) was charged with five counts under the Environmental Protection and Enhancement Act of Alberta relating to a pipeline leak in Central Alberta that occurred in January 2004. The charges alleged that COPC released a substance into the environment that could or did have a significant adverse effect and alleged that COPC failed to contain and report the release when it was first detected. On March 7, 2007, ConocoPhillips entered into an order with the Alberta provincial government resolving this matter by payment of a $20,000 penalty and funding of a $200,000 grant to the University of Saskatchewan to develop and/or disseminate the findings of a study of animal health effects from oil and natural gas facilities.

In December 2005, the TCEQ proposed an administrative penalty of $120,132 for alleged violations of the Texas Clean Air Act at the Borger refinery. The allegations relate to unexcused emission events, reporting and recordkeeping requirements, leak detection and repair, flare outages, and deviation reporting. We are continuing to work with the TCEQ to resolve this matter.

In August of 2003, EPA Region 6 issued a Show Cause Order alleging violations of the federal Clean Water Act at the Borger refinery. The alleged violations relate primarily to discharges of selenium and reported exceedances of permit limits for whole effluent toxicity. On April 17, 2007, the U.S. Department of Justice (DOJ) sent a draft Consent Decree (CD) proposing to settle the outstanding wastewater allegations. The draft CD proposes a penalty of $2.64 million and includes injunctive actions, some of which have already been completed by ConocoPhillips. We expect to work with DOJ and EPA to resolve this matter.

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Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2006.

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

								Millions of Dollars
					Total Number of			Approximate Dollar
					Shares Purchased			Value of Shares
					as Part of Publicly			that May Yet Be
	Total Number of		Average Price		Announced Plans			Purchased Under the
Period	Shares Purchased*		Paid per Share		or Programs		**	Plans or Programs
January 1-31, 2007		3,350,613	$	65.02		3,344,000		$	895
February 1-28, 2007		3,693,944		66.40		3,685,459			3,650
March 1-31, 2007		8,102,448		67.01		8,099,583			3,107
Total		15,147,005	$	66.42		15,129,042

   *Includes the repurchase of common shares from company employees in connection with the company’s broad-based employee incentive plans.

**A repurchase program that provided for the repurchase of up to $1 billion of the company’s common stock over a period of up to two years was announced on November 15, 2005, and was completed in January 2007. On January 12, 2007, we announced a stock repurchase program that provided for the repurchase of up to $1 billion of the company’s common stock. On February 9, 2007, we announced plans to purchase $4 billion of our common stock in 2007, including the $1 billion announced on January 12, 2007. Acquisitions for the share repurchase programs are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Purchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plans are held as treasury shares.

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Item 6. EXHIBITS

Exhibits

10	First and Second Amendments to the ConocoPhillips Executive Severance Plan.
12	Computation of Ratio of Earnings to Fixed Charges.
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32	Certifications pursuant to 18 U.S.C. Section 1350.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CONOCOPHILLIPS

/s/ Rand C. Berney

Rand C. Berney

Vice President and Controller

(Chief Accounting and Duly Authorized Officer)

May 2, 2007

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Index to Exhibits

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