ConocoPhillips 10Q 2005 Q2 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 endedJune 30, 2005


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 number001-32395

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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yesþ Noo

The registrant had 1,391,961,391 shares of common stock, $.01 par value, outstanding at June 30, 2005.

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		24

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		33

Item 3. Quantitative and Qualitative Disclosures About Market Risk		60

Item 4. Controls and Procedures		60

Part II – Other Information

Item 1. Legal Proceedings		61

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		62

Item 4. Submission of Matters to a Vote of Security Holders		63

Item 6. Exhibits		64

Signature		65
Computation of Ratio of Earnings to Fixed Charges
Certification of CEO pursuant to Rule 13a-14a
Certification of CFO pursuant to Rule 13a-14a
Certifications pursuant to Section 1350

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS



Consolidated Income Statement		ConocoPhillips


	Millions of Dollars
	Three Months Ended					Six Months Ended
	June 30					June 30
	2005		2004*			2005			2004*
Revenues
Sales and other operating revenues(1)(2)	$	41,808		31,528			79,439			61,341
Equity in earnings of affiliates		701		322			1,754			591
Other income		105		36			339			171

Total Revenues		42,614		31,886			81,532			62,103


Costs and Expenses
Purchased crude oil, natural gas and products(3)		28,523		20,363			54,095			40,098
Production and operating expenses		2,147		1,840			4,099			3,505
Selling, general and administrative expenses		539		516			1,078			984
Exploration expenses		121		163			292			306
Depreciation, depletion and amortization		985		912			2,026			1,830
Property impairments		9		20			31			51
Taxes other than income taxes(1)		4,664		4,428			9,152			8,542
Accretion on discounted liabilities		41		41			89			77
Interest and debt expense		127		159			265			304
Foreign currency transaction losses (gains)		21		(33	)		18			(49	)
Minority interests		5		7			15			21

Total Costs and Expenses		37,182		28,416			71,160			55,669

Income from continuing operations before income taxes		5,432		3,470			10,372			6,434
Provision for income taxes		2,301		1,457			4,318			2,818

Income From Continuing Operations		3,131		2,013			6,054			3,616
Income (loss) from discontinued operations		7		62			(4	)		75

Net Income	$	3,138		2,075			6,050			3,691


Income Per Share of Common Stock(dollars)(4)
Basic
Continuing operations	$	2.24		1.46			4.33			2.63
Discontinued operations		.01		.04			—			.05

Net Income	$	2.25		1.50			4.33			2.68


Diluted
Continuing operations	$	2.21		1.44			4.26			2.60
Discontinued operations		—		.04			—			.05

Net Income	$	2.21		1.48			4.26			2.65


Dividends Paid Per Share of Common Stock(dollars)(4)	$	.31		.22			.56			.43


Average Common Shares Outstanding(in thousands)(4)
Basic		1,396,724		1,379,380			1,397,305			1,375,788
Diluted		1,419,288		1,398,022			1,420,022			1,393,528

(1)Includes excise, value added and other similar taxes on petroleum products sales:		*$ 4,338*		*4,172*			*8,493*			7,994

(2) Includes sales related to purchases/sales with the same counterparty:		*4,836*		*3,433*			*9,405*			6,799

(3) Includes purchases related to purchases/sales with the same counterparty:		*4,781*		*3,393*			*9,278*			6,681

(4) Per-share amounts and average number of common shares outstanding in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend on June 1, 2005.
*Certain amounts reclassified to conform to current year presentation.
See Notes to Consolidated Financial Statements.



Consolidated Balance Sheet		ConocoPhillips


	Millions of Dollars
	June 30			December 31
	2005			2004
Assets
Cash and cash equivalents	$	1,541			1,387
Accounts and notes receivable (net of allowance of $55 million in 2005 and 2004)		8,607			5,449
Accounts and notes receivable—related parties		403			3,339
Inventories		4,870			3,666
Prepaid expenses and other current assets		1,159			986
Assets of discontinued operations held for sale		167			194

Total Current Assets		16,747			15,021
Investments and long-term receivables		12,569			10,408
Net properties, plants and equipment		51,730			50,902
Goodwill		14,943			14,990
Intangibles		1,051			1,096
Other assets		429			444

Total Assets	$	97,469			92,861


Liabilities
Accounts payable	$	9,875			8,727
Accounts payable—related parties		623			404
Notes payable and long-term debt due within one year		354			632
Accrued income and other taxes		2,840			3,154
Employee benefit obligations		1,119			1,215
Other accruals		1,412			1,351
Liabilities of discontinued operations held for sale		105			103

Total Current Liabilities		16,328			15,586
Long-term debt		13,659			14,370
Asset retirement obligations and accrued environmental costs		3,741			3,894
Deferred income taxes		10,614			10,385
Employee benefit obligations		2,250			2,415
Other liabilities and deferred credits		2,365			2,383

Total Liabilities		48,957			49,033


Minority Interests		1,212			1,105

Common Stockholders’ Equity
Common stock (2,500,000,000 shares authorized at $.01 par value) Issued (2005—1,449,747,674 shares; 2004—1,437,729,662 shares)* Par value*		14			14
Capital in excess of par*		26,550			26,047
Compensation and Benefits Trust (CBT) (at cost: 2005—47,116,283 shares; 2004—48,182,820 shares)		(798	)		(816	)
Treasury stock (at cost: 2005—10,670,000 shares; 2004—0 shares)		(576	)		—
Accumulated other comprehensive income		1,003			1,592
Unearned employee compensation		(292	)		(242	)
Retained earnings		21,399			16,128

Total Common Stockholders’ Equity		47,300			42,723

Total	$	97,469			92,861


*2004 restated to reflect a two-for-one stock split effected as a 100 percent stock dividend on June 1, 2005.

See Notes to Consolidated Financial Statements.



Consolidated Statement of Cash Flows		ConocoPhillips


	Millions of Dollars
	Six Months Ended
	June 30
	2005			2004
Cash Flows From Operating Activities
Income from continuing operations	$	6,054			3,616
Adjustments to reconcile income from continuing operations to net cash provided by continuing operations
Non-working capital adjustments
Depreciation, depletion and amortization		2,026			1,830
Property impairments		31			51
Dry hole costs and leasehold impairments		156			192
Accretion on discounted liabilities		89			77
Deferred taxes		492			670
Undistributed equity earnings		(1,219	)		(278	)
Gain on asset dispositions		(242	)		(88	)
Other		(191	)		135
Working capital adjustments
Decrease in aggregate balance of accounts receivable sold		(480	)		(675	)
Decrease (increase) in other accounts and notes receivable		221			(1,319	)
Increase in inventories		(1,280	)		(710	)
Decrease (increase) in prepaid expenses and other current assets		(176	)		44
Increase in accounts payable		1,509			1,045
Decrease in taxes and other accruals		(130	)		(263	)

Net cash provided by continuing operations		6,860			4,327
Net cash provided by (used in) discontinued operations		(3	)		22

Net Cash Provided by Operating Activities		6,857			4,349


Cash Flows From Investing Activities
Capital expenditures and investments, including dry hole costs		(4,947	)		(3,065	)
Proceeds from asset dispositions		308			1,354
Long-term advances/loans to affiliates and other		(119	)		(72	)
Collection of advances/loans to affiliates and other		148			37

Net cash used in continuing operations		(4,610	)		(1,746	)
Net cash used in discontinued operations		—			(2	)

Net Cash Used in Investing Activities		(4,610	)		(1,748	)


Cash Flows From Financing Activities
Issuance of debt		333			—
Repayment of debt		(1,332	)		(2,083	)
Issuance of company common stock		263			207
Repurchase of company common stock		(576	)		—
Dividends paid on common stock		(780	)		(590	)
Other		97			183

Net cash used in continuing operations		(1,995	)		(2,283	)

Net Cash Used in Financing Activities		(1,995	)		(2,283	)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		(98	)		(4	)


Net Change in Cash and Cash Equivalents		154			314
Cash and cash equivalents at beginning of period		1,387			490

Cash and Cash Equivalents at End of Period	$	1,541			804


See Notes to Consolidated Financial Statements.



Notes to Consolidated Financial Statements		ConocoPhillips

Note 1—Interim Financial Information

The financial information for the interim periods presented in the financial statements included in this report is unaudited and includes all known accruals and adjustments that, in the opinion of management, are necessary for a fair presentation of the consolidated financial position of ConocoPhillips and its results of operations and cash flows for such periods. All such adjustments are of a normal and recurring nature. These interim financial statements should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and the consolidated financial statements and notes included in ConocoPhillips’ 2004 Annual Report on Form 10-K. Certain amounts in the 2004 financial statements included in this report on Form 10-Q have been reclassified to conform to the 2005 presentation.

Note 2—Accounting Policies

Revenue Recognition—Revenues associated with sales of crude oil, natural gas, natural gas liquids, petroleum and chemical products, and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry. Revenues include the sales portion of transactions commonly called buy/sell contracts, in which physical commodity purchases and sales are simultaneously contracted with the same counterparty to either obtain a different quality or grade of refinery feedstock supply, reposition a commodity (for example, where we enter into a contract with a counterparty to sell refined products or natural gas volumes at one location and purchase similar volumes at another location closer to our wholesale customer), or both.

At its June 2005, March 2005 and November 2004 meetings, the Emerging Issues Task Force (EITF) discussed Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” which addresses accounting issues that arise when one company both sells inventory to, and buys inventory from, another company in the same line of business. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate contractual arrangements, and the inventory purchased or sold may be in the form of raw material, work-in-progress, or finished goods. At issue is whether both the revenue and inventory/cost of sales should be recorded at fair value or whether the transactions should be classified as nonmonetary exchanges subject to the fair value exception of Accounting Principles Board (APB) Opinion No. 29, “Accounting for Nonmonetary Transactions.” Issue No. 04-13 encompasses our buy/sell transactions described above.

Buy/sell transactions have the same general terms and conditions as typical commercial contracts including: separate title transfer, transfer of risk of loss, separate gross billing and cash settlement for both the buy and sell sides of the transaction, and non-performance by one party does not relieve the other party of its obligation to perform (except in events of force majeure). Because buy/sell contracts have similar terms and conditions, we account for these purchase and sale transactions in the consolidated income statement as monetary transactions outside the scope of APB Opinion No. 29.

Our buy/sell transactions are similar to the “barrel back” example used in EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in Issue No. 02-3.” Using the “barrel back” example, the EITF concluded that a company’s decision to display buy/sell-type transactions either gross or net on the income statement is a matter of judgment that depends on relevant facts and circumstances. We apply this judgment based on guidance in EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” (Issue No. 99-19), which provides indicators for when to report revenues and the associated cost of goods sold gross (i.e., on separate revenue and cost of sales lines in the income statement) or net (i.e., on the same line). The indicators for gross reporting in Issue No. 99-19 are consistent with many of the characteristics of buy/sell transactions, which support our accounting for buy/sell transactions.

We also believe that the conclusion reached by the Derivatives Implementation Group Statement 133 Implementation Issue No. K1, “Miscellaneous: Determining Whether Separate Transactions Should be Viewed as a Unit,” further supports our judgment that the purchase and sale contracts should be viewed as two separate transactions and not as a single transaction.

At its March 2005 meeting, the EITF reached a tentative conclusion that exchanges of finished goods for raw materials or work-in-progress within the same line of business should be recorded at fair value because these exchanges culminate the earnings process. At its June 2005 meeting, the EITF reached a tentative conclusion that purchases and sales of inventory with the same party in the same line of business should be combined and accounted for as nonmonetary exchanges in accordance with APB Opinion No. 29 if they are entered into “in contemplation” of one another. The inventory could be raw materials, work-in progress, or finished goods. The tentative conclusions were posted to the Financial Accounting Standards Board (FASB) Web site for public comment and are scheduled to be discussed again at the EITF’s September meeting.

Depending on the EITF’s final conclusions, it is possible that we could be required to decrease sales and other operating revenues for second-quarter 2005 and 2004 periods by $4,836 million and $3,433 million, respectively, and six-month 2005 and 2004 periods by $9,405 million and $6,799 million, respectively, with a related decrease in purchased crude oil, natural gas and products on our consolidated income statement. We believe any impact to income from continuing operations and net income would result from LIFO inventory and would not be material to our financial statements.

Our Commercial organization uses commodity derivative contracts (such as futures and options) in various markets to optimize the value of our supply chain and balance physical systems. In addition to cash settlement prior to contract expiration, exchange-traded futures contracts may also be settled by physical delivery of the commodity, providing another source of supply to meet our refinery requirements or marketing demand.

Revenues from the production of natural gas properties, in which we have an interest with other producers, are recognized based on the actual volumes we sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be non-recoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant. Revenues associated with royalty fees from licensed technology are recorded based either upon volumes produced by the licensee or upon the successful completion of all substantive performance requirements related to the installation of licensed technology.

Stock-Based Compensation—Effective January 1, 2003, we voluntarily adopted the fair-value accounting method prescribed by Statement of Financial Accounting Standard (SFAS) No. 123, “Accounting for Stock-Based Compensation.” We used the prospective transition method, applying the fair-value accounting method and recognizing compensation expense equal to the fair-market value on the grant date for all stock options granted or modified after December 31, 2002.

Employee stock options granted prior to 2003 continue to be accounted for under APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. Because the exercise price of our employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is generally recognized under APB Opinion No. 25. The following table displays pro forma information as if provisions of SFAS No. 123 had been applied to all employee stock options granted:


	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2005			2004			2005			2004
Net income, as reported	$	3,138			2,075			6,050			3,691
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects		29			26			68			39
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effects		(30	)		(28	)		(69	)		(44	)

Pro forma net income	$	3,137			2,073			6,049			3,686

Earnings per share*:
Basic—as reported	$	2.25			1.50			4.33			2.68
Basic—pro forma		2.25			1.50			4.33			2.68
Diluted—as reported		2.21			1.48			4.26			2.65
Diluted—pro forma		2.21			1.48			4.26			2.65


*Per-share amounts reflect a two-for-one stock split effected as a 100 percent stock dividend on June 1, 2005.

Note 3—Common Stock Split

On April 7, 2005, our Board of Directors declared a 2-for-1 split on our common stock effected in the form of a 100 percent stock dividend, payable June 1, 2005, to stockholders of record as of May 16, 2005. The total number of authorized common stock shares and associated par value per share was unchanged by this action. Shares and per-share information in the Consolidated Income Statement and Consolidated Balance Sheet presented in this report are on an after-split basis for all periods presented.

Note 4—Changes in Accounting Principles

In April 2005, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) FAS 19-1, “Accounting for Suspended Well Costs,” with application required in the first reporting period beginning after April 4, 2005. Under early application provisions, we adopted FSP FAS 19-1 effective January 1, 2005. The adoption of this standard did not impact our six-month 2005 net income. See Note 8—Properties, Plants and Equipment for additional information.

In December 2004, the FASB issued FSP FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” and FSP 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004.” See Note 20—Income Taxes for additional information.

Consolidation of Variable Interest Entities (VIEs)

In February 2003, we entered into two 20-year agreements establishing separate guarantee facilities of $50 million for two liquefied natural gas ships that were under construction. Subject to the terms of the facilities, we will be required to make payments should the charter revenue generated by the ships fall below a certain specified minimum threshold, and we will receive payments to the extent that such revenues exceed those thresholds. Actual gross payments over the 20 years could exceed $100 million to the extent cash is received by us. In the first quarter of 2004, we determined the entity associated with the first ship was a VIE, but we were not the primary beneficiary and did not consolidate the entity. The second ship was delivered to its owner in July 2005. We are currently assessing the entity associated with this ship to determine if the entity is a VIE, and if we are the primary beneficiary. We currently account for these agreements as guarantees and contingent liabilities. See Note 12—Guarantees for additional information.

In July 2004, we announced the finalization of our transaction with Freeport LNG Development, L.P. (Freeport LNG) to participate in a LNG receiving terminal in Quintana, Texas. We have no ownership in Freeport LNG; however, we obtained a 50 percent interest in Freeport LNG GP, Inc., which serves as the general partner managing the venture. We agreed to provide loan financing to the venture. We determined Freeport LNG is a VIE, and that we are not the primary beneficiary. We account for our loan to Freeport LNG as a financial asset. Through June 30, 2005, we have provided $105 million in loan financing.

On June 30, 2005, ConocoPhillips and LUKOIL created the OOO Naryanmarneftegaz (NMNG) joint venture to develop resources in the northwest Arctic Russia. We determined that NMNG is a VIE because we and our related party, LUKOIL, have disproportionate interests. We have a 30 percent ownership interest with a 50 percent governance interest in the joint venture. We will use the equity method of accounting for this investment because we have determined we are not the primary beneficiary. Our funding for a 30 percent ownership interest amounted to $512 million.

Production from the NMNG joint-venture fields is expected to be transported via pipeline to LUKOIL’s existing terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international markets. LUKOIL is expected to complete an expansion of the terminal capacity in 2007, with ConocoPhillips participating in the design and financing of the terminal expansion. We determined that the terminal entity, Varandey Terminal Company, is also a VIE because we and our related party, LUKOIL, have disproportionate interests. We have an obligation to fund, through loans, 30 percent of the terminal’s costs, but we will have no governance interest in the terminal. We have determined we are not the primary beneficiary and will account for our loan to Varandey Terminal Company as a financial asset. Through June 30, 2005, we had provided $26 million in loan financing.

Note 5—Discontinued Operations

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


	Millions of Dollars
	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005			2004
Sales and other operating revenues from discontinued operations	$	89		341		165			919

Income (loss) from discontinued operations before-tax	$	11		82		(6	)		103
Income tax expense (benefit)		4		20		(2	)		28

Income (loss) from discontinued operations	$	7		62		(4	)		75

Assets of discontinued operations were primarily properties, plants and equipment, while liabilities of discontinued operations were primarily deferred taxes.

Note 6—Inventories

Inventories consisted of the following:


	Millions of Dollars
	June 30		December 31
	2005		2004
Crude oil and petroleum products	$	4,305		3,147
Materials, supplies and other		565		519

	$	4,870		3,666

Inventories valued on a last-in, first-out (LIFO) basis totaled $4,145 million and $2,988 million at June 30, 2005, and December 31, 2004, respectively. The remainder of our inventories is valued under various methods, including first-in, first-out and weighted average. The excess of current replacement cost over LIFO cost of inventories amounted to $4,214 million and $2,220 million at June 30, 2005, and December 31, 2004, respectively.

Note 7—Investments and Long-Term Receivables

LUKOIL

During the second quarter of 2005, we increased our ownership interest in LUKOIL to 12.6 percent at June 30, 2005, from 11.3 percent at March 31, 2005.

At June 30, 2005, the book value of our ordinary share investment in LUKOIL was $3,638 million. Our 12.6 percent share of the net assets of LUKOIL was estimated to be $2,833 million. This basis difference is $805 million, a majority of which is being amortized on a unit-of-production basis. On June 30, 2005, the closing price of LUKOIL shares on the London Stock Exchange was $36.81 per share, making the aggregate total market value of our LUKOIL investment $3,936 million at that date.

Duke Energy Field Services, LLC (DEFS)

On July 1, 2005, ConocoPhillips and Duke Energy Corporation (Duke) completed the restructuring of their respective ownership levels in DEFS, which resulted in DEFS becoming a jointly controlled venture, owned 50 percent by each company. This restructuring increased our ownership in DEFS to 50 percent from 30.3 percent through a series of direct and indirect transfers of certain Canadian Midstream assets from DEFS to Duke, a disproportionate cash distribution from DEFS to Duke from the sale of DEFS’ interest in TEPPCO Partners, L.P., and a combined payment by ConocoPhillips to Duke and DEFS of approximately $840 million. This payment was approximately $230 million higher than previously anticipated as our interest in the Empress plant in Canada was not included in the initial transaction as anticipated due to weather-related damages. However, the Empress plant was sold to Duke on August 1, 2005. We remain responsible for the repair of weather-related damages.

In the first-quarter 2005, as a part of equity earnings, we recorded our $306 million (after-tax) equity share of the financial gain from DEFS’ sale of the interest in TEPPCO.

Note 8—Properties, Plants and Equipment

Properties, plants and equipment included the following:


	Millions of Dollars
	June 30			December 31
	2005			2004
Properties, plants and equipment	$	71,442			69,151
Accumulated depreciation, depletion and amortization		(19,712	)		(18,249	)

Net properties, plants and equipment	$	51,730			50,902

Suspended Wells

In April 2005, the FASB issued FSP FAS 19-1, “Accounting for Suspended Well Costs” (FSP 19-1). This FASB Staff Position was issued to address whether there are circumstances that would permit the continued capitalization of exploratory well costs beyond one year, other than when further exploratory drilling is planned and major capital expenditures would be required to develop the project.

FSP 19-1 requires the continued capitalization of suspended well costs if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. All relevant facts and circumstances should be evaluated in determining whether a company is making sufficient progress assessing the reserves, and FSP 19-1 provides several indicators to assist in this evaluation. FSP 19-1 prohibits continued capitalization of suspended well costs on the chance that market conditions will change or technology will be developed to make the project economic. We adopted FSP 19-1 effective January 1, 2005. There was no impact to our consolidated financial statements from the adoption of this FSP.

The following table reflects the net changes in suspended exploratory well costs during the first six months of 2005, as well as for the years 2004 and 2003.


	Millions of Dollars
	Six Months
	Ended			Year			Year
	June 30, 2005			2004			2003
Beginning balance at January 1	$	347			403			221
Additions pending the determination of proved reserves		64			142			217
Reclassifications to proved properties		(59	)		(112	)		(6	)
Charged to dry hole expense		(82	)		(86	)		(29	)

Ending balance	$	270			347			403

The following table provides an aging of suspended well balances at June 30, 2005, and December 31, 2004 and 2003:


	Millions of Dollars
	June 30		December 31
	2005		2004		2003
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	136		142		217
Capitalized exploratory well costs that have been capitalized for a period greater than one year		134		205		186

Ending balance	$	270		347		403

Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		14		16		12

The following table provides a further aging of those exploratory well costs that have been capitalized for more than one year since the completion of drilling as of June 30, 2005:


	Millions of Dollars
	Suspended Since
Project	Total		2004		2003		2002		200l

Alpine satellite—Alaska (1)	$	21		—		—		21		—
Kashagan—Republic of Kazakhstan (2)		18		—		9		—		9
Aktote—Republic of Kazakhstan (4)		12		—		12		—		—
Gumusut—Malaysia (4)		12		—		12		—		—
Foothills of Western Alberta—Canada (3)		11		11		—		—		—
Su Tu Trang—Vietnam (2)		10		—		10		—		—
Eight projects of less than $10 million each (2)(4)		50		8		19		14		9

Total of 14 projects	$	134		19		62		35		18


(1)		Development decisions pending infrastructure west of Alpine and construction authorization.

(2)		Additional appraisal wells planned.

(3)		Wells in various stages of testing/completion.

(4)		Appraisal drilling complete; costs being incurred to assess development.

Note 9—Property Impairments

In the second quarter and six-month periods of 2005 and 2004, we recorded property impairments related to planned dispositions in our Midstream, Exploration and Production (E&P) and Refining and Marketing (R&M) segments. The amount of property impairments by segment were:


	Millions of Dollars
	Three Months Ended					Six Months Ended
	June 30					June 30
	2005			2004		2005		2004
Exploration and Production	$	1			4		1		8
Midstream		9			16		30		36
Refining and Marketing		(1	)		—		—		7

	$	9			20		31		51

Note 10—Debt

At June 30, 2005, we had two revolving credit facilities totaling $5 billion, available for use either as direct bank borrowings or as support for the issuance of up to $5 billion in commercial paper, a portion of which may be denominated in other currencies (limited to euro 3 billion equivalent). The facilities included a $2.5 billion four-year facility expiring in October 2008 and a $2.5 billion five-year facility expiring in October 2009. In addition, the five-year facility may be used to support issuances of letters of credit totaling up to $750 million. The facilities are broadly syndicated among financial institutions and do not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The credit agreements do contain a cross-default provision relating to our, or any of our consolidated subsidiaries’, failure to pay principal or interest on other debt obligations of $200 million or more. At June 30, 2005, and December 31, 2004, we had no outstanding borrowings under these facilities, but $62 million in letters of credit had been issued. There was no commercial paper outstanding at June 30, 2005, compared with $544 million at December 31, 2004.

In March 2005, we redeemed our $400 million 3.625% Notes due 2007 at par plus accrued interest. In conjunction with this redemption, $400 million of interest rate swaps were cancelled.

Note 11—Contingencies and Commitments

In the case of all known contingencies, we accrue a liability when the loss is probable and the amount is reasonably estimable. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries.

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

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

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

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

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those assumed in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable that future costs will be incurred and these costs can be reasonably estimated. At June 30, 2005, our balance sheet included a total environmental accrual of $1,020 million, compared with $1,061 million at December 31, 2004. We expect to incur the majority of these expenditures within the next 30 years. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings.

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

Other Contingencies—We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, we have performance obligations that are secured by unused letters of credit and various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.

Note 12—Guarantees

At June 30, 2005, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability at inception for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted, no liability has been recorded related to the guarantee.

Construction Completion Guarantees

•

We have a construction completion guarantee related to our share of debt held by Hamaca Holding LLC, used to construct the joint-venture project in Venezuela. The maximum potential amount of future payments under the guarantee is estimated to be $360 million, which could be called due if completion certification is not achieved by the Guaranteed Project Completion Date. The required 90-day Lender’s Reliability Test is currently underway and is a key to achieving project completion certification. If any issue arises during the 90-day Lender’s Reliability Test, we expect the Guaranteed Project Completion Date (currently October 1, 2005) to be extended to at least December 1, 2005, because of force majeure events that occurred during the construction period. In addition, other completion certification requirements remain outstanding at this time. These certification requirements may be resolved satisfactorily so that completion certification can be achieved; however, it is reasonably possible that the construction completion guarantee may not be fully released or the debt could be called due if the issues are not satisfactorily resolved.

Guarantees of Joint-Venture Debt

•

At June 30, 2005, we had guarantees outstanding for our portion of joint-venture debt obligations, which have terms of up to 20 years. The maximum potential amount of future payments under the guarantees is approximately $240 million. Payment would be required if a joint venture defaults on its debt obligations. Included in these outstanding guarantees was $98 million associated with the Polar Lights Company joint venture in Russia.

Other Guarantees

•

The Merey Sweeny, L.P. (MSLP) joint-venture project agreement requires the partners in the venture to pay cash calls to cover operating expenses in the event that the venture does not have enough cash to cover operating expenses after setting aside the amount required for debt service over the next 19 years. Although there is no maximum limit stated in the agreement, the intent is to cover short-term cash deficiencies should they occur. Our maximum potential future payments under the agreement are currently estimated to be $100 million, assuming such a shortfall exists at some point in the future due to an extended operational disruption. If such an operational disruption did occur, MSLP has business interruption insurance and would be entitled to insurance proceeds subject to deductibles and certain limits.

	•		In February 2003, we entered into two agreements establishing separate guarantee facilities for $50 million each for two liquefied natural gas ships. Subject to the terms of each such facility, we will be required to make payments should the charter revenue generated by the respective ship fall below certain specified minimum thresholds, and we will receive payments to the extent that such revenues exceed those thresholds. The net maximum future payments that we may have to make over the 20-year terms of the two agreements could be up to an aggregate of $100 million. Actual gross payments over the 20 years could exceed that amount to the extent cash is received by us. In the event either ship is sold or a total loss occurs, we also may have recourse to the sales or insurance proceeds to recoup payments made under the guarantee facilities. In September 2003, the first ship was delivered to its owner and the second ship was delivered to its owner in July 2005.

	•		We have other guarantees with maximum future potential payment amounts totaling $350 million, which consist primarily of dealer and jobber loan guarantees to support our marketing business, a guarantee to fund the short-term cash liquidity deficits of a lubricants joint venture, a guaranteed revenue deficiency payment to a pipeline joint venture, two small construction completion guarantees, a guarantee supporting a lease assignment on a corporate aircraft, a guarantee associated with a pending lawsuit and guarantees of the lease payment obligations of a joint venture. The carrying amount recorded for these other guarantees, as of June 30, 2005, was $22 million. These guarantees generally extend up to 15 years and payment would only be required if the dealer, jobber or lessee goes into default, if the lubricants joint venture has cash liquidity issues, if the pipeline joint venture has revenue below a certain threshold, if construction projects are not completed, if guaranteed parties default on lease payments, or if an adverse decision occurs in the lawsuit.

Indemnifications

•

Over the years, we have entered into various agreements to sell ownership interests in certain corporations and joint ventures and sold several assets, including FTC-mandated sales of downstream and midstream assets, certain exploration and production assets, and downstream retail and wholesale sites, giving rise to qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, environmental liabilities, underground storage tank repairs or replacements, permits and licenses, employee claims, real estate indemnity against tenant defaults, and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications, as of June 30, 2005, was $461 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information that the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible that future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the carrying amount recorded were $344 million of environmental accruals for known contamination that is included in asset retirement obligations and accrued environmental costs at June 30, 2005. For additional information about environmental liabilities, see Note 11—Contingencies and Commitments.

Note 13—Financial Instruments and Derivative Contracts

Commodity Derivative Contracts

In June 2005, we acquired two limited-term, fixed-volume overriding royalty interests in Utah and the San Juan Basin related to our production. As part of the acquisition, we assumed related commodity swaps with a negative fair value of $261 million at June 30, 2005. In late June and early July, we entered into additional commodity swaps to offset essentially all of the exposure from the assumed swaps.

Note 14—Comprehensive Income

ConocoPhillips’ comprehensive income was as follows:


	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2005			2004			2005			2004
Net income	$	3,138			2,075			6,050			3,691
After-tax changes in:
Minimum pension liability adjustment		—			—			(1	)		(1	)
Foreign currency translation adjustments		(336	)		48			(592	)		24
Unrealized loss on securities		—			(1	)		(1	)		—
Hedging activities		5			5			5			5

	$	2,807			2,127			5,461			3,719

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


	Millions of Dollars
	June 30			December 31
	2005			2004
Minimum pension liability adjustment	$	(68	)		(67	)
Foreign currency translation adjustments		1,070			1,662
Unrealized gain on securities		5			6
Deferred net hedging loss		(4	)		(9	)

	$	1,003			1,592

Note 15—Supplemental Cash Flow Information


	Millions of Dollars
	Six Months Ended
	June 30
	2005		2004
Non-Cash Investing and Financing Activities
Investment in properties, plants and equipment of businesses through the assumption of non-cash liabilities*	$	261		—
Fair market value of properties, plants and equipment received in a nonmonetary exchange transaction		138		—

Cash Payments
Interest	$	269		322
Income taxes		3,681		1,825


*See Note 13—Financial Instruments and Derivative Contracts for additional information.

Note 16—Sales of Receivables

At December 31, 2004, certain credit card and trade receivables had been sold to a Qualifying Special Purpose Entity (QSPE) in a revolving-period securitization arrangement. This arrangement provides for us to sell, and the QSPE to purchase, certain receivables and for the QSPE to then issue beneficial interests of up to $1.2 billion to five bank-sponsored entities. At December 31, 2004, the QSPE had issued beneficial interests to the bank-sponsored entities of $480 million. All five bank-sponsored entities are multi-seller conduits with access to the commercial paper market and purchase interests in similar receivables from numerous other companies unrelated to us. We have no ownership interests, nor any variable interests, in any of the bank-sponsored entities, which we do not consolidate. Furthermore, except as discussed below, we do not consolidate the QSPE because it meets the requirements of SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” to be excluded from the consolidated financial statements of ConocoPhillips. The receivables transferred to the QSPE met the isolation and other requirements of SFAS No. 140 to be accounted for as sales and were accounted for accordingly.

By January 31, 2005, all of the beneficial interests held by the bank-sponsored entities had matured; therefore, in accordance with SFAS No. 140, the operating results and cash flows of the QSPE subsequent to this maturity have been consolidated with our financial statements, and the assets and liabilities of the QSPE are included in our June 30, 2005 balance sheet. The revolving-period securitization arrangement expires in September 2005, and at this time we have no plans to renew the arrangement.

Total cash flows received from and paid under the securitization arrangements were as follows:


	Millions of Dollars
	2005			2004
Receivables sold at beginning of year	$	480			1,200
New receivables sold		960			5,025
Cash collections remitted		(1,440	)		(5,700	)

Receivables sold at June 30	$	—			525

Discounts and other fees paid on revolving balances	$	2			4

Note 17—Employee Benefit Plans

Pension and Postretirement Plans


	Millions of Dollars
	Pension Benefits												Other Benefits
Three Months Ended	June 30												June 30
	2005						2004						2005			2004
	U.S.			Int’l.			U.S.			Int’l.
Components of Net Periodic Benefit Cost
Service cost	$	38			19			38			18			5			6
Interest cost		44			32			43			27			12			14
Expected return on plan assets		(32	)		(28	)		(26	)		(22	)		—			—
Amortization of prior service cost		1			2			1			1			5			5
Recognized net actuarial loss (gain)		13			8			13			10			(1	)		3

Net periodic benefit costs	$	64			33			69			34			21			28


	Millions of Dollars
	Pension Benefits												Other Benefits
Six Months Ended	June 30												June 30
	2005						2004						2005			2004
	U.S.			Int’l.			U.S.			Int’l.
Components of Net Periodic Benefit Cost
Service cost	$	76			37			75			34			10			11
Interest cost		87			64			87			55			25			29
Expected return on plan assets		(63	)		(56	)		(52	)		(45	)		—			—
Amortization of prior service cost		2			4			2			3			10			10
Recognized net actuarial loss (gain)		27			17			26			20			(2	)		5

Net periodic benefit costs	$	129			66			138			67			43			55

We recognized pension settlement losses of $6 million in the first six months of 2004 due to high levels of lump-sum elections by new retirees in certain plans. Of this amount, $2 million was recognized in the second quarter of 2004.

During the first six months of 2005, we contributed $220 million to our domestic qualified and non-qualified benefit plans and $82 million to international qualified and non-qualified benefit plans.

At the end of 2004, we estimated that during 2005, we would contribute approximately $410 million to our domestic qualified and non-qualified plans and $140 million to our international benefits plans. We presently anticipate 2005 contributions to be $540 million to our domestic plans and $145 million to our international plans.

Note 18—Related Party Transactions

Significant transactions with related parties were:


	Millions of Dollars
	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
Operating revenues (a)	$	1,833		1,273		3,478		2,359
Purchases (b)		1,496		1,101		2,652		2,125
Operating expenses and selling, general and administrative expenses (c)		198		198		444		334
Net interest income (d)		9		8		19		15


(a)		Our Exploration and Production (E&P) segment sells natural gas to Duke Energy Field Services, LLC (DEFS) and crude oil to the Malaysian Refining Company Sdn. Bhd (Melaka), among others, for processing and marketing. Natural gas liquids, solvents and petrochemical feedstocks are sold to Chevron Phillips Chemical Company LLC (CPChem), gas oil and hydrogen feedstocks are sold to Excel Paralubes, and refined products are sold primarily to CFJ Properties and Getty Petroleum Marketing, Inc. (a subsidiary of LUKOIL). Also, we charge several of our affiliates including CPChem, MSLP, and Hamaca Holding LLC for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.

(b)		We purchase natural gas and natural gas liquids from DEFS and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchase upgraded crude oil from Petrozuata C.A. and refined products from Melaka. We also pay fees to various pipeline equity companies for transporting finished refined products and a price upgrade to MSLP for heavy crude processing. We purchase base oils and fuel products from Excel Paralubes for use in our refinery and specialty businesses.

(c)		We pay processing fees to various affiliates. Additionally, we pay crude oil transportation fees to pipeline equity companies.

(d)		We pay and/or receive interest to/from various affiliates including, prior to consolidation, the receivables securitization QSPE.

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

Note 19—Segment Disclosures and Related Information

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

E&P—This segment primarily explores for, produces and markets crude oil, natural gas, and natural gas liquids on a worldwide basis. At June 30, 2005, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Nigeria, Venezuela, offshore Timor Leste in the Timor Sea, Australia, China, Indonesia, the United Arab Emirates, Vietnam, and Russia. The E&P segment’s U.S. and international operations are disclosed separately for reporting purposes.

	2)		Midstream—Through both consolidated and equity interests, this segment gathers and processes natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in the United States, Canada and Trinidad. The Midstream segment includes our equity investment in DEFS. Through June 30, 2005, our equity ownership in DEFS was 30.3 percent. Effective July 1, 2005, we increased our ownership interest to 50 percent.

	3)		R&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. At June 30, 2005, we owned 12 refineries in the United States; one in the United Kingdom; one in Ireland; and had equity interests in one refinery in Germany, two in the Czech Republic, and one in Malaysia. The R&M segment’s U.S. and international operations are disclosed separately for reporting purposes.

	4)		LUKOIL Investment—This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia. In October 2004, we closed on a transaction to acquire 7.6 percent of LUKOIL’s shares held by the Russian government. During the remainder of 2004, we increased our ownership to 10.0 percent. During the first six months of 2005, we increased our ownership to 12.6 percent.

	5)		Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in CPChem.

	6)		Emerging Businesses—This segment encompasses the development of new businesses beyond our traditional operations. Emerging Businesses includes new technologies related to natural gas conversion into clean fuels and related products (gas-to-liquids), technology solutions, power generation, and emerging technologies.

Corporate and Other includes general corporate overhead; interest income and expense; discontinued operations; restructuring charges; certain eliminations; and various other corporate activities. Corporate assets include all cash and cash equivalents.

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

Analysis of Results by Operating Segment


	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2005			2004			2005			2004
Sales and Other Operating Revenues
E&P
United States	$	7,493			5,646			14,525			11,213
International		4,331			3,668			9,238			7,707
Intersegment eliminations-U.S.		(979	)		(697	)		(1,891	)		(1,359	)
Intersegment eliminations-international		(995	)		(1,021	)		(1,992	)		(1,959	)

E&P		9,850			7,596			19,880			15,602

Midstream
Total sales		850			700			1,871			1,939
Intersegment eliminations		(197	)		(184	)		(427	)		(537	)

Midstream		653			516			1,444			1,402

R&M
United States		24,021			17,391			43,976			32,818
International		7,296			6,078			14,155			11,617
Intersegment eliminations-U.S.		(150	)		(97	)		(237	)		(192	)
Intersegment eliminations-international		(4	)		—			(6	)		(1	)

R&M		31,163			23,372			57,888			44,242

LUKOIL Investment		—			—			—			—
Chemicals		4			3			7			7
Emerging Businesses		134			39			215			85
Corporate and Other		4			2			5			3

Consolidated Sales and Other Operating Revenues	$	41,808			31,528			79,439			61,341

Net Income (Loss)
E&P
United States	$	966			671			1,858			1,306
International		963			683			1,858			1,305

Total E&P		1,929			1,354			3,716			2,611

Midstream		68			42			453			97

R&M
United States		936			734			1,506			1,137
International		174			84			304			145

Total R&M		1,110			818			1,810			1,282

LUKOIL Investment		148			—			258			—
Chemicals		63			46			196			85
Emerging Businesses		(8	)		(29	)		(16	)		(51	)
Corporate and Other		(172	)		(156	)		(367	)		(333	)

Consolidated Net Income	$	3,138			2,075			6,050			3,691


	Millions of Dollars
	June 30		December 31
	2005		2004
Total Assets
E&P
United States	$	16,676		16,105
International		27,288		26,481
Goodwill		11,043		11,090

Total E&P		55,007		53,676

Midstream		1,671		1,293

R&M
United States		20,735		19,180
International		6,036		5,834
Goodwill		3,900		3,900

Total R&M		30,671		28,914

LUKOIL Investment		3,738		2,723
Chemicals		2,352		2,221
Emerging Businesses		897		972
Corporate and Other		3,133		3,062

Consolidated Total Assets	$	97,469		92,861

Note 20—Income Taxes

Our effective tax rate for the second quarter and first six months of 2005 was 42 percent, compared with 42 percent and 44 percent for the same periods a year ago. While there was not a change in the effective tax rate for the second quarter of 2005, versus the same period in 2004, there was a lower proportion of income in higher tax rate jurisdictions that offset the effect of international tax law changes in 2004. The change in the effective tax rate for the first six months of 2005, versus the same period in 2004, was due to the utilization of capital loss carryforwards that previously had a full valuation allowance and a lower proportion of income in higher tax rate jurisdictions that more than offset the effect of international tax law changes in 2004. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.

One of the provisions of the American Jobs Creation Act of 2004 was a special deduction for qualifying manufacturing activities. While the legislation is still undergoing clarifications, under guidance from FSP 109-1, we included the estimated impact as a current benefit, which was not material to the company’s effective tax rate, and it did not have any impact on our assessment of the need for possible valuation allowances.

Another provision of the American Jobs Creation Act of 2004 was a special one-time provision allowing earnings of controlled foreign companies to be repatriated at a reduced tax rate. At this point, our investigation into our response to the legislation is preliminary, as we await additional and final clarifying legislation and guidance from the government. Because of the uncertainties related to this legislation, and as provided by FSP 109-2, we elected to defer our decision on potentially altering our current plans on permanently reinvesting in certain foreign subsidiaries and foreign corporate joint ventures. We expect final guidance to be issued and our investigation into our response to the legislation to be completed late in 2005.

Note 21—New Accounting Standards and Emerging Issues

New Accounting Standards

In June 2005, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.” Issue No. 04-5 adopts a framework for evaluating whether the general partner (or general partners as a group) controls the partnership. The framework makes it more likely that a single general partner (or a general partner within a general partner group) would have to consolidate the limited partnership regardless of its ownership in the limited partnership. The new guidance was effective upon ratification for all newly-formed limited partnerships and for existing limited partnership agreements that are modified. The guidance is effective January 1, 2006, for existing limited partnership agreements that are not modified. We are reviewing Issue No. 04-5 to determine the impact, if any, on our financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3.” Among other changes, this Statement requires retrospective application for voluntary changes in accounting principle, unless it is impractical to do so. Guidance is provided on how to account for changes when retrospective application is impractical. This Statement is effective on a prospective basis beginning January 1, 2006.

In March 2005, the FASB issued FASB Interpretation 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). This Interpretation clarifies that an entity is required to recognize a liability for a legal obligation to perform asset retirement activities when the retirement is conditional on a future event and if the liability’s fair value can be reasonably estimated. If the liability’s fair value cannot be reasonably estimated, then the entity must disclose (a) a description of the obligation, (b) the fact that a liability has not been recognized because the fair value cannot be reasonably estimated, and (c) the reasons why the fair value cannot be reasonably estimated. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. We are required to implement this Interpretation in the fourth quarter of 2005 and are currently studying its provisions to determine the impact, if any, on our financial statements.

In December 2004, the FASB issued SFAS No. 153, “Exchange of Nonmonetary Assets, an amendment of APB Opinion No. 29.” This amendment eliminates the APB Opinion No. 29 exception for fair value recognition of nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges of nonmonetary assets that do not have commercial substance. This Statement is effective on a prospective basis beginning July 1, 2005.

Also in December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” (SFAS 123(R)), which supercedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” which we adopted at the beginning of 2003. SFAS 123(R) prescribes the accounting for a wide range of share-based compensation arrangements, including share options, restricted share plans, performance-based awards, share appreciation rights, and employee share purchase plans, and generally requires the fair value of share-based awards to be expensed in the income statement. For ConocoPhillips, this Statement provided for an effective date of third-quarter 2005; however, in April 2005, the Securities and Exchange Commission approved a new rule that delayed the effective date until January 1, 2006. We plan to adopt the provisions of this Statement January 1, 2006. We are studying the provisions of this new pronouncement to determine the impact, if any, on our financial statements. For more information on our adoption of SFAS No. 123 and its effect on net income, see Note 2—Accounting Policies.

In November 2004, the FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4.” This Statement requires that items, such as abnormal idle facility expense, excessive spoilage, double freight, and handling costs, be recognized as a current-period charge. We are required to implement this Statement in the first quarter of 2006. We are analyzing the provisions of this Statement to determine the effects, if any, on our financial statements.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity,” to address the balance sheet classification of certain financial instruments that have characteristics of both liabilities and equity. The Statement, already effective for contracts created or modified after May 31, 2003, was originally intended to become effective July 1, 2003, for all contracts existing at May 31, 2003. However, on November 7, 2003, the FASB issued an indefinite deferral of certain provisions of SFAS No. 150. We continue to monitor and assess the FASB’s modifications of SFAS No. 150, but do not anticipate any material impact to our financial statements.

Emerging Issues

At a November 2004 meeting and subsequent meetings, the EITF continued to discuss Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” which addresses accounting issues that arise when one company both sells inventory to and buys inventory from another company in the same line of business. For additional information, see the Revenue Recognition section of Note 2—Accounting Policies.

Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips and ConocoPhillips Company with respect to publicly held debt securities. ConocoPhillips Company is wholly owned by ConocoPhillips. ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. Similarly, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:

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

	•		All other non-guarantor subsidiaries of ConocoPhillips Company.

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

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

Effective January 1, 2005, ConocoPhillips Holding Company was merged into ConocoPhillips Company. Previously reported prior period information has been restated to reflect this reorganization of companies under common control.


	Millions of Dollars
	Three Months Ended June 30, 2005
				ConocoPhillips			All Other		Consolidating			Total
Income Statement	ConocoPhillips			Company			Subsidiaries		Adjustments			Consolidated
Revenues
Sales and other operating revenues	$	—			28,832			12,976		—			41,808
Equity in earnings of affiliates		3,142			2,207			577		(5,225	)		701
Other income		—			97			8		—			105
Intercompany revenues		8			447			2,261		(2,716	)		—

Total Revenues		3,150			31,583			15,822		(7,941	)		42,614


Costs and Expenses
Purchased crude oil, natural gas and products		—			24,173			6,731		(2,381	)		28,523
Production and operating expenses		—			1,131			1,028		(12	)		2,147
Selling, general and administrative expenses		5			334			204		(4	)		539
Exploration expenses		—			25			96		—			121
Depreciation, depletion and amortization		—			321			664		—			985
Property impairments		—			(2	)		11		—			9
Taxes other than income taxes		—			1,519			3,255		(110	)		4,664
Accretion on discounted liabilities		—			9			32		—			41
Interest and debt expense		26			226			84		(209	)		127
Foreign currency transaction losses (gains)		—			6			15		—			21
Minority interests		—			—			5		—			5

Total Costs and Expenses		31			27,742			12,125		(2,716	)		37,182

Income from continuing operations before income taxes		3,119			3,841			3,697		(5,225	)		5,432
Provision for income taxes		(12	)		699			1,614		—			2,301

Income from continuing operations		3,131			3,142			2,083		(5,225	)		3,131
Income (loss) from discontinued operations		7			7			—		(7	)		7

Net Income	$	3,138			3,149			2,083		(5,232	)		3,138


	Millions of Dollars
	Three Months Ended June 30, 2004
				ConocoPhillips		All Other			Consolidating			Total
Income Statement	ConocoPhillips			Company		Subsidiaries			Adjustments			Consolidated
Revenues
Sales and other operating revenues	$	—			21,046		10,482			—			31,528
Equity in earnings of affiliates		2,011			1,292		274			(3,255	)		322
Other income		—			57		(21	)		—			36
Intercompany revenues		21			372		1,586			(1,979	)		—

Total Revenues		2,032			22,767		12,321			(5,234	)		31,886


Costs and Expenses
Purchased crude oil, natural gas and products		—			16,898		5,336			(1,871	)		20,363
Production and operating expenses		—			1,001		849			(10	)		1,840
Selling, general and administrative expenses		2			348		169			(3	)		516
Exploration expenses		—			32		131			—			163
Depreciation, depletion and amortization		—			277		635			—			912
Property impairments		—			—		20			—			20
Taxes other than income taxes		—			1,570		2,858			—			4,428
Accretion on discounted liabilities		—			9		32			—			41
Interest and debt expense		22			177		55			(95	)		159
Foreign currency transaction losses (gains)		—			7		(40	)		—			(33	)
Minority interests		—			—		7			—			7

Total Costs and Expenses		24			20,319		10,052			(1,979	)		28,416

Income from continuing operations before income taxes		2,008			2,448		2,269			(3,255	)		3,470
Provision for income taxes		(5	)		437		1,025			—			1,457

Income from continuing operations		2,013			2,011		1,244			(3,255	)		2,013
Income from discontinued operations		62			62		31			(93	)		62

Net Income	$	2,075			2,073		1,275			(3,348	)		2,075


	Millions of Dollars
	Six Months Ended June 30, 2005
				ConocoPhillips			All Other		Consolidating			Total
Income Statement	ConocoPhillips			Company			Subsidiaries		Adjustments			Consolidated
Revenues
Sales and other operating revenues	$	—			53,458			25,981		—			79,439
Equity in earnings of affiliates		6,078			4,587			1,412		(10,323	)		1,754
Other income		(9	)		235			113		—			339
Intercompany revenues		18			941			4,281		(5,240	)		—

Total Revenues		6,087			59,221			31,787		(15,563	)		81,532


Costs and Expenses
Purchased crude oil, natural gas and products		—			44,931			13,873		(4,709	)		54,095
Production and operating expenses		—			2,155			1,968		(24	)		4,099
Selling, general and administrative expenses		9			675			407		(13	)		1,078
Exploration expenses		—			38			254		—			292
Depreciation, depletion and amortization		—			683			1,343		—			2,026
Property impairments		—			—			31		—			31
Taxes other than income taxes		—			3,067			6,195		(110	)		9,152
Accretion on discounted liabilities		—			18			71		—			89
Interest and debt expense		50			430			169		(384	)		265
Foreign currency transaction losses (gains)		—			5			13		—			18
Minority interests		—			—			15		—			15

Total Costs and Expenses		59			52,002			24,339		(5,240	)		71,160

Income from continuing operations before income taxes		6,028			7,219			7,448		(10,323	)		10,372
Provision for income taxes		(26	)		1,141			3,203		—			4,318

Income from continuing operations		6,054			6,078			4,245		(10,323	)		6,054
Income (loss) from discontinued operations		(4	)		(4	)		—		4			(4	)

Net Income	$	6,050			6,074			4,245		(10,319	)		6,050


	Millions of Dollars
	Six Months Ended June 30, 2004
				ConocoPhillips		All Other			Consolidating			Total
Income Statement	ConocoPhillips			Company		Subsidiaries			Adjustments			Consolidated
Revenues
Sales and other operating revenues	$	—			40,460		20,881			—			61,341
Equity in earnings of affiliates		3,611			2,446		489			(5,955	)		591
Other income		—			51		120			—			171
Intercompany revenues		44			756		3,014			(3,814	)		—

Total Revenues		3,655			43,713		24,504			(9,769	)		62,103


Costs and Expenses
Purchased crude oil, natural gas and products		—			33,002		10,659			(3,563	)		40,098
Production and operating expenses		—			1,892		1,635			(22	)		3,505
Selling, general and administrative expenses		4			648		342			(10	)		984
Exploration expenses		—			50		256			—			306
Depreciation, depletion and amortization		—			517		1,313			—			1,830
Property impairments		—			7		44			—			51
Taxes other than income taxes		—			2,921		5,621			—			8,542
Accretion on discounted liabilities		—			19		58			—			77
Interest and debt expense		44			384		95			(219	)		304
Foreign currency transaction losses (gains)		—			1		(50	)		—			(49	)
Minority interests		—			—		21			—			21

Total Costs and Expenses		48			39,441		19,994			(3,814	)		55,669

Income from continuing operations before income taxes		3,607			4,272		4,510			(5,955	)		6,434
Provision for income taxes		(9	)		661		2,166			—			2,818

Income from continuing operations		3,616			3,611		2,344			(5,955	)		3,616
Income from discontinued operations		75			75		90			(165	)		75

Net Income	$	3,691			3,686		2,434			(6,120	)		3,691


	Millions of Dollars
	At June 30, 2005
			ConocoPhillips			All Other		Consolidating			Total
Balance Sheet	ConocoPhillips		Company			Subsidiaries		Adjustments			Consolidated
Assets
Cash and cash equivalents	$	—		949			592		—			1,541
Accounts and notes receivable		782		14,138			17,941		(23,851	)		9,010
Inventories		—		3,358			1,512		—			4,870
Prepaid expenses and other current assets		9		501			649		—			1,159
Assets of discontinued operations held for sale		—		131			36		—			167

Total Current Assets		791		19,077			20,730		(23,851	)		16,747
Investments and long-term receivables		42,854		51,790			17,269		(99,344	)		12,569
Net properties, plants and equipment		—		17,408			34,322		—			51,730
Goodwill		—		14,943			—		—			14,943
Intangibles		—		739			312		—			1,051
Other assets		17		151			261		—			429

Total Assets	$	43,662		104,108			72,894		(123,195	)		97,469


Liabilities and Stockholders’ Equity
Accounts payable	$	51		20,863			13,435		(23,851	)		10,498
Notes payable and long-term debt due within one year		—		267			87		—			354
Accrued income and other taxes		—		4			2,836		—			2,840
Employee benefit obligations		—		819			300		—			1,119
Other accruals		18		736			658		—	��		1,412
Liabilities of discontinued operations held for sale		—		(8	)		113		—			105

Total Current Liabilities		69		22,681			17,429		(23,851	)		16,328
Long-term debt		1,600		7,897			4,162		—			13,659
Asset retirement obligations and accrued environmental costs		—		875			2,866		—			3,741
Deferred income taxes		—		3,159			7,463		(8	)		10,614
Employee benefit obligations		—		1,681			569		—			2,250
Other liabilities and deferred credits		1,054		17,743			17,987		(34,419	)		2,365

Total Liabilities		2,723		54,036			50,476		(58,278	)		48,957
Minority interests		—		(8	)		1,220		—			1,212
Retained earnings		14,863		22,053			15,416		(30,933	)		21,399
Other stockholders’ equity		26,076		28,027			5,782		(33,984	)		25,901

Total	$	43,662		104,108			72,894		(123,195	)		97,469


	Millions of Dollars
	At December 31, 2004
				ConocoPhillips			All Other		Consolidating			Total
Balance Sheet	ConocoPhillips			Company			Subsidiaries		Adjustments			Consolidated
Assets
Cash and cash equivalents	$	—			879			508		—			1,387
Accounts and notes receivable		767			11,742			20,995		(24,716	)		8,788
Inventories		—			2,367			1,299		—			3,666
Prepaid expenses and other current assets		20			381			585		—			986
Assets of discontinued operations held for sale		—			150			44		—			194

Total Current Assets		787			15,519			23,431		(24,716	)		15,021
Investments and long-term receivables		38,194			46,325			15,980		(90,091	)		10,408
Net properties, plants and equipment		—			16,618			34,284		—			50,902
Goodwill		—			14,990			—		—			14,990
Intangibles		—			747			349		—			1,096
Other assets		17			124			303		—			444

Total Assets	$	38,998			94,323			74,347		(114,807	)		92,861


Liabilities and Stockholders’ Equity
Accounts payable	$	62			17,443			16,342		(24,716	)		9,131
Notes payable and long-term debt due within one year		544			27			61		—			632
Accrued income and other taxes		—			360			2,794		—			3,154
Employee benefit obligations		—			646			569		—			1,215
Other accruals		20			488			843		—			1,351
Liabilities of discontinued operations held for sale		—			(10	)		113		—			103

Total Current Liabilities		626			18,954			20,722		(24,716	)		15,586
Long-term debt		1,994			8,163			4,213		—			14,370
Asset retirement obligations and accrued environmental costs		—			890			3,004		—			3,894
Deferred income taxes		(1	)		2,979			7,415		(8	)		10,385
Employee benefit obligations		—			1,809			606		—			2,415
Other liabilities and deferred credits		8			18,120			18,140		(33,885	)		2,383

Total Liabilities		2,627			50,915			54,100		(58,609	)		49,033
Minority interests		—			(6	)		1,111		—			1,105
Retained earnings		9,592			16,762			14,089		(24,315	)		16,128
Other stockholders’ equity		26,779			26,652			5,047		(31,883	)		26,595

Total	$	38,998			94,323			74,347		(114,807	)		92,861


	Millions of Dollars
	Six Months Ended June 30, 2005
				ConocoPhillips			All Other			Consolidating			Total
Statement of Cash Flows	ConocoPhillips			Company			Subsidiaries			Adjustments			Consolidated
Cash Flows From Operating Activities
Net cash provided by continuing operations	$	152			2,471			4,973			(736	)		6,860
Net cash used in discontinued operations		—			(3	)		—			—			(3	)

Net Cash Provided by Operating Activities		152			2,468			4,973			(736	)		6,857


Cash Flows From Investing Activities
Capital expenditures and investments, including dry holes		—			(1,894	)		(3,833	)		780			(4,947	)
Proceeds from asset dispositions		—			81			227			—			308
Long-term advances/loans to affiliates and other investments		—			(2,062	)		(1,086	)		3,029			(119	)
Collection of advances/loans to affiliates		—			432			78			(362	)		148

Net cash used in continuing operations		—			(3,443	)		(4,614	)		3,447			(4,610	)
Net cash used in discontinued operations		—			—			—			—			—

Net Cash Used in Investing Activities		—			(3,443	)		(4,614	)		3,447			(4,610	)


Cash Flows From Financing Activities
Issuance of debt		1,895			1,390			77			(3,029	)		333
Repayment of debt		(952	)		(347	)		(393	)		360			(1,332	)
Issuance of company common stock		263			—			—			—			263
Repurchase of company common stock		(576	)		—			—			—			(576	)
Dividends paid on common stock		(780	)		—			(739	)		739			(780	)
Other		(2	)		—			880			(781	)		97

Net Cash Used in Financing
Activities		(152	)		1,043			(175	)		(2,711	)		(1,995	)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			2			(100	)		—			(98	)


Net Change in Cash and Cash Equivalents		—			70			84			—			154
Cash and cash equivalents at beginning of year		—			878			509			—			1,387

Cash and Cash Equivalents at End	$
of Period		—			948			593			—			1,541


	Millions of Dollars
	Six Months Ended June 30, 2004
				ConocoPhillips			All Other			Consolidating			Total
Statement of Cash Flows	ConocoPhillips			Company			Subsidiaries			Adjustments			Consolidated
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operations	$	(267	)		2,516			2,929			(851	)		4,327
Net cash provided by (used in) discontinued operations		—			(319	)		341			—			22

Net Cash Provided by (Used in) Operating Activities		(267	)		2,197			3,270			(851	)		4,349


Cash Flows From Investing Activities
Capital expenditures and investments, including dry holes		—			(707	)		(2,464	)		106			(3,065	)
Proceeds from asset dispositions		—			1,097			458			(201	)		1,354
Long-term advances/loans to affiliates and other investments		—			(1,817	)		—			1,745			(72	)
Collection of advances/loans to affiliates		1,359			1,728			—			(3,050	)		37

Net cash provided by (used in) continuing operations		1,359			301			(2,006	)		(1,400	)		(1,746	)
Net cash provided by (used in) discontinued operations		—			(2	)		—			—			(2	)

Net Cash Provided by (Used in) Investing Activities		1,359			299			(2,006	)		(1,400	)		(1,748	)


Cash Flows From Financing Activities
Issuance of debt		—			1,668			77			(1,745	)		—
Repayment of debt		(709	)		(4,009	)		(415	)		3,050			(2,083	)
Issuance of company common stock		207			—			—			—			207
Repurchase of company common stock		—			—			—			—			—
Dividends paid on common stock		(590	)		—			(851	)		851			(590	)
Other		—			—			88			95			183

Net Cash Used in Financing Activities		(1,092	)		(2,341	)		(1,101	)		2,251			(2,283	)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			(5	)		1			—			(4	)


Net Change in Cash and Cash Equivalents		—			150			164			—			314
Cash and cash equivalents at beginning of year		—			268			222			—			490

Cash and Cash Equivalents at End of Period	$	—			418			386			—			804


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

Management’s Discussion and Analysis contains forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations, and intentions, that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “intends,” “believes,” “expects,” “plans,” “scheduled,” “anticipates,” “estimates,” and similar expressions identify forward-looking statements. We do not undertake to update, revise or correct any of the forward-looking information. Readers are cautioned that such forward-looking statements should be read in conjunction with the disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995” beginning on page 58.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and six-month periods ending June 30, 2005, is based on a comparison with the corresponding periods of 2004.

Business Environment and Executive Overview

Favorable market conditions and consistent production and throughput resulted in net income and cash from operations in the second quarter of 2005 that increased 51 percent and 22 percent, respectively, over the second quarter of 2004. Net income in the second quarter of 2005 was $3,138 million, while cash from operations totaled $2,768 million. During the quarter, we funded our capital expenditures and investments program of $3,125 million, which included a $512 million investment to acquire a 30 percent economic interest in a joint venture with LUKOIL to explore for and develop oil and gas resources in the northern part of Russia’s Timan-Pechora province, as well as a $384 million increase of our investment in the ordinary shares of LUKOIL. We also used cash to repurchase $382 million of our common stock in the quarter and pay $432 million in dividends. As a result of the above activity, our cash balance decreased $880 million during the quarter.

In the first six months of 2005, net income was $6,050 million, while cash from operations totaled $6,857 million. This allowed us to fund our capital expenditures and investments of $4,947 million, including a $708 million increase in our LUKOIL investment. Cash from operations was also used in the six-month period of 2005 to reduce debt by $989 million, pay $780 million in dividends, and repurchase $576 million of our common stock.

The Exploration and Production segment had net income of $1,929 million in the second quarter of 2005, compared with $1,787 million in the first quarter of 2005 and $1,354 million in the second quarter of 2004. Industry crude oil prices for West Texas Intermediate continued to strengthen in the second quarter of 2005, increasing to $53.03 per barrel, or $3.33 per barrel higher than the first quarter 2005 average price per barrel. Average crude prices in the second quarter of 2005 were $14.72 per barrel higher than in the same period a year earlier. Price increases continued to be supported by strong fundamentals, including robust global consumption and concern over the ability of production to keep pace with demand. Heightened geopolitical risk lent further support to crude prices worldwide.

Industry natural gas prices for Henry Hub during the second quarter of 2005 were up $0.47 to $6.74 per thousand cubic feet. Overall strength in natural gas prices was due primarily to higher crude oil prices and continued concerns regarding the adequacy of U.S. natural gas supplies.

The Refining and Marketing segment had net income of $1,110 million in the second quarter of 2005, compared with $700 million in the first quarter of 2005 and $818 million in the second quarter of 2004. Worldwide refining and marketing margins improved during the second quarter of 2005, compared with the first quarter of 2005. Industry U.S. refining margins strengthened due to the relatively higher demand for gasoline and distillates, concurrent with tight inventories and concern over adequate refining capacity to meet demand growth. This improvement was partially offset by narrowing light-heavy differentials. Worldwide marketing results improved as wholesale and retail prices began catching up with rising gasoline and diesel spot market prices, which rose, in part, as a consequence of the increase in crude oil prices.

Through the first six months of 2005, we continued to reduce debt, as well as increase stockholders’ equity through increased earnings. As a result, our debt-to-capital ratio was 22 percent at June 30, 2005, compared with 26 percent at December 31, 2004, and 34 percent at December 31, 2003.

On April 7, 2005, our Board of Directors declared a 2-for-1 stock split, which was paid on June 1, 2005, to stockholders of record as of May 16, 2005.

Consolidated Results

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


	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2005			2004			2005			2004
Exploration and Production (E&P)	$	1,929			1,354			3,716			2,611
Midstream		68			42			453			97
Refining and Marketing (R&M)		1,110			818			1,810			1,282
LUKOIL Investment		148			—			258			—
Chemicals		63			46			196			85
Emerging Businesses		(8	)		(29	)		(16	)		(51	)
Corporate and Other		(172	)		(156	)		(367	)		(333	)

Net income	$	3,138			2,075			6,050			3,691

Net income was $3,138 million in the second quarter of 2005, compared with $2,075 million in the second quarter of 2004. For the June year-to-date periods, net income was $6,050 million in 2005 and $3,691 million in 2004. The improved results in both 2005 periods primarily were the result of:

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

	•		Improved refining margins in the R&M segment.

	•		Equity earnings from our investment in LUKOIL.

In addition, the improved results in the six-month period of 2005 also reflected higher net gains on assets sales, including our equity share of DEFS’ sale of the general partner interest in TEPPCO Partners, LP (TEPPCO), as well as improved margins in the Chemicals segment.

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

Income Statement Analysis

Sales and other operating revenues increased 33 percent in the second quarter of 2005 and 30 percent in the six-month period, while purchased crude oil, natural gas and products increased 40 percent and 35 percent in the same periods, respectively. These increases mainly were due to higher petroleum product prices and higher prices for crude oil, natural gas and natural gas liquids.

Equity in earnings of affiliates increased 118 percent in the second quarter of 2005, and 197 percent in the six-month period. The increases reflect equity earnings from our investment in LUKOIL, which was initiated in October 2004, as well as improved results from:

	•		Our chemicals joint venture, Chevron Phillips Chemical Company LLC, due to higher margins.

	•		Our heavy-oil joint ventures in Venezuela, due to higher crude oil prices and higher production volumes.

	•		Our joint-venture refinery in Melaka, Malaysia, due to improved refining margins in the Asia Pacific region.

	•		Our joint-venture delayed coker facilities at the Sweeny, Texas, refinery, Merey Sweeny, L.P., due to higher crude oil light-heavy differentials.

	•		Our midstream joint venture, DEFS, due to higher natural gas liquids prices.

In addition, the six-month period also included our equity share of DEFS’ gain on the sale of the TEPPCO general partnership interest.

Other income increased 192 percent in the second quarter of 2005, and 98 percent in the six-month period. The increases were primarily due to higher net gains on asset dispositions in the 2005 periods. Asset dispositions in the first six months of 2005 included the sale of our interest in coalbed methane acreage positions in the Powder River Basin in Wyoming, as well as our interests in Dixie Pipeline and Turcas Petrol A.S. Asset dispositions in the first six months of 2004 included our interest in the Petrovera heavy-oil joint venture in Canada.

Production and operating expenses increased 17 percent in the second quarter and first six months of 2005. The increases were primarily due to new fields in the E&P segment, including the Magnolia field in the Gulf of Mexico that began producing in late-2004, and the Bayu-Undan field in the Timor Sea, which began production in February 2004 and achieved full production in the third quarter of 2004; and higher maintenance and utility costs in the R&M segment, due to increased turnaround activity and higher natural gas costs.

Depreciation, depletion and amortization (DD&A) increased 8 percent in second quarter of 2005, and 11 percent in the six-month period. The increases primarily were due to new fields in the E&P segment, including the Magnolia field and the Bayu-Undan field.

Segment Results

E&P

Millions of Dollars

Three Months Ended

Six Months Ended

June 30

2005

2004

2005

2004

Net Income

Alaska

572

397

1,104

800

Lower 48

394

274

754

506

United States

966

671

1,858

1,306

International

963

683

1,858

1,305

1,929

1,354

3,716

2,611

Dollars Per Unit

Average Sales Prices

Crude oil (per barrel)

United States

48.21

36.22

45.86

34.45

International

49.41

34.58

47.68

33.02

Total consolidated

48.88

35.32

46.85

33.68

Equity affiliates*

36.11

25.48

33.59

22.17

Worldwide

46.93

34.17

45.04

32.27

Natural gas—lease (per thousand cubic feet)

United States

6.07

5.35

5.83

5.11

International

5.16

3.81

5.10

3.96

Total consolidated

5.53

4.43

5.38

4.42

Equity affiliates*

.32

.31

.30

3.14

Worldwide

5.52

4.43

5.38

4.42


	Millions of Dollars
Worldwide Exploration Expenses
General administrative; geological and geophysical; and lease rentals	$	73	58	136	114
Leasehold impairment		18	63	38	83
Dry holes		30	42	118	109

	$	121	163	292	306


	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
	Thousands of Barrels Daily
Operating Statistics
Crude oil produced
Alaska		297		307		303		314
Lower 48		63		52		62		52

United States		360		359		365		366
European North Sea		255		276		261		279
Asia Pacific		88		88		98		86
Canada		23		25		23		26
Other areas		54		61		54		61

Total consolidated		780		809		801		818
Equity affiliates*		123		104		122		109

		903		913		923		927


Natural gas liquids produced*
Alaska		16		23		20		25
Lower 48		31		26		29		25

United States		47		49		49		50
European North Sea		12		13		13		13
Asia Pacific		9		4		13		2
Canada		10		10		10		10
Other areas		2		3		2		3

		80		79		87		78


	Millions of Cubic Feet Daily
Natural gas produced**
Alaska		148	147	166	166
Lower 48		1,195	1,226	1,182	1,229

United States		1,343	1,373	1,348	1,395
European North Sea		1,009	1,124	1,065	1,162
Asia Pacific		336	284	331	295
Canada		422	437	420	432
Other areas		81	81	78	73

Total consolidated		3,191	3,299	3,242	3,357
Equity affiliates*		7	4	7	6

		3,198	3,303	3,249	3,363


	Thousands of Barrels Daily
Mining operations
Syncrude produced		21	20	18	22


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

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

The E&P segment explores for, produces and markets crude oil, natural gas, and natural gas liquids on a worldwide basis. It also mines deposits of oil sands in Canada to extract the bitumen and upgrade it into a synthetic crude oil. At June 30, 2005, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Nigeria, Venezuela, offshore Timor Leste in the Timor Sea, Australia, China, Indonesia, the United Arab Emirates, Vietnam, and Russia.

Net income for the E&P segment increased 42 percent in the second quarter and first six months of 2005. The increase in both periods was primarily due to higher crude oil prices and, to a lesser extent, higher natural gas and natural gas liquids prices. Higher prices were partially offset by higher production taxes, reduced foreign currency exchange benefits, and a benefit in the 2004 periods from Canadian tax law changes. See the Business Environment and Executive Overview section for our view of the factors that helped support crude oil and natural gas prices during the second quarter of 2005.

U.S. E&P

Net income from our U.S. E&P operations increased 44 percent in the second quarter of 2005, and 42 percent in the six-month period. Both increases reflect higher crude oil, natural gas and natural gas liquids prices. Higher prices were partially offset by increased production taxes and higher depreciation, depletion and amortization resulting from new producing fields. In addition the six-month period of 2005 reflects increased gains from asset dispositions.

U.S. E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 631,000 BOE per day in the second quarter of 2005, down slightly from 637,000 BOE per day in the second quarter of 2004. The decrease reflects unplanned maintenance, the impact of asset dispositions, and field production declines, mostly mitigated by new production from the Magnolia field in the Gulf of Mexico and increased production resulting from the Alpine expansion project on the western North Slope of Alaska.

International E&P

Net income from our international E&P operations increased 41 percent in the second quarter of 2005, and 42 percent in the six-month period. Both increases reflect higher crude oil, natural gas and natural gas liquids prices, as well as higher natural gas liquids volumes. Higher prices were partially offset by reduced foreign currency exchange benefits, a benefit in the 2004 periods from Canadian tax law changes, and increased costs associated with new production. In addition the six-month period of 2005 reflects lower gains from asset dispositions and increased maintenance costs primarily associated with a turnaround of Syncrude operations in Canada.

International E&P production averaged 885,000 BOE per day in the second quarter of 2005, down 2 percent from 906,000 BOE per day in the second quarter of 2004. Production was favorably impacted in 2005 by the Bayu-Undan field, the Hamaca project, and the Belanak field. At the Bayu-Undan field in the Timor Sea, second-quarter 2005 production was higher than in the same period of 2004 when production was still ramping up, despite a planned six-week shutdown for maintenance in the second quarter of 2005. At the Hamaca project in Venezuela, production increased in late 2004 with the startup of a heavy-oil upgrader. At the Belanak field offshore Indonesia, production began in late 2004. These increases in production were more than offset by the impact of asset dispositions, field production declines, and maintenance.

Midstream


	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
	Millions of Dollars
Net income*	$	68		42		453		97

*Includes DEFS-related net income:	$	51		33		*410*		66

Dollars Per Barrel

Average Sales Prices

U.S. natural gas liquids*

Consolidated

32.49

26.42

32.22

26.05

Equity affiliates

31.33

25.61

30.97

25.21

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

Thousands of Barrels Daily

Operating Statistics

Natural gas liquids extracted*

183

174

187

195

Natural gas liquids fractionated**

186

187

199

204

*Includes our share of equity affiliates, except LUKOIL, which is reported in the LUKOIL Investment segment.

**Excludes DEFS.

The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract natural gas liquids from the raw gas stream. The remaining “residue” gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are fractionated—separated into individual components like ethane, butane and propane—and marketed as chemical feedstock, fuel, or blendstock. The Midstream segment consists of our equity investment in Duke Energy Field Services, LLC (DEFS), as well as our other natural gas gathering and processing operations, and natural gas liquids fractionation and marketing businesses, primarily in the United States, Canada and Trinidad. Through June 30, 2005, our equity ownership in DEFS was 30.3 percent. Effective July 1, 2005, we increased our ownership interest to 50 percent.

Net income from the Midstream segment increased 62 percent in the second quarter of 2005, and 367 percent in the six-month period. The improvement in both periods reflects higher natural gas liquids prices, which resulted in improved earnings from DEFS, as well as our other Midstream operations, partially offset by asset dispositions in 2004. In addition, the six-month 2005 results included our share of a gain from DEFS’ sale of its general partnership interest in TEPPCO. Our share of this gain, reflected in equity earnings, was $306 million on an estimated after-tax basis.

On July 1, 2005, ConocoPhillips and Duke Energy Corporation (Duke) completed the restructuring of their respective ownership levels in DEFS, which resulted in DEFS becoming a jointly controlled venture, owned 50 percent by each company. This restructuring increased our ownership in DEFS to 50 percent from 30.3 percent through a series of direct and indirect transfers of certain Canadian Midstream assets from DEFS to Duke, a disproportionate cash distribution from DEFS to Duke from the sale of DEFS’ interest in TEPPCO, and a combined payment by ConocoPhillips to Duke and DEFS of approximately $840 million. This payment was approximately $230 million higher than previously anticipated as our

interest in the Empress plant in Canada was not included in the initial transaction as anticipated due to weather-related damages. However, the Empress plant was sold to Duke on August 1, 2005. We remain responsible for the repair of weather-related damages.

The restructuring is expected to have the effect of significantly reducing the favorable basis difference in our investment in DEFS which, in turn, will significantly reduce the basis difference amortization reported in equity method earnings.

R&M

Three Months Ended

Six Months Ended

June 30

2005

2004

2005

2004

Millions of Dollars

��

Net Income

United States

936

734

1,506

1,137

International

174

304

145

1,110

818

1,810

1,282

Dollars Per Gallon

U.S. Average Sales Prices*

Automotive gasoline

Wholesale

1.67

1.40

1.56

1.28

Retail

1.85

1.61

1.70

1.47

Distillates—wholesale

1.66

1.17

1.57

1.09


	Thousands of Barrels Daily
Operating Statistics
Refining operations**
United States
Rated crude oil capacity		2,182		2,168	2,178	***	2,168
Crude oil runs		2,133		2,119	2,046		2,112
Capacity utilization (percent)		98	%	98	94		97
Refinery production		2,349		2,300	2,247		2,273
International
Rated crude oil capacity		428		447	428		447
Crude oil runs		402		309	415		359
Capacity utilization (percent)		94	%	69	97		80
Refinery production		410		318	427		364
Worldwide
Rated crude oil capacity		2,610		2,615	2,606	*******	2,615
Crude oil runs		2,535		2,428	2,461		2,471
Capacity utilization (percent)		97	%	93	94		94
Refinery production		2,759		2,618	2,674		2,637

Petroleum products outside sales
United States
Automotive gasoline		1,426		1,328	1,364		1,321
Distillates		680		538	662		554
Aviation fuels		214		191	206		185
Other products		566		573	514		545

		2,886		2,630	2,746		2,605
International		477		440	486		472

		3,363		3,070	3,232		3,077


*Excludes excise taxes.

**Includes ConocoPhillips’ share of equity affiliates, except for our share of LUKOIL, which is reported in the LUKOIL Investment segment.

***Weighted-average crude oil capacity for the period. Actual capacity at June 30, 2005, was 2,182,000 and 2,610,000 barrels per day for the United States and worldwide, respectively.

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

Net income from the R&M segment increased 36 percent in the second quarter of 2005, and 41 percent in the six-month period. Both increases were primarily due to higher worldwide refining margins. See the Business Environment and Executive Overview section for our view of the factors that supported the improved refining margins during the second quarter of 2005. In addition to refining margins, R&M benefited from improved U.S. marketing margins in the second quarter of 2005, higher refinery production volumes, and net gains from asset sales. These factors were partially offset by increased maintenance turnaround costs, as well as higher utility expenses.

U.S. R&M

Net income from our U.S. R&M operations increased 28 percent in the second quarter of 2005, and 32 percent in the six-month period. Both increases mainly were the result of higher refining margins. In addition to refining margins, the U.S. R&M operations benefited from improved marketing margins and higher refinery production volumes in the second quarter of 2005. These factors were partially offset by increased maintenance turnaround costs, as well as higher utility expenses.

Our U.S. refining capacity utilization rate was 98 percent in the second quarter of 2005, the same as in the corresponding quarter of 2004. Effective April 1, 2005, we increased the crude oil processing capacity at our San Francisco refinery by 9,000 barrels per day as a result of a project implementation related to clean fuels.

International R&M

Net income from our international R&M operations increased 107 percent in the second quarter of 2005, and 110 percent in the six-month period. Both increases were primarily due to higher refining margins, as well as improved refinery production volumes and net gains on asset sales. These factors were partially offset by negative foreign currency exchange impacts.

Our international refining capacity utilization rate was 94 percent in the second quarter of 2005, compared with 69 percent in the second quarter of 2004. The second-quarter 2004 rate reflects maintenance turnarounds at most of our international refineries, whereas in 2005 only the Humber refinery was in turnaround.

LUKOIL Investment


	Millions of Dollars
	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004

Net income	$	148		—		258		—


Operating Statistics*
Net crude oil production (thousands of barrels daily)		215		—		203		—
Net natural gas production (millions of cubic feet daily)		50		—		58		—
Net refinery crude processed (thousands of barrels daily)		102		—		97		—


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

This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia, which we account for under the equity method. In October 2004, we purchased 7.6 percent of LUKOIL’s ordinary shares held by the Russian government and during the remainder of 2004, we increased our ownership interest to 10.0 percent. During the first six months of 2005, we expended $708 million to further increase our ownership interest to 12.6 percent. Purchase of LUKOIL shares continued into the third quarter.

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

Because LUKOIL’s accounting cycle close and preparation of U.S. GAAP financial statements occurs subsequent to our accounting cycle close, our equity earnings and statistics for our LUKOIL investment are an estimate, based on market indicators, historical production trends of LUKOIL, and other factors. Any difference between the estimate and actual results will be recorded in a subsequent period. This estimate-to-actual adjustment will be a recurring component of future period results. This adjustment to our estimate of LUKOIL’s fourth quarter 2004 and first quarter 2005 results in the second quarter of 2005 was not material.

Chemicals


	Millions of Dollars
	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004

Net income	$	63		46		196		85

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

Net income from the Chemicals segment increased 37 percent in the second quarter of 2005, and 131 percent in the six-month period. Results for the second quarter reflect improved ethylene and polyethylene margins and lower maintenance turnaround costs, partially offset by lower benzene margins and higher utility costs. The improved results for the six-month period was primarily due to higher ethylene and polyethylene margins, partially offset by higher utility costs.

Emerging Businesses


	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2005			2004			2005			2004

Net Income (Loss)
Technology solutions	$	(4	)		(4	)		(6	)		(8	)
Gas-to-liquids		(7	)		(7	)		(14	)		(16	)
Power		9			(16	)		11			(20	)
Other		(6	)		(2	)		(7	)		(7	)

	$	(8	)		(29	)		(16	)		(51	)

The Emerging Businesses segment includes the development of new businesses outside our traditional operations. These activities include gas-to-liquids (GTL) operations, power generation, technology solutions such as sulfur removal technologies, and emerging technologies, such as renewable fuels and emission management technologies.

The Emerging Businesses segment incurred net losses of $8 million and $16 million in the second quarter and first six months of 2005, respectively, compared with net losses of $29 million and $51 million in the corresponding periods of 2004. The improved results in both periods reflect that the Immingham power plant was fully operational throughout the first six months of 2005, but was completing construction and commissioning activities during the corresponding periods of 2004.

Corporate and Other


	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2005			2004			2005			2004

Net Income (Loss)
Net interest	$	(84	)		(143	)		(185	)		(256	)
Corporate general and administrative expenses		(46	)		(52	)		(104	)		(100	)
Discontinued operations		7			62			(4	)		75
Merger-related costs		—			—			—			(14	)
Other		(49	)		(23	)		(74	)		(38	)

	$	(172	)		(156	)		(367	)		(333	)

After-tax net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest decreased 41 percent in the second quarter of 2005, and 28 percent in the six-month period. The decreases were primarily due to lower average debt levels and an increased amount of interest income, partially offset by a lower amount of interest being capitalized in the 2005 periods.

After-tax corporate general and administrative expenses decreased 12 percent in the second quarter of 2005, while they increased 4 percent in the six-month period. The changes in both periods primarily reflect fluctuations in compensation and benefit costs.

Results from discontinued operations reflect asset dispositions completed during 2004.

Beginning with the second quarter of 2004, we no longer separately identify merger-related costs because these activities have been substantially completed.

The category “Other” consists primarily of items not directly associated with the operating segments on a stand-alone basis, including certain foreign currency transaction gains and losses, and environmental costs associated with sites no longer in operation. Results from Other were lower in both 2005 periods due to unfavorable foreign currency transactions, higher environmental accruals, and global information technology initiatives.

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators


	Millions of Dollars
	At June 30			At December 31
	2005			2004

Current ratio		1.0			1.0
Notes payable and long-term debt due within one year	$	354			632
Total debt	$	14,013			15,002
Minority interests	$	1,212			1,105
Common stockholders’ equity	$	47,300			42,723
Percent of total debt to capital*		22	%		26
Percent of floating-rate debt to total debt		13	%		19


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

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, primarily cash generated from operating activities. During the first six months of 2005, available cash was used to support our ongoing capital expenditures and investments program, repay debt, pay dividends and repurchase shares of our common stock. Total dividends paid on our common stock during the first six months were $780 million. During the first six months of 2005, cash and cash equivalents increased $154 million to $1.5 billion.

In addition to cash flows from operating activities, we also rely on our cash balance, commercial paper and credit facility programs, and our $5 billion universal shelf registration statement, to support our short- and long-term liquidity requirements. We anticipate that these sources of liquidity will be adequate to meet our funding requirements through 2006, including our capital spending program and required debt payments.

Significant Sources of Capital

Operating Activities

During the first six months of 2005, cash from operating activities totaled $6,857 million, compared with cash from operations of $4,349 million in the corresponding period of 2004. This 58 percent increase correlates with the 67 percent increase in income from continuing operations over the same time periods. The percentage increase in cash from operations was somewhat lower than income from continuing operations due to higher non-cash items included in earnings in 2005, primarily undistributed equity earnings. After excluding these non-cash items, cash from operations was higher in 2005 primarily due to higher crude oil, natural gas and natural gas liquid prices, as well as improved worldwide refining margins.

Our cash flows from operating activities, for both the short- and long-term, are highly dependent upon prices for crude oil, natural gas and natural gas liquids, as well as refining and marketing margins. During the first six months of 2005 and the year 2004, we benefited from favorable crude oil and natural gas prices, as well as strong refining margins. The sustainability of these prices and margins are driven by market conditions over which we have no control. In addition, the level of our production volumes of crude oil, natural gas and natural gas liquids also impacts our cash flows. These production levels are impacted by such factors as acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiency, the addition of proved reserves through exploratory success, and the timely and cost-effective development of those proved reserves.

Asset Sales

During the first six months of 2005, proceeds from asset sales were $308 million, compared with asset sales in the same period of 2004 of $1,354 million, which were related to our asset disposition program that began following the merger in late August of 2002 between Conoco and Phillips. While we will continue to have modest asset disposition activity, this asset disposition program was essentially completed at the end of the second quarter of 2004. Proceeds from these asset sales were used primarily to repay debt.

Commercial Paper and Credit Facilities

While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our operating cash flows remain exposed to the volatility of commodity crude oil and natural gas prices and refining and marketing margins, as well as periodic cash needs to finance tax payments and crude oil, natural gas and petroleum product purchases. Our primary funding source for short-term working capital needs is a $5 billion commercial paper program, a portion of which may be denominated in other currencies (limited to euro 3 billion equivalent). Commercial paper maturities are generally limited to 90 days. At June 30, 2005, we had no commercial paper outstanding, compared with $544 million of commercial paper outstanding at December 31, 2004.

At June 30, 2005, we had two revolving credit facilities totaling $5 billion. The two facilities included a $2.5 billion four-year facility expiring in October 2008 and a $2.5 billion five-year facility expiring in October 2009. Both facilities are available for use as direct bank borrowings or as support for our $5 billion commercial paper program. In addition, the five-year facility may be used to support issuances of letters of credit totaling up to $750 million. The facilities are broadly syndicated among financial institutions and do not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The credit agreements do contain a cross-default provision relating to our, or any of our consolidated subsidiaries’, failure to pay principal or interest on other debt obligations of $200 million or more. There were no outstanding borrowings under these facilities at June 30, 2005.

Based on having no commercial paper outstanding and having issued $62 million of letters of credit, we had access to $4.9 billion in borrowing capacity under the two revolving credit facilities as of June 30, 2005, which provides liquidity to cover daily operations. In addition, at June 30, 2005, our $1.5 billion cash balance and $1.2 billion of capacity related to our receivables monetization program also supported our liquidity position.

Shelf Registration

In late 2002, we filed a universal shelf registration statement with the U.S. Securities and Exchange Commission for various types of debt and equity securities. As a result, we have available to issue and sell a total of $5 billion of various types of securities under the universal shelf registration statement.

Minority Interests

At June 30, 2005, we had outstanding $1,212 million of equity in less than wholly owned consolidated subsidiaries held by minority interest owners, including a minority interest of $505 million in Ashford Energy Capital S.A. The remaining minority interest amounts are primarily related to controlled-operating joint ventures with minority interest owners. The largest of these, $640 million, was related to the Bayu-Undan liquefied natural gas project in the Timor Sea and northern Australia.

Off-Balance Sheet Arrangements

Receivables Monetization

By January 31, 2005, all of the beneficial interests held by the bank-sponsored entities had matured; therefore, in accordance with SFAS No. 140, the operating results and cash flows of the QSPE subsequent to this maturity have been consolidated with our financial statements, and the assets and liabilities of the QSPE are included in our June 30, 2005, balance sheet. The revolving-period securitization arrangement expires in September 2005, and at this time we have no plans to renew the arrangement. See Note 16—Sales of Receivables, in the Notes to Consolidated Financial Statements, for additional information.

Capital Requirements

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

Our balance sheet debt at June 30, 2005, was $14 billion. This reflects debt reductions of approximately $1 billion during the first six months of 2005. The decline in debt primarily resulted from a reduction of $544 million in our commercial paper balance to zero at June 30, 2005, and the redemption in late March of our $400 million 3.625% Notes due 2007, at par plus accrued interest. In conjunction with the redemption, $400 million of interest rate swaps were cancelled. Going forward, we have no significant mandatory debt retirements until payment of the $1,250 million aggregate principal amount of our 5.45% Notes due in 2006, at maturity.

On February 4, 2005, we announced a stock repurchase program that provides for the repurchase of up to $1 billion of the company’s common stock over a period of up to two years. The program will serve as a means of limiting dilution to shareholders from the company’s stock-based compensation programs. Acquisitions for the share repurchase program will be made at management’s discretion at prevailing prices, subject to market conditions and other factors. Purchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan will be held as treasury shares. During the first six months of 2005, we repurchased 10.7 million shares of our common stock under this program at a cost of $576 million.

In April 2005, we announced a quarterly dividend of 62 cents per share, payable June 1, 2005, to stockholders of record as of May 16, 2005. This represented a 24 percent increase in the dividend for our common stock over the previous quarter’s dividend of 50 cents per share. This quarterly dividend applied to shares held on the record date before giving effect to the 2-for-1 stock split also announced in April. See Note 3—Common Stock Split, in the Notes to the Consolidated Financial Statements, for additional information about the stock split.

In July 2004, we announced the finalization of our transaction with Freeport LNG Development, L.P. (Freeport LNG) to participate in a proposed LNG receiving terminal in Quintana, Texas. Construction began in early 2005. We do not have an ownership interest in the facility, but we do have a 50 percent interest in the general partnership managing the venture, along with contractual rights to regasification capacity of the terminal. We entered into a credit agreement with Freeport LNG, whereby we will provide loan financing of approximately $600 million for the construction of the facility. Through June 30, 2005, we had provided $105 million in loan financing.

Anticipated production from the joint venture with LUKOIL in the Timan-Pechora province of Russia is expected to be transported via pipeline to LUKOIL’s existing terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international markets. LUKOIL is expected to complete an expansion of the terminal capacity in 2007, with ConocoPhillips participating in the design and financing of the terminal expansion. We have an obligation to provide loan financing to Varandey Terminal Company for 30 percent of the costs of the terminal expansion, but we will have no governance interest in the terminal. Through June 30, 2005, we had provided $26 million in loan financing.

We account for our loans to Freeport LNG and Varandey Terminal Company as financial assets in the “Investments and long-term receivables” line on the balance sheet.

Contractual Obligations

Our contractual purchase obligations at June 30, 2005, are estimated to be $74 billion, an increase of $7 billion from the amount reported at December 31, 2004, of $67 billion. The majority of the increase results from higher purchase obligations within our Commercial crude oil trading organization, reflecting both higher purchase volume commitments, as well as higher commodity prices.

Capital Spending

Capital Expenditures and Investments


	Millions of Dollars
	Six Months Ended
	June 30
	2005		2004

E&P
United States—Alaska	$	358		324
United States—Lower 48		540		290
International		2,645		1,835

		3,543		2,449

Midstream		1		5

R&M
United States		563		365
International		72		128

		635		493

LUKOIL Investment		708		—
Chemicals		—		—
Emerging Businesses		3		55
Corporate and Other*		57		63

	$	4,947		3,065

United States	$	1,518		1,047
International		3,429		2,018

	$	4,947		3,065

Discontinued operations	$	—		1


*Excludes discontinued operations.

E&P

UNITED STATES

Alaska

During the first six months of 2005, we continued development drilling in the Greater Kuparuk Area, the Greater Prudhoe Area, the Alpine field and the West Sak development. We continued work on the construction of Alpine’s first satellite fields, Nanuq and Fiord, the startup of which is expected in the fourth quarter of 2006. In addition, the Alpine Capacity Expansion-Phase II project was completed in June.

During the first half of 2005, we and our co-venturers in the Trans-Alaska Pipeline System continued a project, which began in 2004, to upgrade the pipeline’s pump stations. This project is anticipated to be complete in 2006.

Lower 48 States

In the Lower 48, capital expenditures during the first half of 2005 included the acquisition of limited-term, fixed-volume overriding royalty interests in Utah and the San Juan Basin related to our production. These acquisitions are expected to have a positive but otherwise insignificant impact to production. In addition, Lower 48 capital expenditures were focused on the completion of Magnolia wells in the deepwater Gulf of Mexico and development of natural gas reserves within core areas, including the San Juan Basin of New Mexico and the Lobo Trend of South Texas.

CANADA

During the first six months of 2005, we continued with the development of our Surmont heavy-oil project and on the development of the Syncrude Stage III expansion-mining project in the Canadian province of Alberta, where an upgrader expansion project is expected to be fully operational in the second quarter of 2006. In April 2005, we exercised our right of first refusal to acquire an additional 6.5 percent interest in Surmont, increasing our interest to 50 percent. We will remain the operator of the project. The acquisition was completed in the second quarter of 2005.

NORTHWEST EUROPE

In the U.K. and Norwegian sectors of the North Sea, funds were invested during the six-month 2005 period for development of the Britannia satellite fields, Callanish and Brodgar, where production is expected in 2007; the Ekofisk Area growth project, where production is expected in the fourth quarter of 2005; and the Alvheim project, where production is scheduled to begin in 2007.

RUSSIA AND CASPIAN SEA

Russia

In June 2005, we invested funds of $512 million to acquire a 30 percent economic interest and a 50 percent voting interest in OOO Naryanmarneftegaz (NMNG), a joint venture with LUKOIL to explore for and develop oil and gas resources in the northern part of Russia’s Timan-Pechora province.

Caspian Sea

In the six-month 2005 period, we continued to participate in construction activities to develop the Kashagan field on the Kazakhstan shelf in the North Caspian Sea. In March 2005, agreement was reached with the Republic of Kazakhstan government to conclude the sale of B.G. International’s interest in the North Caspian Production Sharing Agreement to several of the remaining partners and for the subsequent sale of one-half of the acquired interests to KazMunayGas. This agreement increased our ownership interest from 8.33 percent to 9.26 percent.

ASIA PACIFIC

Timor Sea

In the Timor Sea, we continued with final development activities associated with Phase I of the Bayu-Undan gas recycle project, where condensate and natural gas liquids are separated and removed and the dry gas is re-injected into the reservoir. Production of liquids began from Phase I in February of 2004, and development drilling concluded at the end of March 2005.

Construction activities continued in 2005 for Phase II, the development of a liquefied natural gas (LNG) plant near Darwin, Australia, as well as a gas pipeline from Bayu-Undan to the LNG facility. The LNG project was approximately 86 percent complete at the end of the first six months of 2005. The first LNG cargo from the facility is scheduled for delivery in early 2006.

Indonesia

During the first half of 2005, we continued to invest funds on the development of the Belanak, Kerisi and Hiu fields in the South Natuna Sea Block B. Oil production at Belanak began in late 2004. The commissioning of gas plant facilities on the Belanak floating production, storage and offloading facility (FPSO) continued in June, resulting in first condensate production. In South Sumatra, we continued with the development of the Suban Phase II project, which is an expansion of the existing Suban gas plant.

China

Following developmental approval from the Chinese government in early 2005, we began development of Phase II of the Peng Lai 19-3 oil field, as well as concurrent development of the nearby 25-6 field. The development of Peng Lai 19-3 and Peng Lai 25-6 will include multiple wellhead platforms and a larger FPSO.

Vietnam

In early 2005, we began preliminary engineering for the Su Tu Vang development. The Su Tu Vang field is in Vietnam’s Block 15-1, near our producing Su Tu Den field.

At our producing Rang Dong field on Block 15-2, we continued work during 2005 on the development of the central part of the field, where two additional platforms and additional production and injection wells were added. First production began in the second quarter.

R&M

In the United States, we continued to expend funds related to clean fuels, safety and environmental projects during the first half of 2005, including investing in a new diesel hydrotreater at the Rodeo facility of our San Francisco refinery. This hydrotreater began operation at the end of March 2005. The new diesel hydrotreater provides the capability to produce reformulated California highway diesel over one year ahead of the June 2006 deadline.

Internationally, we continued to invest in our ongoing refining and marketing operations, including marketing growth in select countries in Europe and Asia.

LUKOIL Investment

During the first six months of 2005, we increased our ownership interest in LUKOIL to 12.6 percent at June 30, 2005, from 10.0 percent at December 31, 2004. Purchase of LUKOIL shares continued into the third quarter.

Contingencies

Legal and Tax Matters

We accrue for contingencies when a loss is probable and amounts can be reasonably estimated. Based on currently available information, we believe that it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our financial statements.

Environmental

We are subject to the same numerous international, federal, state, and local environmental laws and regulations, as other companies in the petroleum exploration and production industry; and refining, marketing and transportation of crude oil and refined products businesses. The most significant of these environmental laws and regulations include, among others, the:

•

Federal Clean Air Act, which governs air emissions.

	•		Federal Clean Water Act, which governs discharges to water bodies.

	•		Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability on generators, transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatened to occur.

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

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

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

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

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

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

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

At RCRA permitted facilities, we are required to assess environmental conditions. If conditions warrant, we may be required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as “Superfund,” the cost of corrective action activities under RCRA corrective action programs typically is borne solely by us. Over the next decade, we anticipate that significant ongoing expenditures for RCRA remediation activities may be required, but such annual expenditures for the near term are not expected to vary significantly from the range of such expenditures we have experienced over the past few years. Longer term, expenditures are subject to considerable uncertainty and may fluctuate significantly.

From time to time, we receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2004, we reported we had been notified of potential liability under CERCLA and comparable state laws at 64 sites around the United States. At June 30, 2005, we had resolved 3 of these sites, reclassified 1 site as unresolved, and had received 4 new notices of potential liability, leaving 66 unresolved sites where we have been notified of potential liability.

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

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

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

Remediation Accruals

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

Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we have identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA. Considerable uncertainty exists with respect to these costs, and under adverse changes in circumstances, potential liability may exceed amounts accrued as of June 30, 2005.

Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.

At June 30, 2005, our balance sheet included a total environmental accrual of $1,020 million, compared with $1,061 million at December 31, 2004. We expect to incur a substantial majority of these expenditures within the next 30 years.

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

NEW ACCOUNTING STANDARDS AND EMERGING ISSUES

New Accounting Standards

In June 2005, the Financial Accounting Standards Board (FASB) ratified Emerging Issues Task Force (EITF) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.” Issue No. 04-5 adopts a framework for evaluating whether the general partner (or general partners as a group) controls the partnership. The framework makes it more likely that a single general partner (or a general partner within a general partner group) would have to consolidate the limited partnership regardless of its ownership in the limited partnership. The new guidance was effective upon ratification for all newly-formed limited partnerships and for existing limited partnership agreements that are modified. The guidance is effective January 1, 2006, for existing limited partnership agreements that are not modified. We are reviewing Issue No. 04-5 to determine the impact, if any, on our financial statements.

In May 2005, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3.” Among other changes, this Statement requires retrospective application for voluntary changes in accounting principle, unless it is impractical to do so. Guidance is provided on how to account for changes when retrospective application is impractical. This Statement is effective on a prospective basis beginning January 1, 2006.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). This Interpretation clarifies that an entity is required to recognize a liability for a legal obligation to perform asset retirement activities when the retirement is conditional on a future event and if the liability’s fair value can be reasonably estimated. If the liability’s fair value cannot be reasonably estimated, then the entity must disclose (a) a description of the obligation, (b) the fact that a liability has not been recognized because the fair value cannot be reasonably estimated, and (c) the reasons why the fair value cannot be reasonably estimated. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. We are required to implement this Interpretation in the fourth quarter of 2005. We are studying the provisions of this Interpretation to determine the impact, if any, on our financial statements.

In December 2004, the FASB issued SFAS No. 153, “Exchange of Nonmonetary Assets, an amendment of APB Opinion No. 29.” This amendment eliminates the Accounting Principles Board (APB) Opinion No. 29

exception for fair value recognition of nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges of nonmonetary assets that do not have commercial substance. This Statement is effective on a prospective basis beginning July 1, 2005.

Also in December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment,” (SFAS 123(R)), which supercedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” that we adopted at the beginning of 2003. SFAS 123(R) prescribes the accounting for a wide range of share-based compensation arrangements, including share options, restricted share plans, performance-based awards, share appreciation rights, and employee share purchase plans, and generally requires the fair value of share-based awards to be expensed in the income statement. For ConocoPhillips, this Statement provided for an effective date of third-quarter 2005; however, the Securities and Exchange Commission approved a new rule that delayed the effective date until January 1, 2006. We plan to adopt the provisions of this Statement January 1, 2006. We are studying the provisions of this new pronouncement to determine the impact, if any, on our financial statements. For more information on our adoption of SFAS No. 123 and its effect on net income, see Note 2—Accounting Policies, in the Notes to Consolidated Financial Statements.

Emerging Issues

OUTLOOK

E&P’s production for the full year 2005 is expected to be approximately 3 percent higher than the amount produced in 2004. E&P’s production for the third quarter of 2005 is expected to be higher than its second-quarter level, primarily due to a lower level of scheduled maintenance at Bayu-Undan and in Norway, and continued increase from new projects in the Lower 48, Venezuela and Indonesia. Actual production increases from quarter-to-quarter and year-to-year may vary due to the timing of maintenance work, individual project ramp-ups, unscheduled downtime, reservoir performance, price impacts of production sharing contracts and other factors. These projections exclude amounts related to our Canadian Syncrude operations, and the impact of our equity investment in LUKOIL.

We have received correspondence from the Venezuelan Ministry of Energy and Petroleum regarding the royalty and production applicable to our heavy oil projects. We believe we are, and continue to be, in compliance with the contractual terms related to production and payment of royalties from our heavy oil project. We continue to work closely with the Venezuelan government on any potential impacts to our heavy oil projects in Venezuela.

In February 2003, the Venezuelan government implemented a currency exchange control regime. The government has published legal instruments supporting the controls, one of which establishes official exchange rates for the U.S. dollar. The devaluation of the Venezuelan currency by approximately 11 percent in March 2005 did not have a significant impact on our Venezuelan operations; however, future changes in the exchange rate could have a significant impact on our Venezuelan operations.

In March 2005, a development plan addendum for Phase I of the Corocoro field in the Gulf of Paria was approved by the Venezuelan government. This addendum addressed revisions to the original development plan approved in 2003.

Because of delays pertaining to access and related regulatory matters, the Mackenzie Gas Project co-venturers have elected to halt selected data collection, engineering and preliminary contracting work. Near term efforts will be focused on finalizing benefits and access agreements and firming up the regulatory process and schedule. As a result, we expect first production from the project to be deferred beyond the 2009 time frame.

During the first quarter of 2005, we announced that the PETRONAS Carigali-ConocoPhillips joint venture had signed a production sharing contract with PETRONAS, the Malaysian national oil company, for the appraisal and development of the Kebabangan oil field, offshore Sabah, Malaysia. We will have a 40 percent interest in the Kebabangan field. The Kebabangan appraisal represents an opportunity for us to build upon previously announced exploration success in deepwater blocks G and J, offshore Sabah.

In December 2003, we signed a Statement of Intent with Qatar Petroleum regarding the construction of a gas-to-liquids (GTL) plant in Ras Laffan, Qatar. Preliminary engineering and design studies have been completed. In April 2005, the Qatar Minister of Petroleum stated that there would be a postponement of new GTL projects in order to further study impacts on infrastructure, shipping and contractors, and to ensure that the development of its gas resources occurs at a sustainable rate. As a result, we continue to work with Qatar authorities on the appropriate timing of the project to ensure that the development meets Qatar’s and our objectives.

In R&M, we expect our average refinery crude oil utilization rate for the third quarter to be in the high 90 percent range.

Also in R&M, in addition to our announced capital program, we are planning to spend an additional $3 billion over the period 2006 through 2010 to increase our refining system’s ability to process heavy-sour crude oil and other low-quality feedstocks. These investments, primarily domestic, are expected to incrementally increase refining capacity and clean products yield at our existing facilities, while providing competitive returns.

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

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

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

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

	•		Changes in our business, operations, results and prospects.

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

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

	•		Unsuccessful exploratory drilling activities.

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

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

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

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

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

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

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

	•		International monetary conditions and exchange controls.

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

	•		Liability resulting from litigation.

	•		General domestic and international economic and political conditions, including armed hostilities and governmental disputes over territorial boundaries.

	•		Changes in tax and other laws, regulations or royalty rules applicable to our business.

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

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

With the exception of the item described below, information about market risks for the six months ended June 30, 2005, does not differ materially from that discussed under Item 7A of ConocoPhillips’ Annual Report on Form 10-K for the year ended December 31, 2004.

In June 2005, we acquired limited-term, fixed-volume overriding royalty interests in Utah and the San Juan Basin related to our production. As part of the acquisition, we assumed related commodity swaps with a negative fair value of $261 million at June 30, 2005. In late June and early July, we entered into additional commodity swaps to offset most of the exposure from the assumed swaps.

Item 4. CONTROLS AND PROCEDURES

As of June 30, 2005, with the participation of our management, our Chairman, President and Chief Executive Officer and our Executive Vice President, Finance, and Chief Financial Officer carried out an evaluation of the effectiveness of the design and operation of ConocoPhillips’ disclosure controls and procedures pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended. Based upon that evaluation, our Chairman, President and Chief Executive Officer and our Executive Vice President, Finance, and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of June 30, 2005.

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

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the second quarter of 2005 and any material developments with respect to those matters previously reported in ConocoPhillips’ 2004 Form 10-K and 2005 first quarter Form 10-Q. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to the U.S. Securities and Exchange Commission’s regulations.

In June 2005, the South Coast Air Quality Management District (SCAQMD) notified us of their intent to seek civil penalties in the amount of $401,000 for 18 alleged violations of various SCAQMD regulations at our Los Angeles Refinery in Wilmington and Carson, California and one of our tank facilities in Torrance, California. We are currently assessing these allegations and expect to work with the SCAQMD towards a resolution of this matter.

In July 2004, Polar Tankers, Inc. notified the U.S. Coast Guard of possible environmental violations onboard the vessel Polar Discovery. On June 29, 2005, the U.S. Attorney’s office in Anchorage issued a subpoena for records to Polar Tankers regarding the possible environmental violations onboard that vessel. We are fully cooperating with the governmental authorities in their investigation.

On March 2, 2004, the Bay Area Air Quality Management District (BAAQMD) notified us of their intent to seek civil penalties in the amount of $750,000 for 17 alleged violations of various BAAQMD regulations at our Rodeo facility and carbon plant located in the San Francisco area. Since that time, we have worked with the BAAQMD to resolve these and subsequent alleged violations. In May 2005, we entered into a settlement with the BAAQMD to resolve the alleged violations and paid a civil penalty of $419,000.

In December 2004, the San Luis Obispo Air Pollution Control District (SLOAPCD) notified us of their intent to seek civil penalties in the amount of $2,700,000 for alleged violations of various SLOAPCD regulations at the Santa Maria facility of our San Francisco refinery. During May 2005, we agreed in principle to settle the alleged violations by funding $675,000 for supplemental environmental projects and paying a $225,000 civil penalty to the SLOAPCD.

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

Issuer Purchases of Equity Securities


					Total Number of		Millions of Dollars
					Shares Purchased		Approximate Dollar
					as Part of Publicly		Value that May Yet
	Total Number of		Average Price		Announced Plans		Be Purchased Under
Period	Shares Purchased*		Paid per Share		or Programs**		the Plans or Programs

April 1-30, 2005		1,770,686	$	53.46		1,760,000	$	680
May 1-31, 2005		2,214,568		51.41		2,200,000		567
June 1-30, 2005		2,525,217		56.93		2,510,000		424

Total		6,510,471	$	54.11		6,470,000


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

**		On February 4, 2005, we announced a stock repurchase program that provides for the repurchase of up to $1 billion of the company’s common stock over a period of up to two years. The program will serve as a means of limiting dilution to shareholders from the company’s stock-based compensation programs. Acquisitions for the share repurchase program will be made at management’s discretion at prevailing prices, subject to market conditions and other factors. Purchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares.

Note: Per-share amounts and number of shares in all periods reflect a two-for-one stock split effected as a 100 percent stock dividend on June 1, 2005.

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

We held our annual stockholders meeting on May 5, 2005. A brief description of each proposal and the voting results follow:

A company proposal to elect four directors.


			Withheld
	For		or Against
Norman R. Augustine		629,634,898		12,519,426
Larry D. Horner		613,129,035		29,025,289
Charles C. Krulak		630,145,712		12,008,612
J. J. Mulva		622,103,463		20,050,861

Those directors whose term of office continued were as follows: Richard H. Auchinleck, James E. Copeland, Kenneth M. Duberstein, Ruth R. Harkin, William K. Reilly, William R. Rhodes, J. Stapleton Roy, Victoria J. Tschinkel and Kathryn C. Turner.

A company proposal to ratify the appointment of Ernst & Young LLP as ConocoPhillips’ independent registered public accounting firm for 2005.


For			629,906,085
Against			7,286,074
Abstentions			4,962,078
Broker Non-Votes			87

A shareholder proposal to replace the current system of compensation for senior executives.


For			51,338,513
Against			510,681,552
Abstentions			9,121,405
Broker Non-Votes			71,012,854

A shareholder proposal to amend the ConocoPhillips’ governance documents to provide that director nominees shall be elected by the affirmative vote of the majority of votes cast at an annual meeting of shareholders.


For			276,887,565
Against			285,192,224
Abstentions			9,062,378
Broker Non-Votes			71,012,157

All four nominated directors were elected and the appointment of the independent auditors was ratified. The two shareholder proposals were not ratified.

Item 6. EXHIBITS

Exhibits

12		Computation of Ratio of Earnings to Fixed Charges.

31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

32		Certifications pursuant to 18 U.S.C. Section 1350.

SIGNATURE

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


		CONOCOPHILLIPS

		/s/ Rand C. Berney

		Rand C. Berney
		Vice President and Controller
		(Chief Accounting and Duly Authorized Officer)

August 3, 2005

Index to Exhibits

Exhibits

12		Computation of Ratio of Earnings to Fixed Charges.

31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

32		Certifications pursuant to 18 U.S.C. Section 1350.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	8th grade Avg

ConocoPhillips (COP) 10-Q2005 Q2 Quarterly report

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