ConocoPhillips (COP) 10-Q 2008 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 ended June 30, 2008

or

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

For the transition period from                           to                          

Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

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

600 North Dairy Ashford, Houston, TX 77079

(Address of principal executive offices) (Zip Code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ Accelerated filer o  Non-accelerated filer o Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o     No þ

The registrant had 1,519,804,610 shares of common stock, $.01 par value, outstanding at June 30, 2008.

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		22
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
Item 3. Quantitative and Qualitative Disclosures About Market Risk		52
Item 4. Controls and Procedures		52
Part II — Other Information
Item 1. Legal Proceedings		53
Item 1A. Risk Factors		55
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		55
Item 4. Submission of Matters to a Vote of Security Holders		56
Item 6. Exhibits		57
Signature		58
Amended and Restated Certificate of Incorporation
Amended and Restated By-Laws
First and Second Amendments to Director's Charitable Gift Program
Computation of Ratio of Earnings to Fixed Charges
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Certifications Pursuant to Section 1350

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

Consolidated Income Statement ConocoPhillips

	Millions of Dollars
	Three Months Ended					Six Months Ended
	June 30					June 30
	2008		2007			2008			2007
Revenues and Other Income
Sales and other operating revenues*	$	71,411		47,370			126,294			88,690
Equity in earnings of affiliates		1,812		1,506			3,171			2,435
Other income		130		521			440			1,139
Total Revenues and Other Income		73,353		49,397			129,905			92,264
Costs and Expenses
Purchased crude oil, natural gas and products		51,214		30,820			89,034			57,535
Production and operating expenses		3,111		2,557			5,802			5,049
Selling, general and administrative expenses		629		604			1,155			1,131
Exploration expenses		288		259			597			521
Depreciation, depletion and amortization		2,178		2,016			4,387			4,040
Impairment—expropriated assets		—		4,588			—			4,588
Impairments		19		98			25			97
Taxes other than income taxes*		5,796		4,697			10,951			9,071
Accretion on discounted liabilities		96		81			200			160
Interest and debt expense		210		319			417			626
Foreign currency transaction gains		—		(179	)		(43	)		(178	)
Minority interests		17		19			36			40
Total Costs and Expenses		63,558		45,879			112,561			82,680
Income before income taxes		9,795		3,518			17,344			9,584
Provision for income taxes		4,356		3,217			7,766			5,737
Net Income	$	5,439		301			9,578			3,847
Net Income Per Share of Common Stock(dollars)
Basic	$	3.54		.18			6.18			2.34
Diluted		3.50		.18			6.11			2.31
Dividends Paid Per Share of Common Stock(dollars)	$	.47		.41			.94			.82
Average Common Shares Outstanding(in thousands)
Basic		1,534,975		1,635,848			1,548,587			1,641,569
Diluted		1,555,447		1,657,999			1,568,867			1,663,618
* Includes excise taxes on petroleum products sales:	$	4,091		4,069			7,948			7,910

See Notes to Consolidated Financial Statements.

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Consolidated Balance Sheet ConocoPhillips

	Millions of Dollars
	June 30			December 31
	2008			2007
Assets
Cash and cash equivalents	$	787			1,456
Accounts and notes receivable (net of allowance of $62 million in 2008 and $58 million in 2007)		17,474			14,687
Accounts and notes receivable—related parties		2,987			1,667
Inventories		6,757			4,223
Prepaid expenses and other current assets		5,510			2,702
Total Current Assets		33,515			24,735
Investments and long-term receivables		33,814			31,457
Loans and advances—related parties		1,981			1,871
Net properties, plants and equipment		89,990			89,003
Goodwill		29,227			29,336
Intangibles		873			896
Other assets		755			459
Total Assets	$	190,155			177,757
Liabilities
Accounts payable	$	21,319			16,591
Accounts payable—related parties		2,042			1,270
Short-term debt		385			1,398
Accrued income and other taxes		6,699			4,814
Employee benefit obligations		681			920
Other accruals		3,721			1,889
Total Current Liabilities		34,847			26,882
Long-term debt		21,539			20,289
Asset retirement obligations and accrued environmental costs		7,330			7,261
Joint venture acquisition obligation—related party		5,985			6,294
Deferred income taxes		21,044			21,018
Employee benefit obligations		3,043			3,191
Other liabilities and deferred credits		2,825			2,666
Total Liabilities		96,613			87,601
Minority Interests		1,144			1,173
Common Stockholders’ Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2008—1,727,212,141 shares; 2007—1,718,448,829 shares)
Par value		17			17
Capital in excess of par		43,261			42,724
Grantor trusts (at cost: 2008—42,397,731 shares; 2007—42,411,331 shares)		(716	)		(731	)
Treasury stock (at cost: 2008—165,009,800 shares; 2007—104,607,149 shares)		(12,978	)		(7,969	)
Accumulated other comprehensive income		4,304			4,560
Unearned employee compensation		(115	)		(128	)
Retained earnings		58,625			50,510
Total Common Stockholders’ Equity		92,398			88,983
Total	$	190,155			177,757

See Notes to Consolidated Financial Statements.

2

Consolidated Statement of Cash Flows ConocoPhillips

	Millions of Dollars
	Six Months Ended
	June 30
	2008			2007
Cash Flows From Operating Activities
Net income	$	9,578			3,847
Adjustments to reconcile net income to net cash provided by operating activities
Nonworking capital adjustments
Depreciation, depletion and amortization		4,387			4,040
Impairment—expropriated assets		—			4,588
Impairments		25			97
Dry hole costs and leasehold impairments		281			281
Accretion on discounted liabilities		200			160
Deferred taxes		11			180
Undistributed equity earnings		(1,988	)		(1,235	)
Gain on asset dispositions		(213	)		(927	)
Other		(81	)		88
Working capital adjustments*
Decrease (increase) in accounts and notes receivable		(3,625	)		210
Increase in inventories		(2,537	)		(271	)
Decrease (increase) in prepaid expenses and other current assets		(2,349	)		285
Increase in accounts payable		5,481			1,097
Increase (decrease) in taxes and other accruals		2,851			(801	)
Net Cash Provided by Operating Activities		12,021			11,639
Cash Flows From Investing Activities
Capital expenditures and investments		(6,720	)		(5,347	)
Proceeds from asset dispositions		441			2,215
Long-term advances/loans—related parties		(154	)		(326	)
Collection of advances/loans—related parties		4			66
Other		7			19
Net Cash Used in Investing Activities		(6,422	)		(3,373	)
Cash Flows From Financing Activities
Issuance of debt		2,065			765
Repayment of debt		(1,841	)		(5,121	)
Issuance of company common stock		185			181
Repurchase of company common stock		(5,008	)		(2,000	)
Dividends paid on company common stock		(1,449	)		(1,342	)
Other		(240	)		(153	)
Net Cash Used in Financing Activities		(6,288	)		(7,670	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		20			(2	)
Net Change in Cash and Cash Equivalents		(669	)		594
Cash and cash equivalents at beginning of period		1,456			817
Cash and Cash Equivalents at End of Period	$	787			1,411

*Net of acquisition and disposition of businesses.

See Notes to Consolidated Financial Statements.

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Notes to Consolidated Financial Statements ConocoPhillips

Note 1—Interim Financial Information

The interim-period financial information presented in the financial statements included in this report is unaudited and includes all known accruals and adjustments, in the opinion of management, necessary for a fair presentation of the consolidated financial position of ConocoPhillips and its results of operations and cash flows for such periods. All such adjustments are of a normal and recurring nature. To enhance your understanding of these interim financial statements, see the consolidated financial statements and notes included in our 2007 Annual Report on Form 10-K.

Note 2—Changes in Accounting Principles

SFAS No. 157

Effective January 1, 2008, we implemented Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for its measurement and expands disclosures about fair value measurements. We elected to implement this Statement with the one-year deferral permitted by FASB Staff Position (FSP) 157-2 for nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis (at least annually). The deferral applies to nonfinancial assets and liabilities measured at fair value in a business combination; impaired properties, plants and equipment; intangible assets and goodwill; and initial recognition of asset retirement obligations and restructuring costs for which we use fair value. We do not expect any significant impact to our consolidated financial statements when we implement SFAS No. 157 for these assets and liabilities.

Due to our election under FSP 157-2, for 2008, SFAS No. 157 applies to commodity and foreign currency derivative contracts and certain nonqualified deferred compensation and retirement plan assets that are measured at fair value on a recurring basis in periods subsequent to initial recognition. The implementation of SFAS No. 157 did not cause a change in the method of calculating fair value of assets or liabilities, with the exception of incorporating the impact of our nonperformance risk on derivative liabilities—which was not material. The primary impact from adoption was additional disclosures.

SFAS No. 157 requires disclosures that categorize assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting our assumptions about pricing by market participants.

We value our exchange-cleared derivatives using unadjusted closing prices provided by the exchange as of the balance sheet date, and these are classified as Level 1 in the fair value hierarchy. Over the counter (OTC) financial swaps and physical commodity purchase and sale contracts are generally valued using quotations provided by brokers and price index developers such as Platts and Oil Price Information Service. These are classified as Level 2. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC swaps and physical commodity purchase and sale contracts are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3.

Exchange-cleared financial options are valued using exchange closing prices and are classified as Level 1. Financial OTC and physical commodity options are valued using industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and

4

contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to which these inputs are observable in the forward markets determines whether the option is classified as Level 2 or 3.

As permitted under SFAS No. 157, we use a mid-market pricing convention (the mid-point price between bid and ask prices). When appropriate, valuations are adjusted to reflect credit considerations, generally based on available market evidence.

The fair value hierarchy for our financial assets and liabilities accounted for at fair value on a recurring basis at June 30, 2008, was:

	Millions of Dollars
	Level 1			Level 2			Level 3			Total
Assets
Commodity derivatives	$	7,990			4,310			40			12,340
Foreign exchange derivatives		—			50			—			50
Nonqualified benefit plans		412			—			—			412
Total assets		8,402			4,360			40			12,802
Liabilities
Commodity derivatives		(7,887	)		(4,565	)		(96	)		(12,548	)
Foreign exchange derivatives		—			(43	)		—			(43	)
Total liabilities		(7,887	)		(4,608	)		(96	)		(12,591	)
Net assets (liabilities)	$	515			(248	)		(56	)		211

The derivative values above are based on analysis of each contract as the fundamental unit of account as required by SFAS No. 157. Derivative assets and liabilities with the same counterparty are not netted where the legal right of offset exists, which is different than the net presentation basis in Note 13—Financial Instruments and Derivative Contracts. Gains or losses from contracts in one level may be offset by gains or losses on contracts in another level or by changes in values of physical contracts or positions that are not reflected in the table above.

5

Changes in the fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy during the three- and six-month periods ended June 30, 2008, were:

	Millions of Dollars
	Three Months Ended			Six Months Ended
	June 30			June 30
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Beginning balance	$	(53	)		(34	)
Total gains (losses), realized and unrealized
Included in earnings		(11	)		(53	)
Included in other comprehensive income		—			—
Purchases, issuances and settlements		—			24
Transfers in and/or out of Level 3		8			7
Balance at June 30, 2008	$	(56	)		(56	)

The amount of total gains (losses) for the three- and six-month periods included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at June 30, 2008, were:

	Millions of Dollars
	Three Months Ended			Six Months Ended
	June 30			June 30
Related to assets	$	14			17
Related to liabilities		(25	)		(61	)

Gains and losses, realized and unrealized, included in earnings for the three- and six-month periods ending June 30, 2008, were:

															��
	Millions of Dollars
	Three Months Ended								Six Months Ended
	June 30								June 30
				Purchased								Purchased
	Other			Crude Oil,					Other			Crude Oil,
	Operating			Natural Gas					Operating			Natural Gas
	Revenues			and Products		Total			Revenues			and Products		Total
Total gains (losses) included in earnings	$	(14	)		3		(11	)		(57	)		4		(53	)
Change in unrealized gains (losses) relating to assets held at June 30, 2008	$	10			4		14			13			4		17
Change in unrealized gains (losses) relating to liabilities held at June 30, 2008	$	(25	)		—		(25	)		(61	)		—		(61	)

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SFAS No. 159

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115.” This Statement permits the election to carry financial instruments and certain other items similar to financial instruments at fair value on the balance sheet, with all changes in fair value reported in earnings. By electing the fair value option in conjunction with a derivative, an entity can achieve an accounting result similar to a fair value hedge without having to comply with complex hedge accounting rules. We adopted this Statement effective January 1, 2008, but did not make a fair value election at that time or during the first six months of 2008 for any financial instruments not already carried at fair value in accordance with other accounting standards. Accordingly, the adoption of SFAS No. 159 did not impact our consolidated financial statements.

Note 3—Variable Interest Entities (VIEs)

We have a 24 percent interest in West2East Pipeline LLC (West2East), a company holding a 100 percent interest in Rockies Express Pipeline LLC (Rockies Express). West2East is a VIE, but we are not the primary beneficiary. We use the equity method of accounting for our investment. In 2007, we issued a guarantee for 24 percent of the $2 billion in credit facilities of Rockies Express. In addition, we have a guarantee for 24 percent of $600 million of Floating Rate Notes due 2009 issued by Rockies Express. At June 30, 2008, the book value of our investment in West2East was $249 million. See Note 11—Guarantees, for additional information.

We have a 30 percent ownership interest with a 50 percent governance interest in the OOO Naryanmarneftegaz (NMNG) joint venture to develop resources in the Timan-Pechora province of Russia. The NMNG joint venture is a VIE because we and our related party, OAO LUKOIL, have disproportionate interests. We are not the primary beneficiary of the VIE and we use the equity method of accounting for this investment. At June 30, 2008, the book value of our investment in the venture was $2,063 million.

Note 4—Inventories

Inventories consisted of the following:

	Millions of Dollars
	June 30		December 31
	2008		2007
Crude oil and petroleum products	$	5,854		3,373
Materials, supplies and other		903		850
	$	6,757		4,223

Inventories valued on the last-in, first-out (LIFO) basis totaled $5,513 million and $2,974 million at June 30, 2008, and December 31, 2007, respectively. The remaining inventories were 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 $12,234 million and $6,668 million at June 30, 2008, and December 31, 2007, respectively.

7

Note 5—Assets Held for Sale

Noncurrent assets and noncurrent liabilities classified as current assets and current liabilities under the “held for sale” provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” totaled $1,092 million and $159 million, respectively, at December 31, 2007. During the first six months of 2008, a portion of these held-for-sale assets were sold, and additional assets met the held-for-sale criteria. As a result, at June 30, 2008, we classified $1,179 million of noncurrent assets as “Prepaid expenses and other current assets” on our consolidated balance sheet and we classified $303 million of noncurrent liabilities as current liabilities, consisting of $164 million in “Accrued income and other taxes” and $139 million in “Other accruals.” Contingent upon necessary regulatory approvals, we expect the disposal of these assets to be substantially completed by the end of 2008.

The major classes of noncurrent assets and noncurrent liabilities held for sale and classified as current were:

	Millions of Dollars
	June 30		December 31
	2008		2007
Assets
Investments and long-term receivables	$	7		48
Net properties, plants and equipment		973		946
Goodwill		188		89
Intangibles		2		2
Other assets		9		7
Total assets	$	1,179		1,092
Exploration and Production	$	432		189
Refining and Marketing		747		903
	$	1,179		1,092
Liabilities
Asset retirement obligations and accrued environmental costs	$	108		23
Deferred income taxes		164		133
Other liabilities and deferred credits		31		3
Total liabilities	$	303		159
Exploration and Production	$	191		35
Refining and Marketing		112		124
	$	303		159

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Note 6—Investments, Loans and Long-Term Receivables

LUKOIL

Our ownership interest in LUKOIL was 20 percent at June 30, 2008, based on 851 million shares authorized and issued. For financial reporting under U.S. generally accepted accounting principles, treasury shares held by LUKOIL are not considered outstanding for determining our equity-method ownership interest in LUKOIL. Our ownership interest, based on estimated shares outstanding, was also 20 percent at June 30, 2008, compared with 20.6 percent at December 31, 2007.

At June 30, 2008, the book value of our ordinary share investment in LUKOIL was $12,393 million. Our share of the net assets of LUKOIL was estimated to be $9,900 million. This basis difference of $2,493 million is primarily being amortized on a unit-of-production basis. On June 30, 2008, the closing price of LUKOIL shares on the London Stock Exchange was $98.60 per share, making the total market value of our LUKOIL investment $16,773 million.

Loans to Related Parties

As part of our normal ongoing business operations and consistent with industry practice, we invest and enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. Included in such activity are loans made to certain affiliated companies. The long-term portion of these loans are included in the “Loans and advances—related parties” balance sheet line item, while the short-term portion is included in “Accounts and notes receivable—related parties.” Significant loans to affiliated companies at June 30, 2008, included the following:

• $644 million in loan financing and an additional $116 million of accrued interest to Freeport LNG Development, L.P. for the construction of a liquefied natural gas (LNG) facility. We expect to provide loan financing of approximately $678 million, excluding accrued interest, for the construction of the facility. The terminal became operational late in the second quarter of 2008.

• $359 million in loan financing and an additional $46 million of accrued interest to Varandey Terminal Company associated with the costs of a terminal expansion. We expect our total financing obligation for the terminal expansion to be approximately $390 million at current exchange rates, excluding interest to be accrued during construction.

• $787 million of project financing and an additional $60 million of accrued interest to Qatargas 3, an integrated project to produce and liquefy natural gas from Qatar’s North field. Our maximum exposure to this financing structure is $1.2 billion, excluding accrued interest.

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Note 7—Properties, Plants and Equipment

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

	Millions of Dollars
	June 30, 2008						December 31, 2007
	Gross		Accum.		Net		Gross		Accum.		Net
	PP&E		DD&A		PP&E		PP&E		DD&A		PP&E
E&P	$	107,053		34,675		72,378		102,550		30,701		71,849
Midstream		114		66		48		267		103		164
R&M		20,764		5,112		15,652		19,926		4,733		15,193
LUKOIL Investment		—		—		—		—		—		—
Chemicals		—		—		—		—		—		—
Emerging Businesses		1,308		181		1,127		1,204		138		1,066
Corporate and Other		1,499		714		785		1,414		683		731
	$	130,738		40,748		89,990		125,361		36,358		89,003

Suspended Wells

The company’s capitalized cost of suspended wells at June 30, 2008, was $694 million, an increase of $105 million from $589 million at year-end 2007. For the category of exploratory well costs capitalized for a period greater than one year as of December 31, 2007, $12 million was charged to dry hole expense during the first six months of 2008.

Note 8—Impairments

Expropriated Assets

In the second quarter of 2007, we recorded a noncash impairment, including allocable goodwill, of $4,588 million before-tax ($4,512 million after-tax) related to our investments in the Petrozuata and Hamaca heavy-oil ventures and the offshore Corocoro oil development project in Venezuela. See Note 13—Impairments, in our 2007 Annual Report on Form 10-K, for additional information.

Other Impairments

During the first six months of 2008 and 2007, we recognized the following net impairments:

	Millions of Dollars
	Three Months Ended				Six Months Ended
	June 30				June 30
	2008		2007		2008		2007
E&P
United States	$	—		1		—		1
International		1		81		3		175
R&M
United States		18		16		22		49
Increase in fair value of previously impaired assets		—		—		—		(128	)
	$	19		98		25		97

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During the second quarter and six-month period of 2008, property impairments were primarily associated with planned asset dispositions.

During the second quarter and six-month period of 2007, we recorded property impairments for:

• The write-down of held-for-sale assets to fair value, less cost to sell.

• Changes in asset retirement obligations for properties at the end of their economic life.

• The write-down of abandoned properties or projects.

In addition and in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the six-month period of 2007 included a $128 million gain for the subsequent increase in the fair value of certain assets impaired in the prior year to reflect finalized sales agreements. This gain was netted with write-downs into the “Impairments” line of the consolidated income statement.

Note 9—Debt

In January 2008, we reduced our Floating Rate Five-Year Term Note due 2011 from $3 billion to $2 billion, with a subsequent reduction in June 2008 to $1.5 billion. In March 2008, we redeemed our $300 million 7.125% Debentures due 2028 at a premium of $8 million, plus accrued interest.

In May 2008, we issued notes consisting of $400 million of 4.40% Notes due 2013, $500 million of 5.20% Notes due 2018 and $600 million of 5.90% Notes due 2038. The proceeds from the offering were used to reduce commercial paper and for general corporate purposes.

At June 30, 2008, we had a $7.5 billion revolving credit facility, which expires in September 2012. The facility may be used as direct bank borrowings, as support for the ConocoPhillips $7.5 billion commercial paper program, as support for the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, or as support for issuances of letters of credit totaling up to $750 million. At June 30, 2008, and December 31, 2007, we had no outstanding borrowings under the credit facility, but $40 million and $41 million, respectively, in letters of credit had been issued. Under both commercial paper programs, $1,314 million of commercial paper was outstanding at June 30, 2008, compared with $725 million at December 31, 2007.

Also at June 30, 2008, we classified $2,264 million of short-term debt as long-term debt, based on our ability and intent to refinance the obligations on a long-term basis under our revolving credit facilities.

Note 10—Joint Venture Acquisition Obligation

On January 3, 2007, we closed on a business venture with EnCana Corporation. As part of this transaction, we are obligated to contribute $7.5 billion, plus interest, over a ten-year period, which began in 2007, to the upstream business venture, FCCL Oil Sands Partnership, which was formed as a result of the transaction.

Quarterly principal and interest payments of $237 million began in the second quarter of 2007, and will continue until the balance is paid. Of the principal obligation amount, approximately $609 million is short-term and is included in the “Accounts payable—related parties” line on our June 30, 2008, consolidated balance sheet. The principal portion of these payments, which totaled $293 million in the first six months of 2008, is presented on our consolidated statement of cash flows as an other financing activity. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

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Note 11—Guarantees

At June 30, 2008, 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 below, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial.

Construction Completion Guarantees

• In December 2005, we issued a construction completion guarantee for 30 percent of the $4.0 billion in loan facilities of Qatargas 3, which will be used to construct an LNG train in Qatar. Of the $4.0 billion in loan facilities, ConocoPhillips has committed to provide $1.2 billion. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $850 million, which could become payable if the full debt financing is utilized and completion of the Qatargas 3 project is not achieved. The project financing will be nonrecourse to ConocoPhillips upon certified completion, currently expected in 2010. At June 30, 2008, the carrying value of the guarantee to the third-party lenders was $11 million. For additional information, see Note 6—Investments, Loans and Long-Term Receivables.

Guarantees of Joint-Venture Debt

• In June 2006, we issued a guarantee for 24 percent of the $2 billion in credit facilities of Rockies Express Pipeline LLC (Rockies Express), which will be used to construct a natural gas pipeline across a portion of the United States. At June 30, 2008, Rockies Express had $740 million outstanding under the credit facilities, with our 24 percent guarantee equaling $178 million. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $480 million, which could become payable if the credit facility is fully utilized and Rockies Express fails to meet its obligations under the credit agreement. In addition, we also have a guarantee for 24 percent of $600 million of Floating Rate Notes due 2009 issued by Rockies Express in September 2007. It is anticipated final construction completion will be achieved in 2009, and refinancing will take place at that time, making the debt nonrecourse to ConocoPhillips. At June 30, 2008, the total carrying value of these guarantees to third-party lenders was $12 million. See Note 3—Variable Interest Entities (VIEs), for additional information.

• At June 30, 2008, we had other guarantees outstanding for our portion of joint-venture debt obligations, which have terms of up to 17 years. The maximum potential amount of future payments under the guarantees is approximately $90 million. Payment would be required if a joint venture defaults on its debt obligations.

Other Guarantees

• The Merey Sweeny, L.P. (MSLP) joint-venture project agreement requires the partners in the venture to pay cash calls to cover operating expenses in the event the venture does not have enough cash to cover operating expenses after setting aside the amount required for debt service over the next 16 years. Although there is no maximum limit stated in the agreement, the intent is to cover short-term cash deficiencies should they occur. Our maximum potential future payments under the agreement are currently estimated to be $100 million, assuming such a shortfall exists at some point in the future due to an extended operational disruption.

• In February 2003, we entered into two agreements establishing separate guarantee facilities of $50 million each for two LNG ships. Subject to the terms of each such facility, we will be required to make payments should the charter revenue generated by the respective ship fall below certain specified minimum thresholds, and we will receive payments to the extent that such revenues exceed those thresholds. The net maximum future payments that we may have to make over the 20-year terms of the two agreements could be up to $100 million in total. To the extent we receive any such payments, our

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actual gross payments over the 20 years could exceed that amount. In the event either ship is sold or a total loss occurs, we also may have recourse to the sales or insurance proceeds to recoup payments made under the guarantee facilities.

• We have guarantees of the residual value of leased corporate aircraft. The maximum potential payment under these guarantees at June 30, 2008, was $150 million.

• In December 2007, we acquired a 50 percent equity interest in the Keystone Oil Pipeline (Keystone) to form a 50/50 joint venture with TransCanada Corporation. Keystone plans to construct a crude oil pipeline originating in Hardisty, Alberta, with delivery points at Wood River and Patoka, Illinois, and Cushing, Oklahoma. In connection with certain planning and construction activities, agreements were put in place with third parties to guarantee the payments due. Our maximum potential amount of future payments under those agreements are estimated to be $400 million, which could become payable if Keystone fails to meet its obligations under the agreements noted above and the obligation cannot otherwise be mitigated. Payments under the guarantees are contingent upon the partners not making necessary equity contributions into Keystone; therefore, it is considered unlikely that payments would be required. All but $15 million of the guarantees will terminate after construction is completed, currently estimated to be in 2010.

• We have other guarantees with maximum future potential payment amounts totaling $200 million, which consist primarily of dealer and jobber loan guarantees to support our marketing business, guarantees to fund the short-term cash liquidity deficits of certain joint ventures, one small construction completion guarantee, guarantees relating to the startup of a refining joint venture, and guarantees of the lease payment obligations of a joint venture. These guarantees generally extend up to 10 years or life of the venture and payment would be required only if the dealer, jobber or lessee goes into default, if the joint ventures have cash liquidity issues, if a construction project is not completed, or if a guaranteed party defaults on lease payments.

Indemnifications

Over the years, we have entered into various agreements to sell ownership interests in certain corporations and joint ventures and have sold several assets, including downstream and midstream assets, certain exploration and production assets, and downstream retail and wholesale sites that gave rise to qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, environmental liabilities, permits and licenses, employee claims, real estate indemnity against tenant defaults, and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications at June 30, 2008, was $454 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the carrying amount recorded were $256 million of environmental accruals for known contamination that is included in asset retirement obligations and accrued environmental costs at June 30, 2008. For additional information about environmental liabilities, see Note 12—Contingencies and Commitments.

Note 12—Contingencies and Commitments

In the case of all known non-income-tax-related contingencies, we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue

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receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we adopted FIN 48, effective January 1, 2007. FIN 48 requires a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.

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

Environmental

We are subject to federal, state and local environmental laws and regulations. These may result in obligations to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various sites. When we prepare our consolidated 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 account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities and we accrue them in the period that they are both probable and reasonably estimable.

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

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

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except for those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable that future costs will be incurred and these costs can be reasonably estimated. At June 30, 2008, our balance

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sheet included a total environmental accrual of $1,046 million, compared with $1,089 million at December 31, 2007. We expect to incur the majority of these expenditures within the next 30 years. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings.

Legal Proceedings

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

Other Contingencies

We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at June 30, 2008, we had performance obligations secured by letters of credit of $1,967 million (of which $40 million was issued under the provisions of our revolving credit facility, and the remainder was issued as direct bank letters of credit) and various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.

Note 13—Financial Instruments and Derivative Contracts

Derivative assets and liabilities were:

	Millions of Dollars
	June 30		December 31
	2008		2007
Derivative Assets
Current	$	1,641		453
Long-term		322		89
	$	1,963		542
Derivative Liabilities
Current	$	1,913		493
Long-term		251		67
	$	2,164		560

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

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Note 14—Comprehensive Income

ConocoPhillips’ comprehensive income was as follows:

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2008			2007			2008			2007
Net income	$	5,439			301			9,578			3,847
After-tax changes in:
Defined benefit pension plans
Net prior service cost		(14	)		5			(10	)		10
Net actuarial loss		(2	)		14			7			30
Nonsponsored plans		2			—			4			(3	)
Foreign currency translation adjustments		178			1,145			(257	)		1,276
Hedging activities		2			(2	)		—			(3	)
Comprehensive income	$	5,605			1,463			9,322			5,157

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

	Millions of Dollars
	June 30			December 31
	2008			2007
Defined benefit pension plans	$	(464	)		(465	)
Foreign currency translation adjustments		4,776			5,033
Deferred net hedging loss		(8	)		(8	)
Accumulated other comprehensive income	$	4,304			4,560

Note 15—Cash Flow Information

	Millions of Dollars
	Six Months Ended
	June 30
	2008		2007
Noncash Investing and Financing Activities
Investment in an upstream business venture through issuance of an acquisition obligation	$	—		7,313
Investment in a downstream business venture through contribution of noncash assets and liabilities		—		2,415
Cash Payments
Interest	$	398		532
Income taxes		6,405		5,525

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Note 16—Employee Benefit Plans

Pension and Postretirement Plans

	Millions of Dollars
	Pension Benefits												Other Benefits
	June 30												June 30
Components of Net Periodic Benefit Cost	2008						2007						2008			2007
	U.S.			Int’l.			U.S.			Int’l.
Three Months Ended
Service cost	$	47			24			44			24			4			4
Interest cost		62			46			57			41			16			11
Expected return on plan assets		(56	)		(45	)		(51	)		(37	)		—			—
Amortization of prior service cost		2			—			2			2			2			4
Recognized net actuarial loss (gain)		17			3			16			12			(6	)		(6	)
Net periodic benefit costs	$	72			28			68			42			16			13
Six Months Ended
Service cost	$	94			47			88			48			7			7
Interest cost		124			90			114			79			28			22
Expected return on plan assets		(112	)		(89	)		(102	)		(72	)		—			—
Amortization of prior service cost		4			—			5			4			5			7
Recognized net actuarial loss (gain)		33			6			31			23			(10	)		(10	)
Net periodic benefit costs	$	143			54			136			82			30			26

During the first six months of 2008, we contributed $222 million to our domestic qualified and nonqualified plans and $92 million to our international benefit plans. We currently expect to contribute a total of $460 million to our domestic plans and $180 million to our international plans in 2008.

Note 17—Related Party Transactions

Significant transactions with related parties were:

	Millions of Dollars
	Three Months Ended				Six Months Ended
	June 30				June 30
	2008		2007		2008		2007
Operating revenues (a)	$	4,001		2,884		7,172		5,502
Purchases (b)		5,693		4,089		10,092		7,299
Operating expenses and selling, general and administrative expenses (c)		127		98		243		206
Net interest income (d)		19		26		40		56

(a) We sold natural gas to DCP Midstream and crude oil to the Malaysian Refining Company Sdn. Bhd. (MRC), among others, for processing and marketing. Natural gas liquids, solvents and petrochemical feedstocks were sold to Chevron Phillips Chemical Company LLC (CPChem), gas oil and hydrogen feedstocks were sold to Excel Paralubes and refined products were sold primarily to CFJ Properties and LUKOIL. Natural gas, crude oil, blendstock and other intermediate products were sold to WRB Refining LLC. In addition, we charged several of our affiliates including CPChem, Merey Sweeny L.P. (MSLP)

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	and Hamaca Holding LLC (until expropriation on June 26, 2007) for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.
(b)	We purchased refined products from WRB Refining. We purchased natural gas and natural gas liquids from DCP Midstream and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchased crude oil from LUKOIL, upgraded crude oil from Petrozuata C.A. (as a related party until expropriation on June 26, 2007) and refined products from MRC. We also paid fees to various pipeline equity companies for transporting finished refined products and natural gas, and a price upgrade to MSLP for heavy crude oil processing. We purchased base oils and fuel products from Excel Paralubes for use in our refinery and specialty businesses.
(c)	We paid processing fees to various affiliates. Additionally, we paid crude oil transportation fees to pipeline equity companies.
(d)	We paid and/or received interest to/from various affiliates, including FCCL Oil Sands Partnership. See Note 6—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

Note 18—Segment Disclosures and Related Information

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

1)	E&P—This segment primarily explores for, produces, transports and markets crude oil, natural gas and natural gas liquids on a worldwide basis.
2)	Midstream—This segment gathers, processes and markets natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, primarily in the United States and Trinidad. The Midstream segment primarily consists of our 50 percent equity investment in DCP Midstream.
3)	R&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia Pacific.
4)	LUKOIL Investment—This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia. At June 30, 2008, our ownership interest was 20 percent based on both issued shares and estimated shares outstanding.
5)	Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in CPChem.
6)	Emerging Businesses—This segment represents our investment in new technologies or businesses outside our normal scope of operations.

Corporate and Other includes general corporate overhead, most interest income and expense, restructuring charges, and various other corporate activities. Corporate assets include all cash and cash equivalents. We evaluate performance and allocate resources based on net income. Intersegment sales are at prices that approximate market.

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Analysis of Results by Operating Segment

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2008			2007			2008			2007
Sales and Other Operating Revenues
E&P
United States	$	15,964			9,465			27,511			17,737
International		8,471			5,480			16,912			11,493
Intersegment eliminations—U.S.		(2,525	)		(1,496	)		(4,637	)		(2,652	)
Intersegment eliminations—international		(3,550	)		(1,476	)		(5,847	)		(2,917	)
E&P		18,360			11,973			33,939			23,661
Midstream
Total sales		2,100			1,109			3,742			2,214
Intersegment eliminations		(30	)		(45	)		(119	)		(104	)
Midstream		2,070			1,064			3,623			2,110
R&M
United States		37,250			24,614			64,211			44,653
International		13,969			9,793			24,895			18,428
Intersegment eliminations—U.S.		(285	)		(119	)		(504	)		(263	)
Intersegment eliminations—international		(13	)		(3	)		(20	)		(5	)
R&M		50,921			34,285			88,582			62,813
LUKOIL Investment		—			—			—			—
Chemicals		3			3			6			6
Emerging Businesses
Total sales		230			131			488			300
Intersegment eliminations		(179	)		(91	)		(356	)		(205	)
Emerging Businesses		51			40			132			95
Corporate and Other		6			5			12			5
Consolidated sales and other operating revenues	$	71,411			47,370			126,294			88,690
Net Income (Loss)
E&P
United States	$	1,852			1,055			3,201			1,971
International		2,147			(3,459	)		3,685			(2,046	)
Total E&P		3,999			(2,404	)		6,886			(75	)
Midstream		162			102			299			187
R&M
United States		587			1,879			1,022			2,775
International		77			479			162			719
Total R&M		664			2,358			1,184			3,494
LUKOIL Investment		774			526			1,484			782
Chemicals		18			68			70			150
Emerging Businesses		8			(12	)		20			(13	)
Corporate and Other		(186	)		(337	)		(365	)		(678	)
Consolidated net income	$	5,439			301			9,578			3,847

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	Millions of Dollars
	June 30		December 31
	2008		2007
Total Assets
E&P
United States	$	38,338		35,160
International		60,102		59,412
Goodwill		25,460		25,569
Total E&P		123,900		120,141
Midstream		2,070		2,016
R&M
United States		29,207		24,336
International		12,464		9,766
Goodwill		3,767		3,767
Total R&M		45,438		37,869
LUKOIL Investment		12,697		11,164
Chemicals		2,265		2,225
Emerging Businesses		1,308		1,230
Corporate and Other		2,477		3,112
Consolidated total assets	$	190,155		177,757

Note 19—Income Taxes

Our effective tax rate for the second quarter and first six months of 2008 was 44 percent and 45 percent, respectively, compared with 91 percent and 60 percent for the same two periods of 2007. The change in the effective tax rate for the second quarter and six months of 2008, versus the same periods of 2007, was primarily due to the impact of the expropriation of our oil interests in Venezuela on 2007 results (see the “Expropriated Assets” section of Note 13—Impairments, in our 2007 Annual Report on Form 10-K, for additional information), partially offset by the impact of a higher proportion of income in higher tax-rate jurisdictions in 2008. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to the impact of foreign taxes.

Note 20—New Accounting Standards

In December 2007, the FASB issued SFAS No. 141 (Revised), “Business Combinations” (SFAS No. 141(R)). This Statement will apply to all transactions in which an entity obtains control of one or more other businesses. In general, SFAS No. 141(R) requires the acquiring entity in a business combination to recognize the fair value of all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date as the fair value measurement point; and modifies the disclosure requirements. This Statement applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. However, starting January 1, 2009, accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for prior business combinations will impact tax expense instead of impacting goodwill. We are currently evaluating the changes provided for in this Statement.

Also in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51,” which changes the classification of noncontrolling interests, sometimes called a minority interest, in the consolidated financial statements. Additionally, this Statement establishes a single method of accounting for changes in a parent company’s ownership interest that do not result in deconsolidation and requires a parent company to recognize a gain or loss when a subsidiary is deconsolidated. This Statement is effective January 1, 2009, and will be applied prospectively with the

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exception of the presentation and disclosure requirements which must be applied retrospectively for all periods presented. We are currently evaluating the impact of this Statement on our consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB No. 133.” This Statement expands the annual and interim disclosure requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” for derivative instruments within the scope of that Statement. We must adopt SFAS No. 161 no later than January 1, 2009, but it will not have any impact on our consolidated financial statements, other than the additional disclosures.

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Supplementary Information—Condensed Consolidating Financial Information

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

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

• All other nonguarantor subsidiaries of ConocoPhillips.

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

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

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	Millions of Dollars
	Three Months Ended June 30, 2008
						ConocoPhillips
						Australia		ConocoPhillips			ConocoPhillips
				ConocoPhillips		Funding		Canada Funding			Canada Funding			All Other			Consolidating			Total
Income Statement	ConocoPhillips			Company		Company		Company I			Company II			Subsidiaries			Adjustments			Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—			47,793		—		—			—			23,618			—			71,411
Equity in earnings of affiliates		5,466			3,796		—		—			—			1,446			(8,896	)		1,812
Other income		(1	)		182		—		—			—			(51	)		—			130
Intercompany revenues		15			915		19		22			13			9,693			(10,677	)		—
Total Revenues and Other Income		5,480			52,686		19		22			13			34,706			(19,573	)		73,353
Costs and Expenses
Purchased crude oil, natural gas and products		—			44,038		—		—			—			17,540			(10,364	)		51,214
Production and operating expenses		—			1,337		—		—			—			1,807			(33	)		3,111
Selling, general and administrative expenses		5			466		—		—			—			171			(13	)		629
Exploration expenses		—			45		—		—			—			243			—			288
Depreciation, depletion and amortization		—			379		—		—			—			1,799			—			2,178
Impairments		—			17		—		—			—			2			—			19
Taxes other than income taxes		—			1,285		—		—			—			4,569			(58	)		5,796
Accretion on discounted liabilities		—			14		—		—			—			82			—			96
Interest and debt expense		51			104		18		20			13			213			(209	)		210
Foreign currency transaction (gains) losses		—			2		—		58			66			(126	)		—			—
Minority interests		—			—		—		—			—			17			—			17
Total Costs and Expenses		56			47,687		18		78			79			26,317			(10,677	)		63,558
Income (loss) before income taxes		5,424			4,999		1		(56	)		(66	)		8,389			(8,896	)		9,795
Provision for income taxes		(15	)		550		—		(17	)		(21	)		3,859			—			4,356
Net Income (Loss)	$	5,439			4,449		1		(39	)		(45	)		4,530			(8,896	)		5,439

23

	Millions of Dollars
	Three Months Ended June 30, 2007
							ConocoPhillips
							Australia		ConocoPhillips			ConocoPhillips
				ConocoPhillips			Funding		Canada Funding			Canada Funding			All Other			Consolidating			Total
Income Statement	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries			Adjustments			Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—			30,915			—		—			—			16,455			—			47,370
Equity in earnings of affiliates		329			632			—		—			—			780			(235	)		1,506
Other income		4			(70	)		���		—			—			587			—			521
Intercompany revenues		58			791			30		20			12			4,754			(5,665	)		—
Total Revenues and Other Income		391			32,268			30		20			12			22,576			(5,900	)		49,397
Costs and Expenses
Purchased crude oil, natural gas and products		—			25,780			—		—			—			9,989			(4,949	)		30,820
Production and operating expenses		—			1,109			—		—			—			1,469			(21	)		2,557
Selling, general and administrative expenses		6			375			—		—			—			235			(12	)		604
Exploration expenses		—			24			—		—			—			235			—			259
Depreciation, depletion and amortization		—			361			—		—			—			1,655			—			2,016
Impairment—expropriated assets		—			1,925			—		—			—			2,663			—			4,588
Impairments		—			—			—		—			—			98			—			98
Taxes other than income taxes		—			1,295			—		—			—			3,472			(70	)		4,697
Accretion on discounted liabilities		—			14			—		—			—			67			—			81
Interest and debt expense		99			291			28		19			13			482			(613	)		319
Foreign currency transaction (gains) losses		—			10			—		91			67			(347	)		—			(179	)
Minority interests		—			—			—		—			—			19			—			19
Total Costs and Expenses		105			31,184			28		110			80			20,037			(5,665	)		45,879
Income (loss) before income taxes		286			1,084			2		(90	)		(68	)		2,539			(235	)		3,518
Provision for income taxes		(15	)		1,090			1		5			6			2,130			—			3,217
Net Income (Loss)	$	301			(6	)		1		(95	)		(74	)		409			(235	)		301

24

	Millions of Dollars
	Six Months Ended June 30, 2008
							ConocoPhillips Australia		ConocoPhillips			ConocoPhillips
				ConocoPhillips			Funding		Canada Funding			Canada Funding			All Other			Consolidating			Total
Income Statement	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries			Adjustments			Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—			82,596			—		—			—			43,698			—			126,294
Equity in earnings of affiliates		9,651			6,857			—		—			—			2,754			(16,091	)		3,171
Other income		(1	)		487			—		—			—			(46	)		—			440
Intercompany revenues		24			1,632			43		45			27			15,743			(17,514	)		—
Total Revenues and Other Income		9,674			91,572			43		45			27			62,149			(33,605	)		129,905
Costs and Expenses
Purchased crude oil, natural gas and products		—			75,530			—		—			—			30,183			(16,679	)		89,034
Production and operating expenses		—			2,447			—		—			—			3,425			(70	)		5,802
Selling, general and administrative expenses		7			785			—		—			—			396			(33	)		1,155
Exploration expenses		—			100			—		—			—			497			—			597
Depreciation, depletion and amortization		—			751			—		—			—			3,636			—			4,387
Impairments		—			21			—		—			—			4			—			25
Taxes other than income taxes		—			2,539			—		—			—			8,531			(119	)		10,951
Accretion on discounted liabilities		—			29			—		—			—			171			—			200
Interest and debt expense		128			325			40		39			26			472			(613	)		417
Foreign currency transaction (gains) losses		—			(2	)		—		(14	)		(7	)		(20	)		—			(43	)
Minority interests		—			—			—		—			—			36			—			36
Total Costs and Expenses		135			82,525			40		25			19			47,331			(17,514	)		112,561
Income before income taxes		9,539			9,047			3		20			8			14,818			(16,091	)		17,344
Provision for income taxes		(39	)		987			1		(13	)		(13	)		6,843			—			7,766
Net Income	$	9,578			8,060			2		33			21			7,975			(16,091	)		9,578

25

	Millions of Dollars
	Six Months Ended June 30, 2007
							ConocoPhillips Australia		ConocoPhillips			ConocoPhillips
				ConocoPhillips			Funding		Canada Funding			Canada Funding			All Other			Consolidating			Total
Income Statement	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries			Adjustments			Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—			56,892			—		—			—			31,798			—			88,690
Equity in earnings of affiliates		3,892			3,654			—		—			—			1,325			(6,436	)		2,435
Other income		4			(180	)		—		—			—			1,315			—			1,139
Intercompany revenues		147			1,489			60		39			24			8,567			(10,326	)		—
Total Revenues and Other Income		4,043			61,855			60		39			24			43,005			(16,762	)		92,264
Costs and Expenses
Purchased crude oil, natural gas and products		—			47,802			—		—			—			18,620			(8,887	)		57,535
Production and operating expenses		—			2,195			—		—			—			2,896			(42	)		5,049
Selling, general and administrative expenses		9			688			—		—			—			464			(30	)		1,131
Exploration expenses		—			46			—		—			—			475			—			521
Depreciation, depletion and amortization		—			723			—		—			—			3,317			—			4,040
Impairment—expropriated assets		—			1,925			—		—			—			2,663			—			4,588
Impairments		—			(24	)		—		—			—			121			—			97
Taxes other than income taxes		—			2,798			—		—			—			6,410			(137	)		9,071
Accretion on discounted liabilities		—			28			—		—			—			132			—			160
Interest and debt expense		211			646			56		38			26			879			(1,230	)		626
Foreign currency transaction (gains) losses		—			10			—		98			77			(363	)		—			(178	)
Minority interests		—			—			—		—			—			40			—			40
Total Costs and Expenses		220			56,837			56		136			103			35,654			(10,326	)		82,680
Income (loss) before income taxes		3,823			5,018			4		(97	)		(79	)		7,351			(6,436	)		9,584
Provision for income taxes		(24	)		1,674			2		(2	)		(2	)		4,089			—			5,737
Net Income (Loss)	$	3,847			3,344			2		(95	)		(77	)		3,262			(6,436	)		3,847

26

	Millions of Dollars
	At June 30, 2008
							ConocoPhillips Australia			ConocoPhillips			ConocoPhillips
				ConocoPhillips			Funding			Canada Funding			Canada Funding			All Other		Consolidating			Total
Balance Sheet	ConocoPhillips			Company			Company			Company I			Company II			Subsidiaries		Adjustments			Consolidated
Assets
Cash and cash equivalents	$	—			366			—			12			1			408		—			787
Accounts and notes receivable		18			13,189			8			—			—			23,323		(16,077	)		20,461
Inventories		—			4,102			—			—			—			2,764		(109	)		6,757
Prepaid expenses and other current assets		5			2,342			—			2			1			3,160		—			5,510
Total Current Assets		23			19,999			8			14			2			29,655		(16,186	)		33,515
Investments, loans and long-term receivables*		93,749			66,090			1,700			1,421			964			37,876		(166,005	)		35,795
Net properties, plants and equipment		—			18,852			—			—			—			71,136		2			89,990
Goodwill		—			12,730			—			—			—			16,497		—			29,227
Intangibles		—			792			—			—			—			81		—			873
Other assets		14			288			3			4			4			660		(218	)		755
Total Assets	$	93,786			118,751			1,711			1,439			970			155,905		(182,407	)		190,155
Liabilities and Stockholders’ Equity
Accounts payable	$	1			21,851			—			6			3			17,577		(16,077	)		23,361
Short-term debt		—			298			950			—			—			87		(950	)		385
Accrued income and other taxes		—			198			—			—			(1	)		6,502		—			6,699
Employee benefit obligations		—			412			—			—			—			268		1			681
Other accruals		27			1,494			15			15			10			2,163		(3	)		3,721
Total Current Liabilities		28			24,253			965			21			12			26,597		(17,029	)		34,847
Long-term debt		4,878			5,390			749			1,250			848			7,474		950			21,539
Asset retirement obligations and accrued environmental costs		—			1,127			—			—			—			6,203		—			7,330
Joint venture acquisition obligation		—			—			—			—			—			5,985		—			5,985
Deferred income taxes		(3	)		3,524			—			8			2			17,529		(16	)		21,044
Employee benefit obligations		—			2,206			—			—			—			837		—			3,043
Other liabilities and deferred credits*		3,155			19,458			—			121			97			18,550		(38,556	)		2,825
Total Liabilities		8,058			55,958			1,714			1,400			959			83,175		(54,651	)		96,613
Minority interests		—			(15	)		—			—			—			1,159		—			1,144
Retained earnings (deficit)		52,112			32,012			(3	)		(114	)		(86	)		27,512		(52,808	)		58,625
Other stockholders’ equity		33,616			30,796			—			153			97			44,059		(74,948	)		33,773
Total	$	93,786			118,751			1,711			1,439			970			155,905		(182,407	)		190,155

*Includes intercompany loans.

27

	Millions of Dollars
	At December 31, 2007
							ConocoPhillips
							Australia			ConocoPhillips			ConocoPhillips
				ConocoPhillips			Funding			Canada Funding			Canada Funding			All Other		Consolidating			Total
Balance Sheet	ConocoPhillips			Company			Company			Company I			Company II			Subsidiaries		Adjustments			Consolidated
Assets
Cash and cash equivalents	$	—			195			—			7			1			1,626		(373	)		1,456
Accounts and notes receivable		40			12,421			15			12			4			19,548		(15,686	)		16,354
Inventories		—			2,043			—			—			—			2,190		(10	)		4,223
Prepaid expenses and other current assets		9			578			—			1			—			2,114		—			2,702
Total Current Assets		49			15,237			15			20			5			25,478		(16,069	)		24,735
Investments, loans and long-term receivables*		86,942			57,936			1,700			1,470			997			18,972		(134,689	)		33,328
Net properties, plants and equipment		—			17,677			—			—			—			71,317		9			89,003
Goodwill		—			12,746			—			—			—			16,590		—			29,336
Intangibles		—			808			—			—			—			88		—			896
Other assets		8			153			3			5			4			520		(234	)		459
Total Assets	$	86,999			104,557			1,718			1,495			1,006			132,965		(150,983	)		177,757
Liabilities and Stockholders’ Equity
Accounts payable	$	6			18,792			—			10			4			15,108		(16,059	)		17,861
Short-term debt		1,000			309			—			—			—			89		—			1,398
Accrued income and other taxes		—			601			—			—			(1	)		4,117		97			4,814
Employee benefit obligations		—			509			—			—			—			411		—			920
Other accruals		21			594			20			16			11			1,230		(3	)		1,889
Total Current Liabilities		1,027			20,805			20			26			14			20,955		(15,965	)		26,882
Long-term debt		3,402			5,694			1,699			1,250			848			7,396		—			20,289
Asset retirement obligations and accrued environmental costs		—			1,167			—			—			—			6,094		—			7,261
Joint venture acquisition obligation		—			—			—			—			—			6,294		—			6,294
Deferred income taxes		(3	)		3,050			—			32			18			17,907		14			21,018
Employee benefit obligations		—			2,292			—			—			—			899		—			3,191
Other liabilities and deferred credits*		42			16,447			—			132			102			15,489		(29,546	)		2,666
Total Liabilities		4,468			49,455			1,719			1,440			982			75,034		(45,497	)		87,601
Minority interests		—			(19	)		—			—			—			1,194		(2	)		1,173
Retained earnings (deficit)		43,988			23,952			(1	)		(147	)		(107	)		20,738		(37,913	)		50,510
Other stockholders’ equity		38,543			31,169			—			202			131			35,999		(67,571	)		38,473
Total	$	86,999			104,557			1,718			1,495			1,006			132,965		(150,983	)		177,757

*Includes intercompany loans.

28

	Millions of Dollars
	Six Months Ended June 30, 2008
							ConocoPhillips
							Australia			ConocoPhillips		ConocoPhillips
				ConocoPhillips			Funding			Canada Funding		Canada Funding		All Other			Consolidating			Total
Statement of Cash Flows	ConocoPhillips			Company			Company			Company I		Company II		Subsidiaries			Adjustments			Consolidated
Net Cash Provided by Operating Activities	$	5,815			189			4			5		—		6,830			(822	)		12,021
Cash Flows From Investing Activities
Capital expenditures and investments		—			(2,462	)		—			—		—		(4,611	)		353			(6,720	)
Proceeds from asset dispositions		—			73			—			—		—		372			(4	)		441
Long-term advances/loans —related parties		—			(53	)		—			—		—		(2,523	)		2,422			(154	)
Collection of advances/loans—related parties		—			212			—			—		—		9			(217	)		4
Other		—			10			—			—		—		(3	)		—			7
Net Cash Used in Investing Activities		—			(2,220	)		—			—		—		(6,756	)		2,554			(6,422	)
Cash Flows From Financing Activities
Issuance of debt		1,967			2,412			—			—		—		108			(2,422	)		2,065
Repayment of debt		(1,500	)		(338	)		—			—		—		(220	)		217			(1,841	)
Issuance of company common stock		185			—			—			—		—		—			—			185
Repurchase of company common stock		(5,008	)		—			—			—		—		—			—			(5,008	)
Dividends paid on common stock		(1,449	)		—			(4	)		—		—		(1,191	)		1,195			(1,449	)
Other		(10	)		128			—			—		—		(9	)		(349	)		(240	)
Net Cash Provided by (Used in) Financing Activities		(5,815	)		2,202			(4	)		—		—		(1,312	)		(1,359	)		(6,288	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			—			—		—		20			—			20
Net Change in Cash and Cash Equivalents		—			171			—			5		—		(1,218	)		373			(669	)
Cash and cash equivalents at beginning of year		—			195			—			7		1		1,626			(373	)		1,456
Cash and Cash Equivalents at End of Period	$	—			366			—			12		1		408			—			787

29

	Millions of Dollars
	Six Months Ended June 30, 2007
							ConocoPhillips
							Australia			ConocoPhillips		ConocoPhillips
				ConocoPhillips			Funding			Canada Funding		Canada Funding		All Other			Consolidating			Total
Statement of Cash Flows	ConocoPhillips			Company			Company			Company I		Company II		Subsidiaries			Adjustments			Consolidated
Net Cash Provided by (Used in) Operating Activities	$	7,762			(777	)		5			—		—		4,755			(106	)		11,639
Cash Flows From Investing Activities
Capital expenditures and investments		—			(1,148	)		—			—		—		(4,301	)		102			(5,347	)
Proceeds from asset dispositions		—			951			—			—		—		1,679			(415	)		2,215
Long-term advances/loans —related parties		—			(118	)		—			—		—		(1,137	)		929			(326	)
Collection of advances/loans—related parties		—			811			—			—		—		—			(745	)		66
Other		1			18			—			—		—		—			—			19
Net Cash Provided by (Used in) Investing Activities		1			514			—			—		—		(3,759	)		(129	)		(3,373	)
Cash Flows From Financing Activities
Issuance of debt		(36	)		929			—			—		—		801			(929	)		765
Repayment of debt		(4,564	)		(547	)		—			—		—		(755	)		745			(5,121	)
Issuance of company common stock		181			—			—			—		—		—			—			181
Repurchase of company common stock		(2,000	)		—			—			—		—		—			—			(2,000	)
Dividends paid on common stock		(1,342	)		—			(5	)		—		—		(316	)		321			(1,342	)
Other		(2	)		50			—			—		—		(513	)		312			(153	)
Net Cash Provided by (Used in) Financing Activities		(7,763	)		432			(5	)		—		—		(783	)		449			(7,670	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			—			—		—		(2	)		—			(2	)
Net Change in Cash andCash Equivalents		—			169			—			—		—		211			214			594
Cash and cash equivalents at beginning of year		—			116			—			—		1		1,042			(342	)		817
Cash and Cash Equivalents at End of Period	$	—			285			—			—		1		1,253			(128	)		1,411

30

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,” “should,” “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 51.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

Our Exploration and Production (E&P) segment had net income of $3,999 million in the second quarter of 2008, which accounted for 74 percent of our total net income in the quarter. This compares with E&P net income of $2,887 million in the first quarter of 2008, and a loss of $2,404 million in the second quarter of 2007. In the second quarter of 2007, we recorded a noncash impairment of $4,588 million before-tax ($4,512 million after-tax) related to the expropriation of our oil interests in Venezuela. For additional information, see the “Expropriated Assets” section of Note 13—Impairments, in our 2007 Annual Report on Form 10-K.

E&P net income in the second quarter of 2008 benefited from an increase in commodity prices. Industry crude oil prices for West Texas Intermediate averaged $123.98 per barrel in the second quarter of 2008, or $26.04 per barrel higher than the first quarter of 2008, and $59.09 per barrel higher than in the same period a year earlier. Crude oil prices were influenced by higher demand in developing economies; geopolitical supply risks; and a financial sector rotation into commodities due to fears about the falling value of the U.S. dollar, inflation and risk in credit markets.

Industry natural gas prices for Henry Hub increased during the second quarter of 2008 to $10.94 per million British thermal units (MMBTU), up $2.91 per MMBTU from the first quarter of 2008. Natural gas prices trended higher during the second quarter due to the outage of a natural gas hub in the Gulf of Mexico for a significant portion of the quarter, low storage levels, and a low level of liquefied natural gas (LNG) imports into the United States. Along with these supply issues, demand in the United States for natural gas remained in line with year-ago levels despite the increased prices.

Our Refining and Marketing (R&M) segment had net income of $664 million in the second quarter of 2008, compared with $520 million in the first quarter of 2008, and $2,358 million in the second quarter of 2007. The increase in net income from the previous quarter was primarily due to higher worldwide realized refining margins and improved refining operations in the U.S. Gulf Coast and United Kingdom. This improvement in realized margins was partially offset by a lower net benefit from asset rationalization efforts, as well as higher turnaround and utility costs. The decrease in net income from the second quarter of 2007 was primarily due to significantly lower U.S. refining and marketing margins, a lower net benefit from the company’s asset rationalization efforts and higher turnaround and utility costs.

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RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and six-month periods ending June 30, 2008, is based on a comparison with the corresponding periods of 2007.

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
	2008			2007			2008			2007
Exploration and Production (E&P)	$	3,999			(2,404	)		6,886			(75	)
Midstream		162			102			299			187
Refining and Marketing (R&M)		664			2,358			1,184			3,494
LUKOIL Investment		774			526			1,484			782
Chemicals		18			68			70			150
Emerging Businesses		8			(12	)		20			(13	)
Corporate and Other		(186	)		(337	)		(365	)		(678	)
Net income	$	5,439			301			9,578			3,847

Net income was $5,439 million in the second quarter of 2008, compared with $301 million in the second quarter of 2007. For the six-month periods ended June 30, 2008 and 2007, net income was $9,578 million and $3,847 million, respectively. The higher results in both 2008 periods were primarily the result of a complete impairment in 2007 ($4,512 million after-tax) of our oil interests in Venezuela, resulting from their expropriation on June 26, 2007.

In addition, the results in both 2008 periods benefited from:

• Significantly higher crude oil, natural gas and natural gas liquids prices in our E&P segment.

• Increased earnings from our LUKOIL investment, primarily due to higher estimated realized prices, partially offset by higher estimated taxes.

These items were partially offset by a decrease in net income from our R&M segment, primarily due to lower domestic realized refining and marketing margins, and a reduced net benefit from asset rationalization efforts. In addition, net income decreased due to higher taxes in our E&P segment.

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

Income Statement Analysis

Sales and other operating revenues increased 51 percent in the second quarter of 2008 and 42 percent in the six-month period, while purchased crude oil, natural gas and products increased 66 percent and 55 percent, respectively. These increases were mainly the result of higher petroleum product prices, and higher prices for crude oil, natural gas and natural gas liquids.

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Equity in earnings of affiliates increased 20 percent in the second quarter of 2008 and 30 percent in the six-month period, reflecting improved results from:

• LUKOIL, primarily reflecting higher estimated realized prices, partially offset by higher estimated taxes.

• DCP Midstream, our midstream joint venture, primarily due to higher realized natural gas liquids prices and volumes.

These increases were partially offset by lower earnings from WRB Refining LLC, primarily due to lower refining margins.

Other income decreased 75 percent and 61 percent during the second quarter and first six months of 2008, respectively. The decrease was primarily due to higher 2007 net gains on asset dispositions associated with asset rationalization efforts.

Production and operating costs increased 22 percent and 15 percent during the second quarter and first six months of 2008, respectively. Contributing to the increase were higher maintenance, well workover and repair costs in E&P and higher turnaround and utility costs in R&M.

Impairment—expropriated assets reflects a second-quarter 2007 noncash impairment of $4,588 million before-tax related to the expropriation of our oil interests in Venezuela. For additional information, see the “Expropriated Assets” section of Note 13—Impairments, in our 2007 Annual Report on Form 10-K.

Taxes other than income taxes increased 23 percent and 21 percent during the second quarter and first six months of 2008, respectively, primarily due to increased production taxes in Alaska.

Interest and debt expense decreased 34 percent and 33 percent during both periods of 2008, respectively, primarily due to lower average debt levels.

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Segment Results

E&P

	Three Months Ended					Six Months Ended
	June 30					June 30
	2008		2007			2008		2007
	Millions of Dollars
Net Income (Loss)
Alaska	$	700		535			1,303		1,042
Lower 48		1,152		520			1,898		929
United States		1,852		1,055			3,201		1,971
International		2,147		(3,459	)		3,685		(2,046	)
	$	3,999		(2,404	)		6,886		(75	)

	Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)
United States	$	118.66	61.91	106.51	57.86
International		119.75	67.16	107.94	61.16
Total consolidated		119.24	64.55	107.27	59.61
Equity affiliates*		93.20	47.74	76.86	44.24
Worldwide E&P		118.01	61.97	105.68	57.53
Natural gas (per thousand cubic feet)
United States		9.69	6.49	8.67	6.34
International		10.02	6.42	9.15	6.46
Total consolidated		9.87	6.45	8.94	6.41
Equity affiliates*		—	.30	—	.30
Worldwide E&P		9.87	6.44	8.94	6.40
Natural gas liquids (per barrel)
United States		65.96	44.17	62.31	41.04
International		71.40	45.64	66.86	42.30
Total consolidated		68.42	44.80	64.40	41.60
Equity affiliates*		—	—	—	—
Worldwide E&P		68.42	44.80	64.40	41.60

	Millions of Dollars
Worldwide Exploration Expenses
General administrative; geological and geophysical; and lease rentals	$	161	126	316	240
Leasehold impairment		59	59	119	145
Dry holes		68	74	162	136
	$	288	259	597	521

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

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	Three Months Ended				Six Months Ended
	June 30				June 30
	2008		2007		2008		2007
	Thousands of Barrels Daily
Operating Statistics
Crude oil produced
Alaska		244		267		249		272
Lower 48		95		105		96		104
United States		339		372		345		376
Europe		194		193		198		214
Asia Pacific		86		93		88		95
Canada		24		19		23		20
Middle East and Africa		78		73		80		84
Other areas		10		10		10		10
Total consolidated		731		760		744		799
Equity affiliates*
Canada		25		28		27		26
Russia and Caspian		16		15		16		15
Venezuela		—		85		—		83
		772		888		787		923
Natural gas liquids produced
Alaska		17		18		18		20
Lower 48		76		71		73		70
United States		93		89		91		90
Europe		19		11		21		12
Asia Pacific		17		15		15		13
Canada		25		28		26		30
Middle East and Africa		2		2		2		2
		156		145		155		147

	Millions of Cubic Feet Daily
Natural gas produced**
Alaska		98	100	99	111
Lower 48		2,034	2,219	1,998	2,205
United States		2,132	2,319	2,097	2,316
Europe		880	921	952	1,003
Asia Pacific		616	603	602	601
Canada		1,055	1,133	1,078	1,142
Middle East and Africa		116	127	110	134
Other areas		19	21	20	22
Total consolidated		4,818	5,124	4,859	5,218
Equity affiliates*
Venezuela		—	9	—	9
		4,818	5,133	4,859	5,227

	Thousands of Barrels Daily
Mining operations
Syncrude produced		19	21	20	22

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

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

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The E&P segment explores for, produces, transports 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, 2008, our E&P operations were producing in the United States, Norway, the United Kingdom, the Netherlands, Canada, Nigeria, Ecuador, Argentina, offshore Timor-Leste in the Timor Sea, Australia, China, Indonesia, Algeria, Libya, Vietnam, and Russia.

The E&P segment reported net income of $3,999 million in the second quarter of 2008, compared with a net loss of $2,404 million in the second quarter of 2007. In the second quarter of 2007, we recorded a noncash impairment of $4,588 million before-tax ($4,512 million after-tax) related to the expropriation of our oil interests in Venezuela. For additional information, see the “Expropriated Assets” section of Note 13—Impairments, in our 2007 Annual Report on Form 10-K. In addition to the impact of the impairment, results for the second quarter of 2008 reflect higher crude oil, natural gas and natural gas liquids prices, partially offset by higher production taxes, lower volumes and higher operating costs.

Net income for the E&P segment for the first six months of 2008 was $6,886 million, compared with a net loss of $75 million for the corresponding period of 2007. In addition to the impact of the impairment noted above, the 2008 period benefited from higher crude oil, natural gas and natural gas liquids prices, partially offset by higher production taxes, lower volumes, higher operating costs, and a reduced net benefit from asset rationalization efforts. See the “Business Environment and Executive Overview” section for additional information on industry crude oil and natural gas prices.

U.S. E&P

Net income from our U.S. E&P operations increased 76 percent and 62 percent in the second quarter and six months of 2008, respectively, primarily due to higher crude oil, natural gas and natural gas liquids prices. The increases were partially offset by higher production taxes in Alaska, lower crude oil and natural gas volumes and higher operating costs.

U.S. E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 787,000 BOE per day in the second quarter of 2008, a decrease of 7 percent from 848,000 BOE per day in the second quarter of 2007. The production decrease was primarily due to normal field decline, as well as unplanned downtime.

We have a long-term terminal use agreement with Freeport LNG Development, L.P. (Freeport) for 0.9 billion cubic feet per day of capacity at Freeport’s 1.5-billion-cubic-feet-per-day liquefied natural gas (LNG) receiving terminal in Quintana, Texas. The terminal became operational late in the second quarter of 2008. Due to present market conditions, which favor the flow of LNG to European and Asian markets, our near-to-mid-term utilization of the terminal is expected to be limited. Due to the process-or-pay nature of the terminal use agreement, we are responsible for monthly payments to Freeport irrespective of whether we are utilizing the terminal for regasification. However, the financial impact of this capacity underutilization is not expected to be material to our future earnings or cash flows.

International E&P

Net income from our international E&P operations was $2,147 million and $3,685 million in the second quarter and first six months of 2008, respectively, compared with a net loss of $3,459 million and $2,046 million in the corresponding periods of 2007. In addition to the impact of the impairment of our oil interests in Venezuela, the 2008 periods benefited from higher crude oil, natural gas and natural gas liquids prices, partially offset by lower crude oil and natural gas volumes, lower foreign currency gains, and higher operating costs and taxes. The first six months of 2008 were also negatively impacted by a lower net benefit from asset rationalization efforts.

36

International E&P production averaged 944,000 BOE per day in the second quarter of 2008, a decrease of 9 percent from 1,041,000 BOE per day in the second quarter of 2007. Production decreased primarily due to the expropriation of our Venezuelan oil projects and normal field decline. These decreases were partially offset by production from new developments in Indonesia, Norway, the United Kingdom, and Canada.

Our Syncrude mining operations produced 19,000 barrels per day in the second quarter of 2008, compared with 21,000 barrels per day in the second quarter of 2007.

Midstream

	Three Months Ended				Six Months Ended
	June 30				June 30
	2008		2007		2008		2007
	Millions of Dollars
Net Income*	$	162		102		299		187
*Includes DCP Midstream-related net income:	$	137		76		255		126

	Dollars Per Barrel
Average Sales Prices
U.S. natural gas liquids*
Consolidated	$	68.21	45.19	64.15	41.46
Equity		62.53	44.30	59.51	40.43

*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*		196	211	197	204
Natural gas liquids fractionated**		162	176	158	175

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

**Excludes DCP Midstream.

The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract natural gas liquids from the raw gas stream. The remaining “residue” gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are fractionated—separated into individual components like ethane, butane and propane—and marketed as chemical feedstock, fuel, or blendstock. The Midstream segment consists of our 50 percent equity investment in DCP Midstream, LLC, as well as our other natural gas gathering and processing operations, and natural gas liquids fractionation and marketing businesses, primarily in the United States and Trinidad.

Net income from the Midstream segment increased 59 percent and 60 percent in the second quarter and first six months of 2008. The increase in both periods was primarily due to higher realized natural gas liquids prices, slightly offset by lower natural gas liquids extraction volumes in our consolidated operations.

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R&M

	Three Months Ended				Six Months Ended
	June 30				June 30
	2008		2007		2008		2007
	Millions of Dollars
Net Income
United States	$	587		1,879		1,022		2,775
International		77		479		162		719
	$	664		2,358		1,184		3,494

	Dollars Per Gallon
U.S. Average Sales Prices*
Gasoline
Wholesale	$	3.23	2.50	2.89	2.19
Retail		3.36	2.68	3.01	2.36
Distillates—wholesale		3.73	2.24	3.33	2.09

*Excludes excise taxes.

	Thousands of Barrels Daily
Operating Statistics
Refining operations*
United States
Crude oil capacity		2,008		2,033	2,008	2,033
Crude oil runs		1,891		1,896	1,848	1,917
Capacity utilization (percent)		94	%	93	92	94
Refinery production		2,095		2,087	2,043	2,119
International
Crude oil capacity		670		696	670	696
Crude oil runs		589		650	583	637
Capacity utilization (percent)		88	%	93	87	92
Refinery production		592		664	583	654
Worldwide
Crude oil capacity		2,678		2,729	2,678	2,729
Crude oil runs		2,480		2,546	2,431	2,554
Capacity utilization (percent)		93	%	93	91	94
Refinery production		2,687		2,751	2,626	2,773

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

Petroleum products sales volumes
United States
Gasoline	1,127	1,300	1,098	1,279
Distillates	912	827	890	845
Other products	404	503	394	491
	2,443	2,630	2,382	2,615
International	683	739	650	726
	3,126	3,369	3,032	3,341

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

Net income from the R&M segment decreased 72 percent during the second quarter of 2008 and 66 percent in the first six months of 2008. The decrease in both periods was primarily due to significantly lower domestic realized refining and marketing margins. Contributing to the lower refinery margins in the second quarter of 2008 were decreases in margins for secondary products, such as fuel oil, natural gas liquids and petroleum coke. Both periods were also impacted by higher turnaround and utility costs. The results for the six-month period of 2008 also included a lower net benefit from asset rationalization efforts.

U.S. R&M
Net income from our U.S. R&M operations decreased 69 percent in the second quarter of 2008 and 63 percent in the first six months of 2008. The decrease was primarily the result of lower refining and marketing margins and higher turnaround and utility costs.

Our U.S. refining capacity utilization rate was 94 percent in the second quarter of 2008, compared with 93 percent in the second quarter of 2007. The current year rate benefited from lower unplanned downtime.

International R&M
Net income from our international R&M operations decreased 84 percent in the second quarter of 2008 and 77 percent for the first six months of 2008. Contributing to the decrease in both periods were lower realized refining margins and a reduced net benefit from our asset rationalization efforts.

Our international refining capacity utilization rate was 88 percent in the second quarter of 2008, compared with 93 percent in the same quarter of 2007. The utilization rate was primarily impacted by reduced crude throughput at our Wilhelmshaven, Germany, refinery due to economic conditions, and planned maintenance at the Humber refinery in the United Kingdom.

LUKOIL Investment

	Millions of Dollars
	Three Months Ended				Six Months Ended
	June 30				June 30
	2008		2007		2008		2007
Net Income	$	774		526		1,484		782
Operating Statistics*
Net crude oil production (thousands of barrels daily)		387		427		390		411
Net natural gas production (millions of cubic feet daily)		363		278		383		293
Net refinery crude oil processed (thousands of barrels daily)		215		184		218		202
*Represents our net share of our estimate of LUKOIL’s production and processing.

This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia, which we account for under the equity method. As of June 30, 2008, our ownership interest in LUKOIL was 20 percent based on issued shares. Our ownership interest based on estimated shares outstanding, used for equity-method accounting, was also 20 percent at June 30, 2008. During the second quarter of 2008, our equity-method accounting ownership percentage was reduced from 20.6 to 20 percent as a result of LUKOIL’s issuance of treasury shares in connection with an acquisition.

39

Since LUKOIL’s accounting cycle close and preparation of U.S. generally accepted accounting principles financial statements occur subsequent to our reporting deadline, our equity earnings and statistics for our LUKOIL investment are estimated, based on current market indicators, publicly available LUKOIL operating results, and other objective data. Once the difference between actual and estimated results is known, an adjustment is recorded. This estimate-to-actual adjustment will be a recurring component of future period results. The adjustment to first-quarter 2008 estimates, recorded in the second quarter of 2008, decreased net income $120 million. This compares with a decrease to net income of $44 million in the second quarter of 2007.

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

Net income from the LUKOIL Investment segment increased 47 percent in the second quarter of 2008 and 90 percent in the first six months of 2008. The increase in net income from the second quarter of 2007 was primarily due to higher estimated realized prices, partially offset by higher estimated taxes and operating costs, as well as the net impact from the alignment of estimated net income to LUKOIL’s reported results. The increase in the first six months of 2008 was primarily due to higher estimated realized prices, partially offset by higher estimated taxes and operating costs.

Chemicals

	Millions of Dollars
	Three Months Ended				Six Months Ended
	June 30				June 30
	2008		2007		2008		2007
Net Income	$	18		68		70		150

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

Net income from the Chemicals segment decreased 74 percent and 53 percent in the second quarter of 2008 and first six months of 2008, respectively. The decrease in both periods was due to lower benzene and polyethylene margins as the result of significant increases in feedstock costs, as well as higher utility and turnaround costs. This decrease was partially offset by an asset retirement in 2007. Business conditions in the chemicals and plastics industry are expected to remain challenging in the near term.

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Emerging Businesses

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2008			2007			2008			2007
Net Income (Loss)
Power	$	26			(1	)		53			12
Other		(18	)		(11	)		(33	)		(25	)
	$	8			(12	)		20			(13	)

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

The Emerging Businesses segment reported net income of $8 million in the second quarter of 2008, compared with a net loss of $12 million in the same quarter of 2007. Net income for the first six months of 2008 was $20 million, compared with a net loss of $13 million for the same period a year ago. The improvement for both periods primarily reflects improved international power generation results. The improvements were partially offset by lower domestic power results and increased technology spending.

Corporate and Other

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2008			2007			2008			2007
Net Income (Loss)
Net interest	$	(119	)		(224	)		(227	)		(468	)
Corporate general and administrative expenses		(68	)		(54	)		(112	)		(77	)
Acquisition/merger-related costs		—			(16	)		—			(29	)
Other		1			(43	)		(26	)		(104	)
	$	(186	)		(337	)		(365	)		(678	)

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 47 percent in the second quarter of 2008 and 51 percent in the first six months of 2008. The decrease in both periods was primarily due to lower average debt levels, as well as higher amounts of interest being capitalized. The first six months of 2008 also benefited from higher interest income.

Corporate general and administrative expenses increased 26 percent and 45 percent in the second quarter and first six months of 2008, respectively. The increase in both periods was primarily due to higher corporate staff costs and benefit-related expenses.

Acquisition-related costs in 2007 included transition costs associated with the Burlington Resources acquisition.

41

The category “Other” includes certain foreign currency transaction gains and losses, and environmental costs associated with sites no longer in operation. Included in the improved results from Other in the second quarter and first six months of 2008 were foreign currency gains in 2008, compared with losses in 2007, as well as lower environmental costs.

42

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

	Millions of Dollars
	At June 30			At December 31
	2008			2007
Short-term debt	$	385			1,398
Total debt*	$	21,924			21,687
Minority interests	$	1,144			1,173
Common stockholders’ equity	$	92,398			88,983
Percent of total debt to capital**		19	%		19
Percent of floating-rate debt to total debt		20	%		25

  *Total debt includes short-term and long-term debt, as shown on our consolidated balance sheet.

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

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from operating activities is the primary source of funding. In addition, during the first six months of 2008, we raised $441 million in proceeds from asset dispositions. During the first six months, available cash was used to support our ongoing capital expenditures and investments program, repurchase shares of our common stock, provide loan financing to certain equity affiliates, pay dividends, and meet the funding requirements to FCCL Oil Sands Partnership (FCCL). Total dividends paid on our common stock during the first six months were $1,449 million. During the first half of 2008, cash and cash equivalents decreased $669 million to $787 million.

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

Significant Sources of Capital

Operating Activities

During the first six months of 2008, cash of $12,021 million was provided by operating activities, a 3 percent increase from cash from operations of $11,639 million in the corresponding period of 2007. Contributing to the increase were higher commodity prices in our E&P segment, partially offset by lower U.S. refining and marketing margins, as well as higher volumetric inventory builds in our R&M segment.

While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, natural gas and natural gas liquids, as well as refining and marketing margins. During the first six months of 2008 and 2007, we benefited from favorable crude oil and natural gas prices. Prices and margins are driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.

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

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

Asset Sales

Proceeds from asset sales during the first half of 2008 were $441 million, compared with $2,215 million in the same period of 2007. Proceeds for both periods primarily reflect our ongoing efforts to dispose of assets that no longer fit into our strategic plans or those that could bring more value by being monetized in the near term.

Commercial Paper and Credit Facilities

At June 30, 2008, we had a $7.5 billion revolving credit facility, which expires in September 2012. This facility may be used as direct bank borrowings, as support for the ConocoPhillips $7.5 billion commercial paper program, as support for the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, or as support for issuances of letters of credit totaling up to $750 million. The facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The credit agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or by any of its consolidated subsidiaries. At June 30, 2008 and December 31, 2007, we had no outstanding borrowings under the credit facility, but $40 million and $41 million, respectively, in letters of credit had been issued. Under both commercial paper programs, $1,314 million of commercial paper was outstanding at June 30, 2008, compared with $725 million at December 31, 2007.

At June 30, 2008, our primary funding source for short-term working capital needs was the ConocoPhillips $7.5 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. The ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program is used to fund commitments relating to the Qatargas 3 project. Since we had $1,314 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $6.1 billion in borrowing capacity under our revolving credit facility at June 30, 2008.

Shelf Registrations

We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities. Under this shelf, in May 2008, we issued notes consisting of $400 million of 4.40% Notes due 2013, $500 million of 5.20% Notes due 2018 and $600 million of 5.90% Notes due 2038. The proceeds from the offering were used to reduce commercial paper and for general corporate purposes.

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

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Minority Interests

At June 30, 2008, we had outstanding $1,144 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 operating joint ventures we control. The largest of these, $620 million, was related to the Darwin LNG project located in northern Australia.

Off-Balance Sheet Arrangements

As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. At June 30, 2008, we were liable for certain contingent obligations under the following contractual arrangements:

• Qatargas 3:We own a 30 percent interest in Qatargas 3, an integrated project to produce and liquefy natural gas from Qatar’s North field. Our interest is held through a jointly owned company, Qatar Liquefied Gas Company Limited (3), for which we use the equity method of accounting. Qatargas 3 secured project financing of $4 billion in December 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA and commercial bank facilities. Prior to project completion certification, all loans, including the ConocoPhillips loan facilities, are guaranteed by the participants, based on their respective ownership interests. Accordingly, our maximum exposure to this financing structure is $1.2 billion, excluding accrued interest. Upon completion certification, currently expected in 2010, all project loan facilities, including the ConocoPhillips loan facilities, will become nonrecourse to the project participants. At June 30, 2008, Qatargas 3 had $2.6 billion outstanding under all the loan facilities, of which ConocoPhillips provided $787 million, and an additional $60 million of accrued interest.

• Rockies Express Pipeline LLC:In June 2006, we issued a guarantee for 24 percent of $2.0 billion in credit facilities issued to Rockies Express Pipeline LLC (Rockies Express). Rockies Express intends to construct a natural gas pipeline across a portion of the United States. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $480 million, which could become payable if the credit facility is fully utilized and Rockies Express fails to meet its obligations under the credit agreement. At June 30, 2008, Rockies Express had $740 million outstanding under the credit facilities, with our 24 percent guarantee equaling $178 million. In addition, we have a 24 percent guarantee on $600 million of Floating Rate Notes due 2009. It is anticipated that construction completion will be achieved in 2009, and refinancing will take place at that time, making the debt nonrecourse.

• Keystone Oil Pipeline:We own a 50 percent equity interest in the Keystone Oil Pipeline (Keystone), a joint venture with TransCanada Corporation. Keystone plans to construct a crude oil pipeline originating in Alberta, with delivery points in Illinois and Oklahoma. In connection with certain planning and construction activities, agreements were put in place with third parties to guarantee the payments due under those agreements. Our maximum potential amount of future payments under those agreements are estimated to be $400 million, which could become payable if Keystone fails to meet its obligations under the agreements noted above and the obligation cannot otherwise be mitigated. Payments under the guarantees are contingent upon the partners not making necessary equity contributions into Keystone; therefore, it is considered unlikely that payments would be required. All but $15 million of the guarantees will terminate after construction is completed, currently estimated to be in 2010.

For additional information about guarantees, see Note 11—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

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Capital Requirements

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

Our debt balance at June 30, 2008, was $21.9 billion, a slight increase from the balance at December 31, 2007.

In January 2008, we reduced our Floating Rate Five-Year Term Note due 2011 from $3 billion to $2 billion, with a subsequent reduction in June 2008 to $1.5 billion. In March 2008, we redeemed our $300 million 7.125% Debentures due 2028 at a premium of $8 million, plus accrued interest.

On January 3, 2007, we closed on a business venture with EnCana. As part of this transaction, we are obligated to contribute $7.5 billion, plus interest, over a ten-year period, which began in 2007, to the upstream business venture, FCCL, formed as a result of the transaction. Quarterly principal and interest payments of $237 million began in the second quarter of 2007, and will continue until the balance is paid. Of the principal obligation amount, approximately $609 million is short-term and is included in the “Accounts payable—related parties” line on our June 30, 2008, consolidated balance sheet. The principal portion of these payments, which totaled $293 million in the first six months of 2008, is presented on our consolidated statement of cash flows as an other financing activity. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

At year-end 2007, approximately $10.1 billion remained authorized for share repurchases in 2008 for our share repurchase programs announced in 2007. During the first six months of 2008, we repurchased 60.4 million shares of our common stock at a cost of $5.0 billion. We anticipate third-quarter 2008 share repurchases to be $2 billion to $3 billion.

In December 2005, we entered into a credit agreement with Qatargas 3, whereby we will provide loan financing of approximately $1.2 billion for the construction of an LNG train in Qatar. This financing will represent 30 percent of the project’s total debt financing. Through June 30, 2008, we had provided $787 million in loan financing, and an additional $60 million of accrued interest. See the “Off-Balance Sheet Arrangements” section for additional information on Qatargas 3.

In 2004, we finalized our transaction with Freeport to participate in a proposed LNG receiving terminal in Quintana, Texas. We entered into a credit agreement with Freeport to provide loan financing of approximately $678 million, excluding accrued interest, for the construction of the facility. The terminal became operational late in the second quarter of 2008. Through June 30, 2008, we had provided $644 million in loan financing, and an additional $116 million of accrued interest.

In the fall of 2004, ConocoPhillips and LUKOIL agreed to the expansion of the Varandey terminal as part of our investment in the OOO Naryanmarneftegaz (NMNG) joint venture. We have an obligation to provide loan financing to Varandey Terminal Company for 30 percent of the costs of the terminal expansion, but we will have no governance or ownership interest in the terminal. We estimate our total loan obligation for the terminal expansion to be approximately $390 million at current exchange rates, excluding interest to be accrued during construction. This amount will be adjusted as the project’s cost estimate and schedule are updated and the ruble exchange rate fluctuates. Through June 30, 2008, we had provided $359 million in loan financing, and an additional $46 million of accrued interest.

The long-term portion of our loans to Qatargas 3, Freeport and Varandey Terminal Company are included in the “Loans and advances—related parties” line on the balance sheet, while the short-term portion is in “Accounts and notes receivable—related parties.”

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Contractual Obligations

Our contractual purchase obligations at June 30, 2008, were estimated to be $166 billion, an increase of $40 billion from the amount reported at December 31, 2007, of $126 billion. The increase primarily results from higher crude oil, natural gas and natural gas liquids prices.

Capital Spending

Capital Expenditures and Investments

	Millions of Dollars
	Six Months Ended
	June 30
	2008		2007
E&P
United States—Alaska	$	890		324
United States—Lower 48		1,735		1,392
International		2,999		3,002
		5,624		4,718
Midstream		—		2
R&M
United States		677		388
International		196		88
		873		476
LUKOIL Investment		—		—
Chemicals		—		—
Emerging Businesses		112		65
Corporate and Other		111		86
	$	6,720		5,347
United States	$	3,413		2,191
International		3,307		3,156
	$	6,720		5,347

E&P

Capital expenditures and investments for E&P during the first six months of 2008 totaled $5.6 billion. The expenditures supported key exploration and development projects including:

• Significant U.S. lease acquisitions in the Chukchi Sea federal waters, offshore Alaska, as well as acquisitions in the deepwater Gulf of Mexico.

• Other Alaska activities related to development drilling in the Greater Kuparuk Area, including West Sak; the Greater Prudhoe Bay Area; the Alpine field, including satellite field prospects; the Cook Inlet Area; as well as exploration activities.

• Oil and natural gas developments in the Lower 48 states, including New Mexico, Texas, Louisiana, Oklahoma, Montana, North Dakota, Colorado, Wyoming, and offshore in the Gulf of Mexico.

• Investment in the West2East Pipeline LLC (West2East), a company holding a 100 percent interest in Rockies Express Pipeline LLC (Rockies Express).

• The development of the Surmont heavy-oil project, investments related to FCCL, and development of conventional oil and gas reserves, all in Canada.

• Development drilling and facilities projects in the Greater Ekofisk Area and Alvheim project in the Norwegian North Sea.

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• The Britannia satellite developments in the U.K. North Sea.

• An integrated project to produce and liquefy natural gas from Qatar’s North field.

• The Kashagan field in the Caspian Sea, offshore Kazakhstan.

• Development of the Yuzhno Khylchuyu (YK) field in the northern part of Russia’s Timan-Pechora province through the NMNG joint venture with LUKOIL.

• The Peng Lai 19-3 development in China’s Bohai Bay.

• The Gumusut-Kakap development offshore Sabah, Malaysia.

• Projects offshore Block B and onshore South Sumatra in Indonesia.

During the second quarter of 2008, affiliates of ConocoPhillips and BP Plc formed a limited liability company to progress the pipeline project named Denali—The Alaska Gas Pipeline. The project, which would move approximately four billion cubic feet per day of Alaska natural gas to North American markets, consists of a gas treatment plant on Alaska’s North Slope and a large-diameter pipeline through Alaska to Alberta, Canada. Should it be required to transport gas from Alberta, the project also could include a large-diameter pipeline from Alberta to the Lower 48 states. Summer fieldwork related to the project began in late May, primarily in eastern Alaska, and involves route reconnaissance and environmental studies. In late June 2008, the Federal Regulatory Commission (FERC) approved the Denali project to use the FERC’s prefiling process.

In July 2008, we announced the signing of an interim agreement with the Abu Dhabi National Oil Company (ADNOC) to develop the Shah gas field in Abu Dhabi. Final project agreements are expected to be completed by year-end 2008. ADNOC will have a 60 percent interest and we will have a 40 percent interest in the project.

R&M

Capital spending for R&M during the first six months of 2008 totaled $873 million and included projects to meet environmental standards and improve the operating integrity, safety and energy efficiency of processing units. Capital also was spent on pipeline development and refinery upgrade projects to increase crude oil capacity, expand conversion capability and increase clean product yield.

Major project activities in progress include:

• Expansion of a hydrocracker at the Rodeo facility of our San Francisco refinery.

• Investment in the Keystone Oil Pipeline.

• U.S. programs aimed at air emission reductions.

Through our joint ventures with TransCanada, we plan to expand the Keystone crude oil pipeline system and provide additional capacity of 500,000 barrels per day from western Canada to the U.S. Gulf Coast. Targeted for completion in 2012, this expansion would increase the capacity of the Keystone pipeline system to approximately 1.1 million barrels per day.

In May 2008, we and the Saudi Arabian Oil Company announced the two companies had approved continued funding for the development of the Yanbu Export Refinery project. Each company would be responsible for marketing one-half of the refinery’s production. The refinery is targeted to start up in 2013.

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Contingencies

Legal and Tax Matters

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

Environmental

We are subject to the same numerous international, federal, state, and local environmental laws and regulations, as are other companies in the petroleum exploration and production, refining and crude oil and refined product marketing and transportation businesses. For a discussion of the most significant of these environmental laws and regulations, including those with associated remediation obligations, see the “Environmental” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 81 through 84 of our 2007 Annual Report on Form 10-K.

We, from time to time, receive requests for information or notices of potential liability from the Environmental Protection Agency and state environmental agencies alleging that we are a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act (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, 2007, we reported we had been notified of potential liability under CERCLA and comparable state laws at 68 sites around the United States. At June 30, 2008, we reopened and closed one site, resolved and closed four sites, and received two new notices of potential liability, leaving 66 unresolved sites where we have been notified of potential liability.

At June 30, 2008, our balance sheet included a total environmental accrual of $1,046 million, compared with $1,089 million at December 31, 2007. 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 effect on our results of operations or financial position as a result of compliance with environmental laws and regulations.

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NEW ACCOUNTING STANDARDS

In December 2007, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 141 (Revised), “Business Combinations” (SFAS No. 141(R)). This Statement will apply to all transactions in which an entity obtains control of one or more other businesses. In general, SFAS No. 141(R) requires the acquiring entity in a business combination to recognize the fair value of all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date as the fair value measurement point; and modifies the disclosure requirements. This Statement applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. However, starting January 1, 2009, accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for prior business combinations will impact tax expense instead of impacting goodwill. We are currently evaluating the changes provided for in this Statement.

Also in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51,” which changes the classification of noncontrolling interests, sometimes called a minority interest, in the consolidated financial statements. Additionally, this Statement establishes a single method of accounting for changes in a parent company’s ownership interest that do not result in deconsolidation and requires a parent company to recognize a gain or loss when a subsidiary is deconsolidated. This Statement is effective January 1, 2009, and will be applied prospectively with the exception of the presentation and disclosure requirements which must be applied retrospectively for all periods presented. We are currently evaluating the impact of this Statement on our consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB No. 133.” This Statement expands the annual and interim disclosure requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” for derivative instruments within the scope of that Statement. We must adopt SFAS No. 161 no later than January 1, 2009, but it will not have any impact on our consolidated financial statements, other than the additional disclosures.

OUTLOOK

In E&P, we expect our third-quarter 2008 production to be similar to the level in the second quarter of 2008. We expect full-year 2008 production will be consistent with our operating plan.

In R&M, we expect our U.S. crude oil capacity utilization in the third quarter of 2008 to be similar to the second quarter. In international refining, utilization at our Wilhelmshaven refinery will continue to be impacted by hydro-skimming margins.

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

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

We based the forward-looking statements relating to our operations on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you that these statements are not guarantees of future performance and involve risks, uncertainties and assumptions 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.

• 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 or the inability to obtain access to exploratory acreage.

• 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, manufacturing, refining or transportation projects.

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

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

• Inability to timely obtain or maintain permits, including those necessary for construction of LNG terminals or regasification facilities, or refinery projects; 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, refinery and transportation projects.

• 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.

• Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations.

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

• Liability resulting from litigation.

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

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

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

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

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• The factors set forth under the heading “Risk Factors” on pages 34 through 39 of our 2007 Annual Report on Form 10-K.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the six months ended June 30, 2008, does not differ materially from that discussed under Item 7A of ConocoPhillips’ Annual Report on Form 10-K for the year ended December 31, 2007.

Item 4. CONTROLS AND PROCEDURES

As of June 30, 2008, with the participation of our management, our Chairman, President and Chief Executive Officer (principal executive officer) and our Executive Vice President, Finance, and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the Act), of the effectiveness of the design and operation of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman, President and Chief Executive Officer and our Executive Vice President, Finance, and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of June 30, 2008.

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

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the second quarter of 2008 and any material developments with respect to matters previously reported in ConocoPhillips’ 2007 Annual Report on Form 10-K or first-quarter 2008 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.

Our U.S. refineries are implementing two separate consent decrees, regarding alleged violations of the Federal Clean Air Act, with the U.S. Environmental Protection Agency (EPA), six states and one local air pollution agency. Some of the requirements and limitations contained in the decrees provide for stipulated penalties for violations. Stipulated penalties under the decrees are not automatic, but must be requested by one of the agency signatories. As part of periodic reports under the decrees and/or other reports required by permits or regulations, we occasionally report matters which could be subject to a request for stipulated penalties. If a specific request for stipulated penalties meeting the reporting threshold set forth in U.S. Securities and Exchange Commission rules is made pursuant to these decrees based on a given reported exceedance, we will separately report that matter and the amount of the proposed penalty.

New Matters

On July 16, 2008, ConocoPhillips received a demand from the Bay Area Air Quality Management District (BAAQMD) to settle 24 Notices of Violation (NOVs) issued in late 2006 and 2007 for alleged violations of air pollution control regulations at the San Francisco refinery. The amount of the settlement demand is $304,500. We intend to work with BAAQMD to resolve these NOVs.

On June 19, 2008, the Trainer refinery received a demand for stipulated penalties under the Refinery Enforcement Initiative Consent Decree in the amount of $110,000 for alleged violations associated with its leak detection and repair program. We intend to work with U.S. EPA and the Pennsylvania Department of Environmental Protection (PADEP) to resolve this matter.

On June 2, 2008, the Billings refinery received a Violation Letter from the Montana Department of Environmental Quality (MDEQ) for opacity and nickel emissions, which occurred during startup of the cat cracker in April 2007. The letter also alleged certain monitoring quality assurance/quality control violations. The letter requests a penalty of $604,000. We intend to work with the MDEQ to resolve this matter.

Matters Previously Reported

The South Coast Air Quality Management District (SCAQMD) conducted an audit of the Los Angeles refinery to assess compliance with applicable local, state, and federal regulations related to fugitive emissions. As a result of the audit, SCAQMD issued three NOVs alleging multiple counts of noncompliance. We reached an agreement with SCAQMD to settle two of the three NOVs for $42,500 and are working with SCAQMD to resolve the third NOV.

On September 25, 2007, the Sweeny refinery received a draft order to resolve a July 6, 2007, Notice of Enforcement (NOE) relating to alleged violations of the Texas Clean Air Act. The allegations relate to compliance with limitations contained in the refinery’s Title V operating permit and one emission event. In November 2007, we paid $114,450 as a penalty and agreed to fund a Supplemental Environmental Project (SEP) in the same amount. The settlement was approved by the Texas Commission on Environmental Quality (TCEQ) on May 22, 2008.

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In June 2007, the U.S. EPA informed the Ferndale refinery it will seek penalties for Ferndale’s alleged failure to comply with certain portions of the Benzene Waste Operations rule. The government alleges the facility has not complied with certain equipment maintenance and inspection rules since 1993. The parties have reached an agreement, which resolves the matter. The agreement specifies a penalty of $60,000, an SEP valued at $200,000 and injunctive actions. The agreement has been incorporated into an amendment to an existing consent decree, which was lodged on June 24, 2008.

The U.S. EPA and the PADEP informed the Trainer refinery they intend to seek penalties for acid gas flaring which allegedly occurred between April 2, 2007, and May 19, 2007. The parties have reached an agreement, which resolves the matter. The agreement has been incorporated into an amendment to an existing consent decree, which was lodged on June 24, 2008.

On April 30, 2007, the Borger refinery received an offer to settle a range of violations alleged in a March 16, 2007, NOE issued by the TCEQ. The alleged violations relate to air quality permit limits, emission events, testing requirements, and reporting or recordkeeping requirements. In November 2007, we submitted payment of a penalty of $84,900 and agreed to fund an SEP valued at $84,900. The settlement was approved by the TCEQ on May 13, 2008.

In March 2005, ConocoPhillips Pipe Line Company (CPPL) received a Notice of Probable Violation and Proposed Civil Penalty from the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (DOT) alleging violation of DOT operation and safety regulations at certain facilities in Kansas, Missouri, Illinois, Indiana, Wyoming and Nebraska. DOT is proposing penalties in the amount of $184,500. An information hearing was held on September 24, 2007. CPPL has provided additional information in support of its position. A DOT ruling is not anticipated until the fourth quarter of 2008.

In August of 2003, EPA Region 6 issued a Show Cause Order alleging violations of the Federal Clean Water Act at the Borger refinery. The alleged violations relate primarily to discharges of selenium and reported exceedances of permit limits for whole effluent toxicity. On April 7, 2008, a Consent Decree (CD) was lodged in the federal court for the Northern District of Texas, Amarillo Division. The CD requires a penalty of $1.2 million and an SEP valued at $600,000. After public notice and comment, the judge approved the consent decree and the penalty has been paid.

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Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2007.

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

Issuer Purchases of Equity Securities

									Millions of Dollars
						Total Number of			Approximate Dollar
						Shares Purchased as			Value of Shares
				Average Price		Part of Publicly			that May Yet Be
	Total Number of			Paid per Total		Announced Plans or			Purchased Under the
Period	Shares Purchased		*	Shares Purchased		Programs		**	Plans or Programs		**
April 1-30, 2008		10,761,518		$	80.26		10,755,700		$	6,737
May 1-31, 2008		9,236,776			89.03		9,217,080			5,916
June 1-30, 2008		8,894,997			93.43		8,864,300			5,088
Total		28,893,291		$	87.12		28,837,080

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

**On January 12, 2007, we announced a stock repurchase program that provided for the repurchase of up to $1 billion of the company’s common stock. On February 9, 2007, we announced plans to repurchase $4 billion of our common stock in 2007, including the $1 billion announced on January 12, 2007. On July 9, 2007, we announced plans to repurchase up to $15 billion of the company’s common stock through the end of 2008, which included the $2 billion remaining under the previously announced $4 billion program. Acquisitions for the share repurchase programs are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Repurchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plans are held as treasury shares.

55

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

We held our annual stockholders meeting on May 14, 2008. A brief description of each proposal and the voting results follow:

     A company proposal to elect three directors.

	Number of Shares
	Voted For		Voted Against		Abstain
Harold W. McGraw III		1,350,374,854		29,576,891		16,553,718
James J. Mulva		1,352,429,492		29,441,436		14,634,207
Bobby S. Shackouls		1,352,499,577		27,226,764		16,779,121

Those directors whose term of office continued were as follows: Richard L. Armitage, Richard H. Auchinleck, James E. Copeland, Jr., Kenneth M. Duberstein, Ruth R. Harkin, Harald J. Norvik, William K. Reilly, Victoria J. Tschinkel, Kathryn C. Turner and William E. Wade, Jr.

Results of other matters submitted to a vote were:

	Number of Shares
	Voted For		Voted Against		Abstain		Broker Nonvotes
Proposal to Amend By-Laws and Certificate of Incorporation for Annual Election of Directors		1,363,589,104		18,979,597		13,936,563		—
Ratification to Appoint Ernst & Young as ConocoPhillips’ Independent Registered Public Accounting Firm		1,375,375,305		7,831,658		13,298,300		—
Stockholder Proposal to Report on Recognition of Indigenous Rights		89,602,302		910,866,101		195,582,036		200,455,024
Stockholder Proposal for Advisory Vote on Executive Compensation		469,972,284		664,403,359		61,672,997		200,456,823
Stockholder Proposal on Political Contributions		287,338,404		730,470,975		178,241,060		200,455,024
Stockholder Proposal on Greenhouse Gas Reduction		293,016,777		704,412,443		198,621,220		200,455,023
Stockholder Proposal on Community Accountability		85,871,110		914,130,286		196,049,043		200,455,024
Stockholder Proposal on Drilling in Sensitive/Protected Areas		267,528,860		737,075,568		191,444,012		200,457,023
Stockholder Proposal on Environment Impact		276,223,532		728,791,844		191,035,065		200,455,022
Stockholder Proposal on Global Warming		36,783,213		967,166,684		192,100,693		200,454,873

All three nominated directors were elected, the appointment of the independent auditors was ratified, and a management proposal providing for the annual election of directors was approved. The eight stockholder proposals presented were not approved.

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Item 6. EXHIBITS

Exhibits

3.1	Amended and Restated Certificate of Incorporation
3.3	Amended and Restated By-Laws
10	First and Second Amendments to the ConocoPhillips Directors’ Charitable Gift Program.
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.

57

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) 

July 29, 2008

58

EXHIBIT INDEX

Exhibits

3.1	Amended and Restated Certificate of Incorporation
3.3	Amended and Restated By-Laws
10	First and Second Amendments to the ConocoPhillips Directors’ Charitable Gift Program.
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.