ConocoPhillips 10Q 2008 Q1 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended March 31, 2008


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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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). Yeso Noþ

The registrant had 1,542,446,703 shares of common stock, $.01 par value, outstanding at March 31, 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		20

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		27

Item 3. Quantitative and Qualitative Disclosures About Market Risk		47

Item 4. Controls and Procedures		47

Part II – Other Information

Item 1. Legal Proceedings		48

Item 1A. Risk Factors		50

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		50

Item 6. Exhibits		51

Signature		52
Computation of Ratio of Earnings to Fixed Charges
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Certifications Pursuant to Section 1350

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS



Consolidated Income Statement		ConocoPhillips


	Millions of Dollars
	Three Months Ended
	March 31
	2008			2007

Revenues and Other Income
Sales and other operating revenues*	$	54,883			41,320
Equity in earnings of affiliates		1,359			929
Other income		310			618

Total Revenues and Other Income		56,552			42,867


Costs and Expenses
Purchased crude oil, natural gas and products		37,820			26,715
Production and operating expenses		2,691			2,492
Selling, general and administrative expenses		526			527
Exploration expenses		309			262
Depreciation, depletion and amortization		2,209			2,024
Impairments		6			(1	)
Taxes other than income taxes*		5,155			4,374
Accretion on discounted liabilities		104			79
Interest and debt expense		207			307
Foreign currency transaction (gains) losses		(43	)		1
Minority interests		19			21

Total Costs and Expenses		49,003			36,801

Income before income taxes		7,549			6,066
Provision for income taxes		3,410			2,520

Net Income	$	4,139			3,546


Net Income Per Share of Common Stock(dollars)
Basic	$	2.65			2.15
Diluted		2.62			2.12


Dividends Paid Per Share of Common Stock(dollars)	$	.47			.41


Average Common Shares Outstanding(in thousands)
Basic		1,562,198			1,647,352
Diluted		1,582,025			1,668,847

*Includes excise taxes on petroleum products sales:	$	*3,857*			3,841


See Notes to Consolidated Financial Statements.



Consolidated Balance Sheet		ConocoPhillips


	Millions of Dollars
	March 31			December 31
	2008			2007
Assets
Cash and cash equivalents	$	1,423			1,456
Accounts and notes receivable (net of allowance of $62 million in 2008 and $58 million in 2007)		15,205			14,687
Accounts and notes receivable—related parties		1,946			1,667
Inventories		6,995			4,223
Prepaid expenses and other current assets		3,039			2,702

Total Current Assets		28,608			24,735
Investments and long-term receivables		32,732			31,457
Loans and advances—related parties		1,962			1,871
Net properties, plants and equipment		89,207			89,003
Goodwill		29,354			29,336
Intangibles		884			896
Other assets		531			459

Total Assets	$	183,278			177,757


Liabilities
Accounts payable	$	18,953			16,591
Accounts payable—related parties		1,741			1,270
Short-term debt		384			1,398
Accrued income and other taxes		7,076			4,814
Employee benefit obligations		597			920
Other accruals		2,374			1,889

Total Current Liabilities		31,125			26,882
Long-term debt		21,108			20,289
Asset retirement obligations and accrued environmental costs		7,360			7,261
Joint venture acquisition obligation—related party		6,141			6,294
Deferred income taxes		21,005			21,018
Employee benefit obligations		3,099			3,191
Other liabilities and deferred credits		2,714			2,666

Total Liabilities		92,552			87,601


Minority Interests		1,151			1,173


Common Stockholders’ Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2008—1,721,017,154 shares; 2007—1,718,448,829 shares)
Par value		17			17
Capital in excess of par		42,831			42,724
Grantor trusts (at cost: 2008—42,397,731 shares; 2007—42,411,331 shares)		(730	)		(731	)
Treasury stock (at cost: 2008—136,172,720 shares; 2007—104,607,149 shares)		(10,465	)		(7,969	)
Accumulated other comprehensive income		4,138			4,560
Unearned employee compensation		(122	)		(128	)
Retained earnings		53,906			50,510

Total Common Stockholders’ Equity		89,575			88,983

Total	$	183,278			177,757


See Notes to Consolidated Financial Statements.



Consolidated Statement of Cash Flows		ConocoPhillips


	Millions of Dollars
	Three Months Ended
	March 31
	2008			2007
Cash Flows From Operating Activities
Net income	$	4,139			3,546
Adjustments to reconcile net income to net cash provided by operating activities
Nonworking capital adjustments
Depreciation, depletion and amortization		2,209			2,024
Impairments		6			(1	)
Dry hole costs and leasehold impairments		154			148
Accretion on discounted liabilities		104			79
Deferred taxes		(17	)		77
Undistributed equity earnings		(987	)		(557	)
Gain on asset dispositions		(181	)		(499	)
Other		(164	)		(94	)
Working capital adjustments*
Decrease (increase) in accounts and notes receivable		(725	)		289
Increase in inventories		(2,783	)		(686	)
Decrease (increase) in prepaid expenses and other current assets		(372	)		67
Increase in accounts payable		2,822			1,539
Increase in taxes and other accruals		2,382			941

Net Cash Provided by Operating Activities		6,587			6,873


Cash Flows From Investing Activities
Capital expenditures and investments		(3,322	)		(2,847	)
Proceeds from asset dispositions		370			1,343
Long-term advances/loans—related parties		(67	)		(179	)
Collection of advances/loans—related parties		-			28
Other		7			7

Net Cash Used in Investing Activities		(3,012	)		(1,648	)


Cash Flows From Financing Activities
Issuance of debt		1,123			81
Repayment of debt		(1,325	)		(3,572	)
Issuance of company common stock		7			40
Repurchase of company common stock		(2,496	)		(1,000	)
Dividends paid on company common stock		(730	)		(674	)
Other		(196	)		(49	)

Net Cash Used in Financing Activities		(3,617	)		(5,174	)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		9			(8	)


Net Change in Cash and Cash Equivalents		(33	)		43
Cash and cash equivalents at beginning of period		1,456			817

Cash and Cash Equivalents at End of Period	$	1,423			860


*Net of acquisition and disposition of businesses.
See Notes to Consolidated Financial Statements.



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

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 March 31, 2008, was:


	Millions of Dollars
	Level 1			Level 2			Level 3			Total

Assets
Commodity derivatives	$	2,721			1,660			19			4,400
Foreign exchange derivatives		-			172			-			172
Nonqualified benefit plans		418			-			-			418

Total assets		3,139			1,832			19			4,990


Liabilities
Commodity derivatives	$	(2,677	)		(1,716	)		(72	)		(4,465	)
Foreign exchange derivatives		-			(33	)		-			(33	)

Total liabilities		(2,677	)		(1,749	)		(72	)		(4,498	)

Net assets (liabilities)		462			83			(53	)		492

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 19—Financial Instruments and Derivative Contracts, in our 2007 Annual Report on Form 10-K. 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.

Changes in the fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy at March 31, 2008, were:


	Millions
	of Dollars
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Balance at January 1, 2008	$	(34	)
Total gains (losses), realized and unrealized
Included in earnings or changes in net assets		(42	)
Included in other comprehensive income		-
Purchases, issuances and settlements		24
Transfers in and/or out of Level 3		(1	)

Balance at March 31, 2008	$	(53	)


The amount of total gains (losses) for the period included in earnings or changes in net assets attributable to the change in unrealized gains (losses) relating to assets held at March 31, 2008	$	1


The amount of total gains (losses) for the period included in earnings or changes in net assets attributable to the change in unrealized gains (losses) relating to liabilities held at March 31, 2008	$	(31	)

Gains and losses, realized and unrealized, included in earnings or changes in net assets for the three-month period ending March 31, 2008, were reported as follows:


	Millions of Dollars
				Purchased
	Other			Crude Oil
	Operating			Natural Gas
	Revenues			and Products		Total


Total gains (losses) included in earnings or changes in net assets	$	(43	)		1		(42	)


Change in unrealized gains (losses) relating to assets held at March 31, 2008	$	1			-		1


Change in unrealized gains (losses) relating to liabilities held at March 31, 2008	$	(31	)		-		(31	)

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. During the first quarter of 2008, we did not make the fair value election for any financial instruments not already carried at fair value in accordance with other accounting standards, so 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 March 31, 2008, the book value of our investment in West2East was $248 million. See Note 10—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 March 31, 2008, the book value of our investment in the venture was $1,929 million.

Note 4—Inventories

Inventories consisted of the following:


	Millions of Dollars
	March 31		December 31
	2008		2007


Crude oil and petroleum products	$	6,118		3,373
Materials, supplies and other		877		850

	$	6,995		4,223

Inventories valued on the last-in, first-out (LIFO) basis totaled $5,694 million and $2,974 million at March 31, 2008, and December 31, 2007, respectively. The remainder of our inventories are 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 $7,945 million and $6,668 million at March 31, 2008, and December 31, 2007, respectively.

Note 5—Assets Held for Sale

In 2006, we commenced asset rationalization efforts that led to the classification of certain assets as “held for sale” under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Accordingly, at December 31, 2007, we classified $1,092 million of noncurrent assets and $159 million of noncurrent liabilities as current assets and current liabilities, respectively.

During the first quarter 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 March 31, 2008, we classified $914 million of noncurrent assets as “Prepaid expenses and other current assets” on our consolidated balance sheet and we classified $139 million of noncurrent liabilities as current liabilities, consisting of $114 million in “Accrued income and other taxes” and $25 million in “Other accruals.” We expect the disposal of these assets to be 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
	March 31		December 31
	2008		2007


Assets
Investments and long-term receivables	$	4		48
Net properties, plants and equipment		834		946
Goodwill		66		89
Intangibles		2		2
Other assets		8		7

Total assets	$	914		1,092

Exploration and Production	$	154		189
Refining and Marketing		760		903

	$	914		1,092


Liabilities
Asset retirement obligations and accrued environmental costs	$	21		23
Deferred income taxes		114		133
Other liabilities and deferred credits		4		3

Total liabilities	$	139		159

Exploration and Production	$	27		35
Refining and Marketing		112		124

	$	139		159

Note 6—Investments, Loans and Long-Term Receivables

LUKOIL

Our ownership interest in LUKOIL was 20 percent at March 31, 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 20.6 percent at March 31, 2008.

At March 31, 2008, the book value of our ordinary share investment in LUKOIL was $11,896 million. Our share of the net assets of LUKOIL was estimated to be $9,382 million. This basis difference of $2,514 million is primarily being amortized on a unit-of-production basis. On March 31, 2008, the closing price of LUKOIL

shares on the London Stock Exchange was $85.80 per share, making the total market value of our LUKOIL investment $14,596 million.

Loans to Related Parties

As part of our normal ongoing business operations and consistent with industry practice, we invest and enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. Included in such activity are loans made to certain affiliated companies. Significant loans to affiliated companies at March 31, 2008, included the following:

	•		$612 million in loan financing and an additional $101 million of accrued interest to Freeport LNG 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.
	•		$355 million in loan financing and an additional $39 million of accrued interest to Varandey Terminal Company associated with the costs of a terminal expansion. We expect our total obligation for the terminal expansion to be approximately $386 million at current exchange rates, excluding interest to be accrued during construction.
	•		$733 million of project financing and an additional $52 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.

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
	March 31, 2008						December 31, 2007
	Gross		Accum.		Net		Gross		Accum.		Net
	PP&E		DD&A		PP&E		PP&E		DD&A		PP&E


E&P	$	104,570		32,714		71,856		102,550		30,701		71,849
Midstream		115		65		50		267		103		164
R&M		20,376		4,936		15,440		19,926		4,733		15,193
LUKOIL Investment		-		-		-		-		-		-
Chemicals		-		-		-		-		-		-
Emerging Businesses		1,254		171		1,083		1,204		138		1,066
Corporate and Other		1,479		701		778		1,414		683		731

	$	127,794		38,587		89,207		125,361		36,358		89,003

Suspended Wells

The company’s capitalized cost of suspended wells at March 31, 2008, was $669 million, an increase of $80 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, $9 million was charged to dry hole expense during the first three months of 2008.

Note 8—Debt

In January 2008, we repaid $1 billion of our Floating Rate Five-Year Term Note due 2011, reducing the outstanding balance to $2 billion. In March 2008, we redeemed our $300 million 7.125% Debentures due 2028 at a premium of $8 million, plus accrued interest.

At March 31, 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 March 31, 2008, and December 31, 2007, we had no outstanding borrowings under the credit facilities, but $40 million and $41 million, respectively, in letters of credit had been issued. Under both commercial paper programs, $1,856 million of commercial paper was outstanding at March 31, 2008, compared with $725 million at December 31, 2007.

Also at March 31, 2008, we classified $1,856 million of short-term debt as long-term debt, based on our ability and intent to refinance the obligation on a long-term basis under our revolving credit facilities.

Note 9—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, beginning 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 $601 million is short-term and is included in the “Accounts payable—related parties” line on our March 31, 2008, consolidated balance sheet. The principal portion of these payments, which totaled $145 million in the first three 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.

Note 10—Guarantees

At March 31, 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 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 March 31, 2008, Rockies Express had $1,523 million outstanding under the credit facilities, with our 24 percent guarantee equaling $366 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 March 31, 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.
	•		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, which is expected in 2010. At March 31, 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

•

At March 31, 2008, we had guarantees outstanding for our portion of joint-venture debt obligations, which have terms of up to 17 years. The maximum potential amount of future payments under the guarantees is approximately $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 17 years. Although there is no maximum limit stated in the agreement, the intent is to cover short-term cash deficiencies should they occur. Our maximum potential future payments under the agreement are currently estimated to be $100 million, assuming such a shortfall exists at some point in the future due to an extended operational disruption.
	•		In February 2003, we entered into two agreements establishing separate guarantee facilities of $50 million each for two LNG ships. Subject to the terms of each such facility, we will be required to make payments should the charter revenue generated by the respective ship fall below certain specified minimum thresholds, and we will receive payments to the extent that such revenues exceed those thresholds. The net maximum future payments that we may have to make over the 20-year terms of the two agreements could be up to $100 million in total. To the extent we receive any such payments, our actual gross payments over the 20 years could exceed that amount. In the event either ship is sold or a total loss occurs, we also may have recourse to the sales or insurance proceeds to recoup payments made under the guarantee facilities.
	•		We have guarantees of the residual value of leased corporate aircraft. The maximum potential payment under these guarantees at March 31, 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 March 31, 2008, was $452 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 $265 million of environmental accruals for known contamination that is included in asset retirement obligations and accrued environmental costs at March 31, 2008. For additional information about environmental liabilities, see Note 11—Contingencies and Commitments.

Note 11—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 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 March 31, 2008, our balance sheet included a total environmental accrual of $1,057 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 that there is only a remote likelihood that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our 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 March 31, 2008, we had performance obligations secured by letters of credit of $1,338 million (of which $40 million was issued under the provisions of our revolving credit facilities, and the remainder was issued as direct bank letters of credit) and various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.

Note 12—Comprehensive Income

ConocoPhillips’ comprehensive income was as follows:


	Millions of Dollars
	Three Months Ended
	March 31
	2008			2007


Net income	$	4,139			3,546
After-tax changes in:
Defined benefit pension plans
Net prior service cost		4			5
Net actuarial loss		9			16
Nonsponsored plans		2			(3	)
Foreign currency translation adjustments		(435	)		131
Hedging activities		(2	)		(1	)

Comprehensive income	$	3,717			3,694

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


	Millions of Dollars
	March 31			December 31
	2008			2007

Defined benefit pension plans	$	(450	)		(465	)
Foreign currency translation adjustments		4,598			5,033
Deferred net hedging loss		(10	)		(8	)

Accumulated other comprehensive income	$	4,138			4,560

Note 13—Cash Flow Information


	Millions of Dollars
	Three Months Ended
	March 31
	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	$	86		115
Income taxes		1,649		1,199

Note 14—Employee Benefit Plans

Pension and Postretirement Plans


	Millions of Dollars
	Pension Benefits												Other Benefits
Three Months Ended	March 31												March 31
	2008						2007						2008			2007
	U.S.			Int’l.			U.S.			Int'l.
Components of Net Periodic Benefit Cost
Service cost	$	47			23			44			24			3			3
Interest cost		62			44			57			38			12			11
Expected return on plan assets		(56	)		(44	)		(51	)		(35	)		-			-
Amortization of prior service cost		2			-			3			2			3			3
Recognized net actuarial loss (gain)		16			3			15			11			(4	)		(4	)

Net periodic benefit costs	$	71			26			68			40			14			13

During the first three months of 2008, we contributed $113 million to our domestic qualified and nonqualified plans and $48 million to our international benefit plans. We currently expect to contribute a total of $460 million to our domestic plans and $177 million to our international plans in 2008.

Note 15—Related Party Transactions

Significant transactions with related parties were:


	Millions of Dollars
	Three Months Ended
	March 31
	2008		2007


Operating revenues (a)	$	3,171		2,618
Purchases (b)		4,398		3,210
Operating expenses and selling, general and administrative expenses (c)		116		108
Net interest expense (d)		21		30



(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) 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. (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 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 16—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 March 31, 2008, our ownership interest was 20 percent based on issued shares, and 20.6 percent based on estimated shares outstanding.

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

	6)		Emerging Businesses—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.

Analysis of Results by Operating Segment


	Millions of Dollars
	Three Months Ended
	March 31
	2008			2007

Sales and Other Operating Revenues
E&P
United States	$	11,547			8,272
International		8,441			6,013
Intersegment eliminations—U.S.		(2,112	)		(1,156	)
Intersegment eliminations—international		(2,297	)		(1,441	)

E&P		15,579			11,688

Midstream
Total sales		1,642			1,105
Intersegment eliminations		(88	)		(59	)

Midstream		1,554			1,046

R&M
United States		26,961			20,039
International		10,926			8,635
Intersegment eliminations—U.S.		(219	)		(144	)
Intersegment eliminations—international		(7	)		(2	)

R&M		37,661			28,528

LUKOIL Investment		-			-
Chemicals		3			3

Emerging Businesses
Total sales		258			169
Intersegment eliminations		(177	)		(114	)

Emerging Businesses		81			55

Corporate and Other		5			-

Consolidated sales and other operating revenues	$	54,883			41,320


	Millions of Dollars
	Three Months Ended
	March 31
	2008			2007


Net Income (Loss)
E&P
United States	$	1,349			916
International		1,538			1,413

Total E&P		2,887			2,329

Midstream		137			85

R&M
United States		435			896
International		85			240

Total R&M		520			1,136

LUKOIL Investment		710			256
Chemicals		52			82
Emerging Businesses		12			(1	)
Corporate and Other		(179	)		(341	)

Consolidated net income	$	4,139			3,546


	Millions of Dollars
	March 31		December 31
	2008		2007

Total Assets
E&P
United States	$	36,263		35,160
International		59,426		59,412
Goodwill		25,587		25,569

Total E&P		121,276		120,141

Midstream		1,856		2,016

R&M
United States		27,296		24,336
International		10,517		9,766
Goodwill		3,767		3,767

Total R&M		41,580		37,869

LUKOIL Investment		11,896		11,164
Chemicals		2,273		2,225
Emerging Businesses		1,277		1,230
Corporate and Other		3,120		3,112

Consolidated total assets	$	183,278		177,757

Note 17—Income Taxes

Our effective tax rates for the first quarters of 2008 and 2007 were 45 percent and 42 percent, respectively. The change in the effective tax rate for the first quarter of 2008, versus the same period of 2007, was primarily due to the effect of our asset rationalization efforts during 2007, partially offset by a higher proportion of income in higher tax rate jurisdictions also during the 2007 quarter. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.

Note 18—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 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 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.

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.


	Millions of Dollars
	Three Months Ended March 31, 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	$	-				34,803			-		-			-			20,080		-			54,883
Equity in earnings of affiliates		4,185				3,061			-		-			-			1,308		(7,195	)		1,359
Other income		-				149			-		-			-			161		-			310
Intercompany revenues		9				717			24		23			14			6,050		(6,837	)		-

Total Revenues and Other Income		4,194				38,730			24		23			14			27,599		(14,032	)		56,552


Costs and Expenses
Purchased crude oil, natural gas and products		-				31,492			-		-			-			12,643		(6,315	)		37,820
Production and operating expenses		-				1,080			-		-			-			1,618		(7	)		2,691
Selling, general and administrative expenses		2				349			-		-			-			225		(50	)		526
Exploration expenses		-				55			-		-			-			254		-			309
Depreciation, depletion and amortization		-				372			-		-			-			1,837		-			2,209
Impairments		-				4			-		-			-			2		-			6
Taxes other than income taxes		-				1,254			-		-			-			3,962		(61	)		5,155
Accretion on discounted liabilities		-				15			-		-			-			89		-			104
Interest and debt expense		77				65			22		19			13			415		(404	)		207
Foreign currency transaction (gains) losses		-				(4	)		-		(72	)		(73	)		106		-			(43	)
Minority interests		-				-			-		-			-			19		-			19

Total Costs and Expenses		79				34,682			22		(53	)		(60	)		21,170		(6,837	)		49,003

Income before income taxes		4,115				4,048			2		76			74			6,429		(7,195	)		7,549
Provision for income taxes		(24	)			437			1		4			8			2,984		-			3,410

Net Income (Loss)	$	4,139				3,611			1		72			66			3,445		(7,195	)		4,139


	Millions of Dollars
	Three Months Ended March 31, 2007
							ConocoPhillips
							Australia		ConocoPhillips			ConocoPhillips
				ConocoPhillips			Funding		Canada Funding			Canada Funding			All Other			Consolidating			Total
Income Statement	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries			Adjustments			Consolidated

Revenues and Other Income
Sales and other operating revenues	$	-			25,977			-		-			-			15,343			-			41,320
Equity in earnings of affiliates		3,563			3,022			-		-			-			545			(6,201	)		929
Other income		-			(110	)		-		-			-			728			-			618
Intercompany revenues		89			698			30		19			12			3,813			(4,661	)		-

Total Revenues and Other Income		3,652			29,587			30		19			12			20,429			(10,862	)		42,867


Costs and Expenses
Purchased crude oil, natural gas and products		-			22,022			-		-			-			8,631			(3,938	)		26,715
Production and operating expenses		-			1,108			-		-			-			1,427			(43	)		2,492
Selling, general and administrative expenses		3			291			-		-			-			229			4			527
Exploration expenses		-			22			-		-			-			240			-			262
Depreciation, depletion and amortization		-			362			-		-			-			1,662			-			2,024
Impairments		-			(24	)		-		-			-			23			-			(1	)
Taxes other than income taxes		-			1,503			-		-			-			2,938			(67	)		4,374
Accretion on discounted liabilities		-			14			-		-			-			65			-			79
Interest and debt expense		112			355			28		19			13			397			(617	)		307
Foreign currency transaction (gains) losses		-			-			-		7			10			(16	)		-			1
Minority interests		-			-			-		-			-			21			-			21

Total Costs and Expenses		115			25,653			28		26			23			15,617			(4,661	)		36,801

Income before income taxes		3,537			3,934			2		(7	)		(11	)		4,812			(6,201	)		6,066
Provision for income taxes		(9	)		584			1		(7	)		(8	)		1,959			-			2,520

Net Income (Loss)	$	3,546			3,350			1		-			(3	)		2,853			(6,201	)		3,546


	Millions of Dollars
	At March 31, 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	$	-			131			-			6			-			1,432		(146	)		1,423
Accounts and notes receivable		34			12,021			24			12			4			19,752		(14,696	)		17,151
Inventories		-			4,373			-			-			-			2,624		(2	)		6,995
Prepaid expenses and other current assets		9			855			-			3			2			2,170		-			3,039

Total Current Assets		43			17,380			24			21			6			25,978		(14,844	)		28,608
Investments, loans and long-term receivables*		88,335			60,806			1,700			1,427			966			21,975		(140,515	)		34,694
Net properties, plants and equipment		-			17,921			-			-			-			71,274		12			89,207
Goodwill		-			12,732			-			-			-			16,622		-			29,354
Intangibles		-			800			-			-			-			84		-			884
Other assets		7			180			3			5			4			425		(93	)		531

Total Assets	$	88,385			109,819			1,727			1,453			976			136,358		(155,440	)		183,278


Liabilities and Stockholders’ Equity
Accounts payable	$	5			19,403			-			11			5			15,966		(14,696	)		20,694
Short-term debt		1			296			-			-			-			87		-			384
Accrued income and other taxes		-			1,288			-			-			(1	)		5,692		97			7,076
Employee benefit obligations		-			378			-			-			-			220		(1	)		597
Other accruals		36			751			29			32			22			1,428		76			2,374

Total Current Liabilities		42			22,116			29			43			26			23,393		(14,524	)		31,125
Long-term debt		4,481			5,398			1,699			1,250			848			7,432		-			21,108
Asset retirement obligations and accrued environmental costs		-			1,140			-			-			-			6,220		-			7,360
Joint venture acquisition obligation		-			-			-			-			-			6,141		-			6,141
Deferred income taxes		(3	)		3,005			-			34			25			17,928		16			21,005
Employee benefit obligations		-			2,213			-			-			-			886		-			3,099
Other liabilities and deferred credits*		734			17,635			-			64			31			14,358		(30,108	)		2,714

Total Liabilities		5,254			51,507			1,728			1,391			930			76,358		(44,616	)		92,552
Minority interests		-			(19	)		-			-			-			1,172		(2	)		1,151
Retained earnings		47,393			27,563			(1	)		(75	)		(41	)		23,209		(44,142	)		53,906
Other stockholders’ equity		35,738			30,768			-			137			87			35,619		(66,680	)		35,669

Total	$	88,385			109,819			1,727			1,453			976			136,358		(155,440	)		183,278


*Includes intercompany loans.


	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		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.


	Millions of Dollars
	Three Months Ended March 31, 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 (Used in) Operating Activities	$	3,143			729			1			(1	)		(1	)		3,455			(739	)		6,587


Cash Flows From Investing Activities
Capital expenditures and investments		-			(903	)		-			-			-			(2,570	)		151			(3,322	)
Proceeds from asset dispositions		-			2			-			-			-			368			-			370
Long-term advances/loans —related parties		-			(16	)		-			-			-			(296	)		245			(67	)
Collection of advances/loans—related parties		-			197			-			-			-			-			(197	)		-
Other		-			10			-			-			-			(3	)		-			7

Net Cash Used in Investing Activities		-			(710	)		-			-			-			(2,501	)		199			(3,012	)


Cash Flows From Financing Activities
Issuance of debt		1,078			243			-			-			-			47			(245	)		1,123
Repayment of debt		(1,000	)		(318	)		-			-			-			(204	)		197			(1,325	)
Issuance of company common stock		7			-			-			-			-			-			-			7
Repurchase of company common stock		(2,496	)		-			-			-			-			-			-			(2,496	)
Dividends paid on common stock		(731	)		-			(1	)		-			-			(964	)		966			(730	)
Other		(1	)		(8	)		-			-			-			(36	)		(151	)		(196	)

Net Cash Used in Financing Activities		(3,143	)		(83	)		(1	)		-			-			(1,157	)		767			(3,617	)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		-			-			-			-			-			9			-			9


Net Change in Cash and Cash Equivalents		-			(64	)		-			(1	)		(1	)		(194	)		227			(33	)
Cash and cash equivalents at beginning of year		-			195			-			7			1			1,626			(373	)		1,456

Cash and Cash Equivalents at End of Year	$	-			131			-			6			-			1,432			(146	)		1,423


	Millions of Dollars
	Three Months Ended March 31, 2007
							ConocoPhillips
							Australia			ConocoPhillips		ConocoPhillips
				ConocoPhillips			Funding			Canada Funding		Canada Funding		All Other			Consolidating			Total
Statement of Cash Flows	ConocoPhillips			Company			Company			Company I		Company II		Subsidiaries			Adjustments			Consolidated

Net Cash Provided by Operating Activities	$	4,678			21			1			-		-		2,142			31			6,873


Cash Flows From Investing Activities
Capital expenditures and investments		-			(444	)		-			-		-		(2,368	)		(35	)		(2,847	)
Proceeds from asset dispositions		-			92			-			-		-		1,251			-			1,343
Long-term advances/loans —related parties		-			(48	)		-			-		-		(932	)		801			(179	)
Collection of advances/loans—related parties		-			33			-			-		-		-			(5	)		28
Other		1			5			-			-		-		1			-			7

Net Cash Provided by (Used in) Investing Activities		1			(362	)		-			-		-		(2,048	)		761			(1,648	)


Cash Flows From Financing Activities
Issuance of debt		(16	)		801			-			-		-		97			(801	)		81
Repayment of debt		(3,028	)		(538	)		-			-		-		(11	)		5			(3,572	)
Issuance of company common stock		40			-			-			-		-		-			-			40
Repurchase of company common stock		(1,000	)		-			-			-		-		-			-			(1,000	)
Dividends paid on common stock		(674	)		-			(1	)		-		-		(61	)		62			(674	)
Other		(1	)		(24	)		-			-		-		(59	)		35			(49	)

Net Cash Provided by (Used in) Financing Activities		(4,679	)		239			(1	)		-		-		(34	)		(699	)		(5,174	)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		-			-			-			-		-		(8	)		-			(8	)


Net Change in Cash and Cash Equivalents		-			(102	)		-			-		-		52			93			43
Cash and cash equivalents at beginning of year		-			116			-			-		1		1,042			(342	)		817

Cash and Cash Equivalents at End of Year	$	-			14			-			-		1		1,094			(249	)		860


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 46.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

Our Exploration and Production (E&P) segment had net income of $2,887 million in the first quarter of 2008, which accounted for 70 percent of our total net income in the quarter. This compares with E&P net income of $2,608 million in the fourth quarter of 2007, and $2,329 million in the first quarter of 2007. Net income in the first quarter of 2008 was impacted by an increase in crude oil prices. Industry crude oil prices for West Texas Intermediate averaged $97.94 per barrel in the first quarter of 2008, or $7.28 per barrel higher than the fourth quarter of 2007, and $39.95 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 dollar, inflation and risk in credit markets.

Industry natural gas prices for Henry Hub increased during the first quarter of 2008 to $8.03 per million British thermal units (MMBTU), up $1.06 per MMBTU from the fourth quarter of 2007. Natural gas prices trended higher during the first quarter due to winter heating demand resulting from colder-than-normal winter weather conditions in parts of the United States, as well as declining liquefied natural gas (LNG) imports and natural gas imports via pipelines.

Our Refining and Marketing segment had net income of $520 million in the first quarter of 2008, compared with $1,122 million in the fourth quarter of 2007, and $1,136 million in the first quarter of 2007. Although global market cracks increased modestly versus the previous quarter, realized margins decreased due to the absence of inventory benefits realized in the fourth quarter of 2007, lower volumes, and lower realized product prices due to regional mix and refinery configuration. The decrease in earnings from the same period last year was the result of lower domestic crack spreads and lower volumes, partially offset by higher international market cracks.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three-month period ending March 31, 2008, is based on a comparison with the corresponding period of 2007.

Consolidated Results

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


	Millions of Dollars
	Three Months Ended
	March 31
	2008			2007


Exploration and Production (E&P)	$	2,887			2,329
Midstream		137			85
Refining and Marketing (R&M)		520			1,136
LUKOIL Investment		710			256
Chemicals		52			82
Emerging Businesses		12			(1	)
Corporate and Other		(179	)		(341	)

Net income	$	4,139			3,546

Net income was $4,139 million in the first quarter of 2008, compared with $3,546 million in the first quarter of 2007. The improved results in the first quarter of 2008 were primarily the result of:

	•		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.

	•		Lower interest and debt expense due to lower average debt levels.

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

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

Income Statement Analysis

Sales and other operating revenues increased 33 percent in the first quarter of 2008, while purchased crude oil, natural gas and products increased 42 percent in the same period. Both increases were mainly the result of higher petroleum product prices, and higher prices for crude oil, natural gas and natural gas liquids.

Equity in earnings of affiliates increased 46 percent in the first quarter of 2008, 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 natural gas liquids prices and volumes.

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

Other income decreased 50 percent during the first quarter of 2008. The decrease was primarily due to higher 2007 net gains on asset dispositions associated with asset rationalization efforts.

Taxes other than income taxes increased 18 percent during the first quarter of 2008, primarily due to increased production taxes in Alaska.

Interest and debt expense decreased 33 percent during the first quarter of 2008, primarily due to lower average debt levels.

Segment Results

E&P


	Three Months Ended
	March 31
	2008		2007
	Millions of Dollars


Net Income
Alaska	$	603		507
Lower 48		746		409

United States		1,349		916
International		1,538		1,413

	$	2,887		2,329


	Dollars Per Unit


Average Sales Prices
Crude oil (per barrel)
United States	$	94.02	53.78
International		95.32	56.29
Total consolidated		94.71	55.17
Equity affiliates*		62.78	40.02
Worldwide E&P		92.88	53.38
Natural gas (per thousand cubic feet)
United States		7.63	6.19
International		8.32	6.49
Total consolidated		8.03	6.36
Equity affiliates*		-	.29
Worldwide E&P		8.03	6.35
Natural gas liquids (per barrel)
United States		58.33	37.86
International		62.20	39.38
Total consolidated		60.14	38.56
Equity affiliates*		-	–
Worldwide E&P		60.14	38.56


	Millions of Dollars


Worldwide Exploration Expenses
General administrative, geological and geophysical, and lease rentals	$	155	114
Leasehold impairment		60	86
Dry holes		94	62

	$	309	262


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


	Three Months Ended
	March 31
	2008		2007
	Thousands of Barrels Daily


Operating Statistics
Crude oil produced
Alaska		254		276
Lower 48		97		104

United States		351		380
Europe		201		234
Asia Pacific		92		98
Canada		23		21
Middle East and Africa		81		96
Other areas		10		11

Total consolidated		758		840
Equity affiliates*
Canada		29		23
Russia and Caspian		16		15
Venezuela		-		82

		803		960


Natural gas liquids produced
Alaska		19		22
Lower 48		69		68

United States		88		90
Europe		23		14
Asia Pacific		15		12
Canada		26		31
Middle East and Africa		2		3

		154		150


	Millions of Cubic Feet Daily


Natural gas produced**
Alaska		100	122
Lower 48		1,963	2,190

United States		2,063	2,312
Europe		1,025	1,085
Asia Pacific		586	600
Canada		1,101	1,152
Middle East and Africa		105	142
Other areas		20	22

Total consolidated		4,900	5,313
Equity affiliates*
Venezuela		-	9

		4,900	5,322


	Thousands of Barrels Daily

Mining operations
Syncrude produced		20	23


*Excludes our equity share of LUKOIL, which is reported in the LUKOIL Investment segment.
**Represents quantities available for sale. Excludes gas equivalent of natural gas liquids shown above.

The E&P segment explores for, produces, 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 March 31, 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.

Net income for the E&P segment increased 24 percent in the first quarter of 2008, primarily due to higher crude oil, natural gas and natural gas liquids prices. This increase was partially offset by higher taxes, lower production, a reduced net benefit from asset rationalization efforts, and higher operating costs. 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 47 percent in the first quarter of 2008, primarily due to higher crude oil, natural gas and natural gas liquids prices. This increase was partially offset by higher production taxes in Alaska, lower crude oil and natural gas production levels, higher operating costs, and a reduced net benefit from asset rationalization efforts.

U.S. E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 783,000 BOE per day in the first quarter of 2008, a decrease of 8 percent from 855,000 BOE per day in the first quarter of 2007. The production decrease was primarily due to normal field decline, as well as unplanned downtime related to the shutdown of a non-operated natural gas processing plant in the San Juan Basin.

International E&P

Net income from our international E&P operations increased 9 percent in the first quarter of 2008, primarily due to higher crude oil, natural gas and natural gas liquids prices. This increase was partially offset by a lower net benefit from asset rationalization efforts, lower crude oil and natural gas production levels, and higher operating costs and taxes.

International E&P production averaged 991,000 BOE per day in the first quarter of 2008, a decrease of 13 percent from 1,142,000 BOE per day in the first quarter of 2007. Production decreased primarily due to the expropriation of our Venezuelan oil projects, normal field decline, our exit from Dubai, and unplanned downtime in the United Kingdom. These decreases were partially offset by production from new developments in Canada, the United Kingdom and Norway.

Our Syncrude mining operations produced 20,000 barrels per day in the first quarter of 2008, compared with 23,000 barrels per day in the first quarter of 2007.

Midstream


	Three Months Ended
	March 31
	2008		2007
	Millions of Dollars

Net Income*	$	137		85

*Includes DCP Midstream-related net income:	$	*118*		50


	Dollars Per Barrel

Average Sales Prices
U.S. natural gas liquids*
Consolidated	$	60.09	37.73
Equity		56.48	36.55


*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*		198	197
Natural gas liquids fractionated**		154	174


*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 61 percent in the first quarter of 2008. The increase was primarily due to higher equity earnings from DCP Midstream, resulting mainly from higher natural gas liquids prices and volumes, slightly offset by reduced marketing results and higher costs.

R&M


	Three Months Ended
	March 31
	2008		2007
	Millions of Dollars

Net Income
United States	$	435		896
International		85		240

	$	520		1,136


	Dollars Per Gallon

U.S. Average Sales Prices*
Gasoline
Wholesale	$	2.54	1.86
Retail		2.67	2.03
Distillates—wholesale		2.89	1.94


*Excludes excise taxes.


	Thousands of Barrels Daily

Operating Statistics
Refining operations*
United States
Crude oil capacity		2,008		2,033
Crude oil runs		1,806		1,938
Capacity utilization (percent)		90	%	95
Refinery production		1,991		2,152
International
Crude oil capacity		670		696
Crude oil runs		578		623
Capacity utilization (percent)		86	%	90
Refinery production		574		644
Worldwide
Crude oil capacity		2,678		2,729
Crude oil runs		2,384		2,561
Capacity utilization (percent)		89	%	94
Refinery production		2,565		2,796


*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	1,070	1,258
Distillates	869	862
Other products	384	480

	2,323	2,600
International	616	713

	2,939	3,313

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

Net income from the R&M segment decreased 54 percent during the first quarter of 2008, primarily due to lower domestic realized refining margins and volumes, as well as lower worldwide marketing volumes. These decreases were partially offset by higher international realized refining margins.

U.S. R&M

Net income from our U.S. R&M operations decreased 51 percent in the first quarter of 2008. The decrease was primarily the result of lower realized refining margins, lower refining and marketing volumes, and lower equity earnings from WRB Refining LLC (WRB). Our earnings from WRB were lower primarily due to lower margins, as well as lower volumes resulting partially from a decrease in our ownership interest in the Borger, Texas, refinery to 65 percent in 2008 from 85 percent in 2007.

Our U.S. refining capacity utilization rate was 90 percent in the first quarter of 2008, compared with 95 percent in the first quarter of 2007. The current year rate was impacted by higher planned maintenance at refineries in the East and Central regions, as well as unplanned downtime in the Gulf Coast refineries.

International R&M

Net income from our international R&M operations decreased 65 percent in the first quarter of 2008. The decrease was primarily due to reduced impairment estimates that positively impacted 2007 results. In addition, net income decreased due to lower marketing volumes resulting from asset dispositions. These decreases were partially offset by improved realized refining margins.

Our international refining capacity utilization rate was 86 percent in the first quarter of 2008, compared with 90 percent in the first quarter of 2007. The utilization rate was primarily impacted by reduced crude throughput at our Wilhelmshaven, Germany, facility due to economic conditions.

LUKOIL Investment


	Millions of Dollars
	Three Months Ended
	March 31
	2008		2007

Net Income	$	710		256


Operating Statistics*
Net crude oil production (thousands of barrels daily)		392		393
Net natural gas production (millions of cubic feet daily)		404		309
Net refinery crude oil processed (thousands of barrels daily)		222		219


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

This segment represents our investment in the ordinary shares of LUKOIL, an international, integrated oil and gas company headquartered in Russia, which we account for under the equity method. As of March 31, 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 20.6 percent at March 31, 2008. During the second quarter of 2008, we expect our equity-method accounting ownership percentage to be reduced to

approximately 20 percent as a result of LUKOIL’s issuance of treasury shares in connection with an acquisition.

Because LUKOIL’s accounting cycle close and preparation of U.S. generally accepted accounting principles financial statements occur subsequent to our reporting deadline, our equity earnings and statistics for our LUKOIL investment are estimated, based on current market indicators, 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.

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 177 percent in the first quarter of 2008, primarily due to higher estimated realized prices, partially offset by higher estimated taxes and operating costs.

Chemicals


	Millions of Dollars
	Three Months Ended
	March 31
	2008		2007


Net Income	$	52		82

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 37 percent in the first quarter of 2008, reflecting higher utility and turnaround costs, lower margins from aromatics and styrenics, and, to a lesser extent, lower margins from olefins and polyolefins.

Emerging Businesses


	Millions of Dollars
	Three Months Ended
	March 31
	2008			2007


Net Income (Loss)
Power	$	27			13
Other		(15	)		(14	)

	$	12			(1	)

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 $12 million in the first quarter of 2008, compared with a net loss of $1 million in the first quarter of 2007, primarily reflecting improved margins from the Immingham power plant in the United Kingdom. This increase was partially offset by the effects of unplanned downtime at the Immingham power plant and higher spending associated with alternative energy programs.

Corporate and Other


	Millions of Dollars
	Three Months Ended
	March 31
	2008			2007
Net Loss
Net interest	$	(108	)		(244	)
Corporate general and administrative expenses		(44	)		(23	)
Acquisition-related costs		-			(13	)
Other		(27	)		(61	)

	$	(179	)		(341	)

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 56 percent in the first quarter of 2008, primarily due to lower average debt levels. In addition, net interest decreased due to higher interest income, as well as higher amounts of interest being capitalized.

Corporate general and administrative expenses increased 91 percent in the first quarter of 2008, primarily due to higher corporate staff costs and benefit-related expenses.

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

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

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators


	Millions of Dollars
	At March 31			At December 31
	2008			2007

Short-term debt	$	384			1,398
Total debt*	$	21,492			21,687
Minority interests	$	1,151			1,173
Common stockholders’ equity	$	89,575			88,983
Percent of total debt to capital**		19	%		19
Percent of floating-rate debt to total debt		25	%		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 quarter of 2008, we raised $370 million in proceeds from asset dispositions. During the quarter, 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 quarter were $730 million. During the first quarter of 2008, cash and cash equivalents decreased $33 million to $1,423 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 quarter of 2008, cash of $6,587 million was provided by operating activities, a 4 percent decrease from cash from operations of $6,873 million in the corresponding period of 2007. Contributing to the decline was the impact of higher volumetric inventory builds than we experienced in the same period a year ago, due in part to the formation of WRB Refining LLC in the first quarter of 2007. Cash from operations in the second quarter of 2008 will be impacted by U.S. federal income tax payments, a semi-annual Norwegian income tax payment and Alaska production tax payments.

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

The level of our production volumes of crude oil, natural gas and natural gas liquids also impacts our cash flows. These production levels are impacted by such factors as acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiency, weather conditions, the addition of proved reserves through exploratory success, and the timely and cost-effective development of those proved reserves. While we actively manage 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 quarter of 2008 were $370 million, compared with $1,343 million in the same period of 2007. Amounts for both periods are mainly due to our ongoing asset rationalization efforts related to the program we announced in April 2006 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. Through March 31, 2008, this program had generated proceeds of approximately $4.1 billion since inception.

Commercial Paper and Credit Facilities

At March 31, 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 March 31, 2008 and December 31, 2007, we had no outstanding borrowings under the credit facilities, but $40 million and $41 million, respectively, in letters of credit had been issued. Under both commercial paper programs, $1,856 million of commercial paper was outstanding at March 31, 2008, compared with $725 million at December 31, 2007.

At March 31, 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 $1,856 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $5.6 billion in borrowing capacity under our revolving credit facility at March 31, 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.

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

Minority Interests

At March 31, 2008, we had outstanding $1,151 million of equity in less than wholly owned consolidated subsidiaries held by minority interest owners, including a minority interest of $507 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, $625 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 March 31, 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, which is expected in 2010, all project loan facilities, including the ConocoPhillips loan facilities, will become nonrecourse to the project participants. At March 31, 2008, Qatargas 3 had $2.4 billion outstanding under all the loan facilities, of which ConocoPhillips provided $733 million, and an additional $52 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 March 31, 2008, Rockies Express had $1,523 million outstanding under the credit facilities, with our 24 percent guarantee equaling $366 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 10—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Capital Requirements

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

Our debt balance at March 31, 2008, was $21.5 billion, a slight decrease from the balance at December 31, 2007.

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, beginning 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 $601 million is short-term and is included in the “Accounts payable—related parties” line on our March 31, 2008, consolidated balance sheet. The principal portion of these payments, which totaled $145 million in the first three 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 related to our share repurchase programs announced in 2007. During the first quarter of 2008, we repurchased 31.6 million shares of our common stock at a cost of $2.5 billion. We anticipate second-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 March 31, 2008, we had provided $733 million in loan financing, and an additional $52 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 LNG Development, L.P. (Freeport LNG) to participate in a proposed LNG receiving terminal in Quintana, Texas. We entered into a credit agreement with Freeport LNG to provide loan financing of approximately $678 million, excluding accrued interest, for the construction of the facility. Through March 31, 2008, we had provided $612 million in loan financing, and an additional $101 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 $386 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 March 31, 2008, we had provided $355 million in loan financing, and an additional $39 million of accrued interest.

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

In February 2008, we announced a quarterly dividend of 47 cents per share, representing a 15 percent increase over the previous quarter’s dividend of 41 cents per share. The dividend was paid March 3, 2008, to stockholders of record at the close of business February 25, 2008.

Capital Spending

Capital Expenditures and Investments


	Millions of Dollars
	Three Months Ended
	March 31
	2008		2007
E&P
United States—Alaska	$	191		158
United States—Lower 48		888		685
International		1,739		1,727

		2,818		2,570

Midstream		-		-

R&M
United States		295		168
International		68		37

		363		205

LUKOIL Investment		-		-
Chemicals		-		-
Emerging Businesses		61		31
Corporate and Other		80		41

	$	3,322		2,847

United States	$	1,454		1,052
International		1,868		1,795

	$	3,322		2,847

E&P

Capital spending for E&P during the first three months of 2008 totaled $2.8 billion. The expenditures supported key exploration and development projects including:

	•		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.
	•		Lease acquisitions in the deepwater 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, capital expenditures 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.
	•		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.

R&M

Capital spending for R&M during the first three months of 2008 totaled $363 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:

	•		Investment in the Keystone Oil Pipeline.
	•		Expansion of a hydrocracker at the Rodeo facility of our San Francisco refinery.
	•		U.S. programs aimed at air emission reductions.

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 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 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 March 31, 2008, we reopened and closed one site, and resolved and closed two sites, leaving 66 unresolved sites where we have been notified of potential liability.

At March 31, 2008, our balance sheet included a total environmental accrual of $1,057 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.

NEW ACCOUNTING STANDARDS

In December 2007, the Financial Accounting Standards Board (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 in this Statement.

OUTLOOK

Alaska Natural Gas Pipeline

On April 8, 2008, ConocoPhillips and BP Plc announced they had combined resources to start a pipeline project named Denali—The Alaska Gas Pipeline, which would move approximately four billion cubic feet per day of Alaska natural gas to North American markets. The project consists of a gas treatment plant on Alaska’s North Slope and a large-diameter pipeline that would travel over 700 miles through Alaska, and then into Canada through the Yukon Territory and British Columbia to Alberta. 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.

We and BP plan to spend a total of $600 million to reach the first major project milestone, an open season, commencing before year-end 2010. Following a successful open season, a process during which the pipeline company seeks customers to make long-term firm transportation commitments to the project, the companies intend to obtain Federal Energy Regulatory Commission (FERC) and the Canadian National Energy Board (NEB) certification and move forward with project construction.

Other

In E&P, we expect our second-quarter 2008 production to be lower than the level in the first quarter of 2008 due to scheduled maintenance.

During the first quarter, we participated in two offshore lease sales—one in Alaska’s Chukchi Sea and the other in the central deepwater Gulf of Mexico. We were the apparent high bidder on 98 blocks in the Chukchi Sea and 20 leases in the Gulf of Mexico, totaling in excess of $800 million. At April 28, 2008, we had received award notices for 84 of the Chukchi Sea blocks and two of the Gulf of Mexico leases. A significant portion of the capital outlays for these acquisitions will be recorded in the second quarter of 2008.

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 is expected to become operational late in the second quarter of 2008. Due to present market conditions which favor the flow of LNG to the European and Asian markets, our near-term utilization of the terminal is expected to be limited. We are currently evaluating the potential impact of these market conditions.

In R&M, we expect our crude oil capacity utilization in the second quarter of 2008 to be in the lower-90-percent range, as a result of planned maintenance at several facilities and the potential for ongoing weak margins at our Wilhelmshaven refinery.

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.

•

The factors generally described in the “Risk Factors” section included in “Items 1 and 2—Business and Properties” in our 2007 Annual Report on Form 10-K.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the three months ended March 31, 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 March 31, 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 March 31, 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.

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the first quarter of 2008 and any material developments with respect to matters previously reported in ConocoPhillips’ 2007 Form 10-K. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to the U.S. Securities and Exchange Commission’s regulations.

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 decree 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 decree 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 March 27, 2008, the Sweeny refinery received a Notice of Enforcement (NOE) from the Texas Commission on Environmental Quality (TCEQ) for an emissions event related to flaring that occurred on January 28, 2008. We have not received a penalty demand. We plan to work with TCEQ to resolve this matter.

On March 27, 2008, the Trainer refinery received a proposed Consent Assessment of Civil Penalty from the Pennsylvania Department of Environmental Protection (PADEP) for alleged air quality violations that occurred from 2002 to 2007. The assessment covers several categories of alleged air quality violations including emission events, air emissions inventory reporting, and violation of permit conditions. The proposed assessment requested a penalty of $130,215 and the purchase of certain volatile organic compound offsets at market prices. We intend to work with the PADEP to resolve this matter.

On February 11, 2008, ConocoPhillips Alaska, Inc. (CPAI) received a Violation Notice and Notice of Penalty (NOV) from the North Slope Borough (NSB) in relation to its Alpine facility on the North Slope of Alaska. The NOV alleges that three fuel tanks at the Alpine facility lacked adequate containment and/or setbacks from water bodies. There was no environmental impact due to these alleged violations. The NOV proposed penalties of $207,000, which was later reduced to $128,000. CPAI paid the reduced penalty under protest in accordance with the payment demands in the NOV. On March 11, 2008, CPAI filed an appeal with the NSB Planning Commission challenging the alleged violations and penalties in the NOV. We will continue to work with the NSB to resolve this matter.

In October 2003, the District Attorney’s Office in Sacramento, California filed a complaint in Superior Court for alleged methyl tertiary-butyl ether (MTBE) contamination in groundwater. On April 4, 2008, the District Attorney’s Office filed an amended complaint that included alleged violations of state regulations relating to operation or maintenance of underground storage tanks. There are numerous defendants named in the suit in addition to ConocoPhillips. We intend to continue to contest this lawsuit.

Matters Previously Reported

In June 2007, the U.S. Environmental Protection Agency (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 will be incorporated into an amendment to an existing consent decree expected to be lodged in the second quarter of 2008.

The 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 will be incorporated into an amendment to an existing consent decree that is expected to be lodged in the second quarter of 2008.

In March 2007, the Sweeny refinery received a series of NOEs from the TCEQ. These NOEs generally relate to emission events such as flaring and other unplanned releases. The TCEQ proposed a penalty of $325,120 in a revised draft order received in November 2007. We paid a penalty of $162,560 and agreed to fund a Supplemental Environmental Project (SEP) in the same amount upon final approval of the settlement by the TCEQ. The settlement agreement was approved by the TCEQ on February 27, 2008.

On February 7, 2007, Gulf Coast Fractionators, a gas processing facility operated by ConocoPhillips in which we have a 22.5 percent interest, received a draft order from the TCEQ proposing to settle alleged violations of air emission permit limits at the plant. The order proposed a penalty of $135,538. In October 2007, this matter was resolved by payment of a penalty of $67,769 and agreement to fund an SEP of $67,769. The settlement agreement was approved by the TCEQ on February 13, 2008.

In the fall of 2006, the Wood River refinery experienced two incidents where coker oil mist was released from the Distilling West coker. In a letter dated February 9, 2007, the state of Illinois demanded $50,000 for each release. During March 2008, we reached agreement with the state of Illinois to settle this matter for a cash penalty of $25,000 and performance of two local recycling events.

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, we expect the court to enter the decree and this matter will be resolved.

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

Programs

Plans or Programs

January 1-31, 2008

10,572,072

$ 79.79

10,571,000

$ 9,254

February 1-29, 2008

10,657,710

78.65

10,648,800

8,416

March 1-31, 2008

10,349,017

78.90

10,345,771

7,600

Total

31,578,799

$ 79.11

31,565,571


*	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.

Item 6. EXHIBITS

Exhibits


12		Computation of Ratio of Earnings to Fixed Charges.

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

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

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

SIGNATURE

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


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

April 30, 2008

EXHIBIT INDEX

Exhibits


12		Computation of Ratio of Earnings to Fixed Charges.

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

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

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

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

ConocoPhillips (COP) 10-Q2008 Q1 Quarterly report

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