ConocoPhillips (COP) 10-Q 2009 Q1 Quarterly report

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

FORM 10-Q

        (Mark One)

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

For the quarterly period ended           March 31, 2009

or

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

For the transition period from   to 

Commission file number:           001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [x] No [  ]

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 [x]  Accelerated filer [  ]  Non-accelerated filer [  ] Smaller reporting company [  ] 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [  ]  No [  ]

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

The registrant had 1,481,554,204 shares of common stock, $.01 par value, outstanding at March 31, 2009.

CONOCOPHILLIPS

TABLE OF CONTENTS

	Page
Part I — Financial Information
Item 1. Financial Statements
Consolidated Income Statement		1
Consolidated Balance Sheet		2
Consolidated Statement of Cash Flows		3
Notes to Consolidated Financial Statements		4
Supplementary Information—Condensed Consolidating Financial Information		24
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		28
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		49
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		49
Item 6. Exhibits		50
Signature		51
EX-12
EX-31.1
EX-31.2
EX-32

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

Consolidated Income Statement ConocoPhillips

	Millions of Dollars
	Three Months Ended
	March 31
	2009			2008
Revenues and Other Income
Sales and other operating revenues*	$	30,741			54,883
Equity in earnings of affiliates		415			1,359
Other income		124			310
Total Revenues and Other Income		31,280			56,552
Costs and Expenses
Purchased crude oil, natural gas and products		19,759			37,820
Production and operating expenses		2,545			2,691
Selling, general and administrative expenses		475			526
Exploration expenses		225			309
Depreciation, depletion and amortization		2,230			2,209
Impairments		3			6
Taxes other than income taxes*		3,464			5,155
Accretion on discounted liabilities		104			104
Interest and debt expense		310			207
Foreign currency transaction losses (gains)		131			(43	)
Total Costs and Expenses		29,246			48,984
Income before income taxes		2,034			7,568
Provision for income taxes		1,178			3,410
Net income		856			4,158
Less: net income attributable to noncontrolling interests		(16	)		(19	)
Net Income Attributable to ConocoPhillips	$	840			4,139
Net Income Attributable to ConocoPhillips Per Share of Common Stock(dollars)
Basic	$	.57			2.65
Diluted		.56			2.62
Dividends Paid Per Share of Common Stock(dollars)	$	.47			.47
Average Common Shares Outstanding(in thousands)
Basic		1,485,890			1,562,198
Diluted		1,495,247			1,582,025
*Includes excise taxes on petroleum products sales:	$	3,060			3,857
See Notes to Consolidated Financial Statements.

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Consolidated Balance Sheet ConocoPhillips

	Millions of Dollars
	March 31			December 31
	2009			2008
Assets
Cash and cash equivalents	$	802			755
Accounts and notes receivable (net of allowance of $109 million in 2009 and $61 million in 2008)		9,271			10,892
Accounts and notes receivable—related parties		1,048			1,103
Inventories		6,480			5,095
Prepaid expenses and other current assets		2,602			2,998
Total Current Assets		20,203			20,843
Investments and long-term receivables		31,724			30,926
Loans and advances—related parties		1,995			1,973
Net properties, plants and equipment		84,056			83,947
Goodwill		3,777			3,778
Intangibles		837			846
Other assets		659			552
Total Assets	$	143,251			142,865
Liabilities
Accounts payable	$	11,879			12,852
Accounts payable—related parties		1,442			1,138
Short-term debt		82			370
Accrued income and other taxes		4,143			4,273
Employee benefit obligations		673			939
Other accruals		2,111			2,208
Total Current Liabilities		20,330			21,780
Long-term debt		29,297			27,085
Asset retirement obligations and accrued environmental costs		7,177			7,163
Joint venture acquisition obligation—related party		5,507			5,669
Deferred income taxes		17,983			18,167
Employee benefit obligations		4,085			4,127
Other liabilities and deferred credits		2,679			2,609
Total Liabilities		87,058			86,600
Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2009—1,730,674,524 shares; 2008—1,729,264,859 shares)
Par value		17			17
Capital in excess of par		43,419			43,396
Grantor trusts (at cost: 2009—40,773,505 shares; 2008—40,739,129 shares)		(703	)		(702	)
Treasury stock (at cost: 2009—208,346,815 shares; 2008—208,346,815 shares)		(16,211	)		(16,211	)
Accumulated other comprehensive loss		(2,118	)		(1,875	)
Unearned employee compensation		(95	)		(102	)
Retained earnings		30,786			30,642
Total Common Stockholders’ Equity		55,095			55,165
Noncontrolling interests		1,098			1,100
Total Equity		56,193			56,265
Total Liabilities and Equity	$	143,251			142,865

See Notes to Consolidated Financial Statements.

2

Consolidated Statement of Cash Flows ConocoPhillips

	Millions of Dollars
	Three Months Ended
	March 31
	2009			2008
Cash Flows From Operating Activities
Net income	$	856			4,158
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		2,230			2,209
Impairments		3			6
Dry hole costs and leasehold impairments		123			154
Accretion on discounted liabilities		104			104
Deferred taxes		(219	)		(17	)
Undistributed equity earnings		(322	)		(987	)
Gain on asset dispositions		(39	)		(181	)
Other		(2	)		(183	)
Working capital adjustments
Decrease (increase) in accounts and notes receivable		1,860			(725	)
Increase in inventories		(1,454	)		(2,783	)
Increase in prepaid expenses and other current assets		(201	)		(372	)
Increase (decrease) in accounts payable		(529	)		2,822
Increase (decrease) in taxes and other accruals		(525	)		2,382
Net Cash Provided by Operating Activities		1,885			6,587
Cash Flows From Investing Activities
Capital expenditures and investments		(2,906	)		(3,322	)
Proceeds from asset dispositions		86			370
Long-term advances/loans—related parties		(88	)		(67	)
Collection of advances/loans—related parties		11			-
Other		(29	)		7
Net Cash Used in Investing Activities		(2,926	)		(3,012	)
Cash Flows From Financing Activities
Issuance of debt		6,033			1,123
Repayment of debt		(4,102	)		(1,325	)
Issuance of company common stock		(21	)		7
Repurchase of company common stock		-			(2,496	)
Dividends paid on company common stock		(696	)		(730	)
Other		(203	)		(196	)
Net Cash Provided by (Used in) Financing Activities		1,011			(3,617	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		77			9
Net Change in Cash and Cash Equivalents		47			(33	)
Cash and cash equivalents at beginning of period		755			1,456
Cash and Cash Equivalents at End of Period	$	802			1,423

See Notes to Consolidated Financial Statements.

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Notes to Consolidated Financial Statements ConocoPhillips

Note 1—Interim Financial Information

The interim-period financial information presented in the financial statements included in this report is unaudited and includes all known accruals and adjustments, in the opinion of management, necessary for a fair presentation of the consolidated financial position of ConocoPhillips and its results of operations and cash flows for such periods. All such adjustments are of a normal and recurring nature. To enhance your understanding of these interim financial statements, see the consolidated financial statements and notes included in our 2008 Annual Report on Form 10-K.

Note 2—Changes in Accounting Principles

SFAS No. 141 (Revised)
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)), which was subsequently amended by FASB Staff Position (FSP) FAS 141(R)-1 in April 2009. This Statement applies prospectively to all transactions in which an entity obtains control of one or more other businesses on or after January 1, 2009. 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 disclosure requirements. It also changes the accounting treatment for transaction costs, in-process research and development, restructuring costs, changes in deferred tax asset valuation allowances as a result of a business combination, and changes in income tax uncertainties after the acquisition date. Additionally, effective 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 impact tax expense instead of impacting goodwill.

SFAS No. 160
Effective January 1, 2009, we implemented SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51,” which requires noncontrolling interests, previously called minority interests, to be presented as a separate item in the equity section of the consolidated balance sheet. It also requires the amount of consolidated net income attributable to noncontrolling interests to be clearly presented on the face of the consolidated income statement. Additionally, this Statement clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions, and deconsolidation of a subsidiary requires gain or loss recognition in net income based on the fair value on the deconsolidation date. This Statement was applied prospectively with the exception of presentation and disclosure requirements, which were applied retrospectively for all periods presented, and did not significantly change the presentation of our consolidated financial statements. Equity attributable to noncontrolling interests did not change materially from year-end 2008 to March 31, 2009.

SFAS No. 161
We implemented SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB No. 133,” in the first quarter of 2009. This Statement does not affect amounts reported in the financial statements; it only expands the disclosure requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” for derivative instruments within the scope of that Statement, to provide greater transparency. Disclosures previously required only for the annual financial statements will now be required in quarterly financial statements. In addition, we now must include an indication of the volume of derivative activity by category (e.g., interest rate, commodity and foreign currency); derivative gains and losses, by category, for the periods presented in the financial statements; and expanded disclosures about credit-risk-related contingent features. This Statement is effective for interim and annual financial statements. See Note 12—Financial Instruments and Derivative Contracts, for additional information.

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SFAS No. 157
Effective January 1, 2008, we implemented 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 FSP FAS 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). Following the one-year deferral permitted by FSP FAS 157-2, effective January 1, 2009, we implemented SFAS No. 157 for nonfinancial assets and nonfinancial liabilities measured at fair value on a nonrecurring basis. The implementation covers assets and liabilities measured at fair value in a business combination; impaired properties, plants and equipment, intangible assets and goodwill; initial recognition of asset retirement obligations; and restructuring costs for which we use fair value. In the first three months of 2009, we did not have a business combination, impairment of goodwill or intangible asset, or restructuring accrual requiring the use of fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of properties, plants and equipment in step two of a SFAS No. 144 impairment test is determined based on the present values of expected future cash flows using inputs reflecting our estimate of a number of variables used by industry participants when valuing similar assets or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. Fair value used in the initial recognition of asset retirement obligations is determined based on the present value of expected future dismantlement costs incorporating our estimate of inputs used by industry participants when valuing similar liabilities. There was no impact to our consolidated financial statements from the implementation of SFAS No. 157 for nonfinancial assets and liabilities, and we do not expect any significant impact to our future consolidated financial statements, other than additional disclosures.

EITF No. 08-6
In November 2008, the FASB reached a consensus on Emerging Issues Task Force (EITF) Issue No. 08-6, “Equity Method Investment Accounting Considerations” (EITF 08-6), which was issued to clarify how the application of equity method accounting will be affected by SFAS No. 141(R) and SFAS No. 160. EITF 08-6 clarifies that an entity shall continue to use the cost accumulation model for its equity method investments. It also confirms past accounting practices related to the treatment of contingent consideration and the use of the impairment model under Accounting Principles Board (APB) Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock” (APB No. 18). Additionally, it requires an equity method investor to account for a share issuance by an investee as if the investor had sold a proportionate share of the investment. This Issue was effective January 1, 2009, and applies prospectively.

Note 3—Variable Interest Entities (VIEs)

We hold significant variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. Information on these VIEs follows.

We own a 24 percent interest in West2East Pipeline LLC, a company holding a 100 percent interest in Rockies Express Pipeline LLC, operated by Kinder Morgan Energy Partners, L.P. Rockies Express is constructing a natural gas pipeline from Colorado to Ohio. West2East is a VIE because a third party has a 49 percent voting interest through the end of the construction of the pipeline, but has no ownership interest. This third party was originally involved in the project, but exited and retained its voting interest to ensure project completion. We have no voting interest during the construction phase, but once the pipeline has been completed, our ownership will increase to 25 percent with a voting interest of 25 percent. Additionally, we have contracted for approximately 22 percent of the pipeline capacity for a 10-year period once the pipeline becomes operational. Construction commenced on the pipeline in 2006. The operator anticipates construction completion in late 2009 and estimates total construction costs of approximately $6.6 billion. Our portion is expected to be funded by a combination of equity contributions and a guarantee of debt incurred by Rockies Express. Given our 24 percent ownership and the fact expected returns are shared among the equity holders in proportion to ownership, we are not the primary beneficiary. We use the equity method of accounting for our investment. In 2006, 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 in August 2009 issued by Rockies Express. At March 31, 2009, the book value of our investment in West2East

5

was $260 million. Construction cost estimates have increased significantly from original projections, and additional increases or other changes related to the investment may impact whether an other-than-temporary impairment of our equity investment in West2East is required under APB No. 18.

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. When related parties are involved in a VIE, FASB Interpretation (FIN) 46(R) indicates that reasonable judgment should take into account the relevant facts and circumstances for the determination of the primary beneficiary. The activities of NMNG are more closely aligned with LUKOIL because they share Russia as a home country and LUKOIL conducts extensive exploration activities in the same province. Additionally, there are no financial guarantees given by LUKOIL or us, and LUKOIL owns 70 percent, versus our 30 percent direct interest. As a result, we have determined we are not the primary beneficiary of NMNG, and we use the equity method of accounting for this investment. The funding of NMNG has been provided with equity contributions for the development of the Yuzhno Khylchuyu (YK) field. Initial production from YK was achieved in June 2008. At March 31, 2009, the book value of our investment in the venture was $2,042 million.

Production from the NMNG joint venture fields is transported via pipeline to LUKOIL’s terminal at Varandey Bay on the Barents Sea and then shipped via tanker to international markets. LUKOIL completed an expansion of the terminal’s gross oil-throughput capacity from 30,000 barrels per day to 240,000 barrels per day, with us participating in the design and financing of the expansion. The terminal entity, Varandey Terminal Company, is a VIE because we and our related party, LUKOIL, have disproportionate interests. We had an obligation to fund, through loans, 30 percent of the terminal’s costs, but have no governance or direct ownership interest in the terminal. Similar to NMNG, we determined we are not the primary beneficiary for Varandey because of LUKOIL’s ownership, the activities are in LUKOIL’s home country, and LUKOIL is the operator of Varandey. We account for our loan to Varandey as a financial asset. Terminal construction was completed in June 2008, and the final loan amount was $249 million at March 2009 exchange rates, excluding accrued interest. Although repayments are not required to start until May 2010, beginning in the second half of 2008 and through March 31, 2009, Varandey used available cash to pay $23 million of interest. The outstanding accrued interest at March 31, 2009, was $31 million at March 2009 exchange rates.

We have an agreement with Freeport LNG Development, L.P. (Freeport LNG) to participate in a liquefied natural gas (LNG) receiving terminal in Quintana, Texas. We have no ownership in Freeport LNG; however, we own a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which serves as the general partner managing the venture. We entered into a credit agreement with Freeport LNG, whereby we agreed to provide loan financing for the construction of the terminal. We also entered into a long-term agreement with Freeport LNG to use 0.9 billion cubic feet per day of regasification capacity. The terminal became operational in June 2008, and we began making payments under the terminal use agreement. In August 2008, the loan was converted from a construction loan to a term loan and consisted of $650 million in loan financing and $124 million of accrued interest. Freeport LNG began making loan repayments in September 2008, and the loan balance outstanding as of March 31, 2009, was $747 million. Freeport LNG is a VIE because Freeport GP holds no equity in Freeport LNG and the limited partners of Freeport LNG do not have any substantive decision making ability. We performed an analysis of the expected losses and determined we are not the primary beneficiary. This expected loss analysis took into account that the credit support arrangement requires Freeport LNG to maintain sufficient commercial insurance to mitigate any loan losses. The loan to Freeport LNG is accounted for as a financial asset, and our investment in Freeport GP is accounted for as an equity investment.

In the case of Ashford Energy Capital S.A., we consolidate this entity in our financial statements because we are the primary beneficiary of this VIE based on an analysis of the variability of the expected losses and expected residual returns. In December 2001, in order to raise funds for general corporate purposes, ConocoPhillips and Cold Spring Finance S.a.r.l. formed Ashford through the contribution of a $1 billion ConocoPhillips subsidiary promissory note and $500 million cash by Cold Spring. Through its initial $500 million investment, Cold Spring is entitled to a cumulative annual preferred return consisting of 1.32 percent plus a three-month LIBOR rate set at the beginning of each quarter. The preferred return at

6

March 31, 2009, was 2.74 percent. In 2008, Cold Spring declined its option to remarket its investment in Ashford. This option remains available in 2018 and at each 10-year anniversary thereafter. If remarketing is unsuccessful, we could be required to provide a letter of credit in support of Cold Spring’s investment, or in the event such a letter of credit is not provided, cause the redemption of Cold Spring’s investment in Ashford. Should our credit rating fall below investment grade, Ashford would require a letter of credit to support $475 million of the term loans, as of March 31, 2009, made by Ashford to other ConocoPhillips subsidiaries. If the letter of credit is not obtained within 60 days, Cold Spring could cause Ashford to sell the ConocoPhillips subsidiary notes. At March 31, 2009, Ashford held $2 billion of ConocoPhillips subsidiary notes and $28 million in investments unrelated to ConocoPhillips. We report Cold Spring’s investment as a noncontrolling interest because it is not mandatorily redeemable, and the entity does not have a specified liquidation date. Other than the obligation to make payment on the subsidiary notes described above, Cold Spring does not have recourse to our general credit.

Note 4—Inventories

Inventories consisted of the following:

	Millions of Dollars
	March 31		December 31
	2009		2008
Crude oil and petroleum products	$	5,573		4,232
Materials, supplies and other		907		863
	$	6,480		5,095

Inventories valued on the last-in, first-out (LIFO) basis totaled $5,378 million and $3,939 million at March 31, 2009, and December 31, 2008, respectively. The remaining 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 $2,400 million and $1,959 million at March 31, 2009, and December 31, 2008, respectively.

Note 5—Assets Held for Sale

In January of 2009, we closed on the sale of a large part of our U.S. retail marketing assets, which included seller financing in the form of a $370 million five-year note and letters of credit totaling $54 million. In addition, we had smaller dispositions in the first quarter. Accordingly, at March 31, 2009, the balance of assets and liabilities held for sale was not material. We expect the disposal of the remaining held-for-sale assets to be completed in 2009.

Note 6—Investments, Loans and Long-Term Receivables

LUKOIL
Our ownership interest in LUKOIL was 20 percent at March 31, 2009, 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 20.09 percent at March 31, 2009.

At March 31, 2009, the book value of our ordinary share investment in LUKOIL was $5,494 million. Our 20 percent share of the net assets of LUKOIL was estimated to be $10,104 million. A majority of this negative basis difference of $4,610 million is being amortized on a straight-line basis over a 22-year useful life as an

7

increase to equity earnings. On March 31, 2009, the closing price of LUKOIL shares on the London Stock Exchange was $37.50 per share, making the total market value of our LUKOIL investment $6,379 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, 2009, included the following:

• $747 million in loan financing to Freeport LNG Development, L.P. for the construction of an LNG facility, which became operational in June 2008. In August 2008, when the loan was converted from a construction loan to a term loan, it consisted of $650 million in loan financing and $124 million of accrued interest. Freeport began making repayments in September 2008.

• $249 million at March 2009 exchange rates, excluding accrued interest, in loan financing to Varandey Terminal Company associated with the costs of a terminal expansion. Terminal expansion was completed in June 2008, and although repayments are not required to start until May 2010, beginning in the second half of 2008 and through March 31, 2009, Varandey used available cash to pay $23 million of interest. The outstanding accrued interest at March 31, 2009, was $31 million at March 2009 exchange rates.

• $923 million of project financing and an additional $79 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.

Other Investments
We have investments remeasured at fair value on a recurring basis to support certain nonqualified deferred compensation plans. The fair value of these assets at March 31, 2009, was $290 million, and substantially the entire value is categorized in Level 1 of the fair value hierarchy defined by SFAS No. 157.

Note 7—Properties, Plants and Equipment

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

	Millions of Dollars
	March 31, 2009						December 31, 2008
	Gross		Accum.		Net		Gross		Accum.		Net
	PP&E		DD&A		PP&E		PP&E		DD&A		PP&E
E&P	$	103,952		36,947		67,005		102,591		35,375		67,216
Midstream		121		71		50		120		70		50
R&M		21,651		6,167		15,484		21,116		5,962		15,154
LUKOIL Investment		-		-		-		-		-		-
Chemicals		-		-		-		-		-		-
Emerging Businesses		1,060		297		763		1,056		293		763
Corporate and Other		1,568		814		754		1,561		797		764
	$	128,352		44,296		84,056		126,444		42,497		83,947

Suspended Wells
Our capitalized cost of suspended wells at March 31, 2009, was $717 million, an increase of $57 million from $660 million at year-end 2008. For the category of exploratory well costs capitalized for a period greater than one year as of December 31, 2008, $3 million was charged to dry hole expense during the first three months of 2009.

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Note 8—Debt

In early February 2009, we issued $1.5 billion of 4.75% Notes due 2014, $2.25 billion of 5.75% Notes due 2019, and $2.25 billion of 6.50% Notes due 2039. The proceeds of the notes were primarily used to reduce outstanding commercial paper balances. Under the terms of our $2.5 billion, 364-day revolving credit facility, the receipt of the proceeds from this bond offering terminated this revolving credit facility.

In late March 2009, we used proceeds from the issuance of commercial paper to redeem our $284 million 6.375% Notes upon their maturity.

At March 31, 2009, we had a $7.35 billion revolving credit facility, which expires in September 2012. The facility may be used as direct bank borrowings, as support for the ConocoPhillips $5.6 billion commercial paper program, as support for the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, as support for issuances of letters of credit totaling up to $750 million, or as support for up to $250 million of commercial paper issued by TransCanada Keystone Pipeline LP, a Keystone pipeline joint venture entity. At both March 31, 2009, and December 31, 2008, we had no outstanding borrowings under the credit facility, but $40 million in letters of credit had been issued. Under both ConocoPhillips commercial paper programs, $3,219 million of commercial paper was outstanding at March 31, 2009, compared with $6,933 million at December 31, 2008.

Since we had $3,219 million of commercial paper outstanding, had issued $40 million of letters of credit and had up to a $250 million guarantee on commercial paper issued by Keystone, we had access to $3.8 billion in borrowing capacity under our revolving credit facility at March 31, 2009.

Also at March 31, 2009, we classified $4,169 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 facility.

In early April 2009, we used proceeds from the issuance of commercial paper to redeem $950 million of Floating Rate Notes upon their maturity.

Note 9—Joint Venture Acquisition Obligation

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period, beginning in 2007, to FCCL Oil Sands Partnership. 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 $634 million was short-term and was included in the “Accounts payable—related parties” line on our March 31, 2009, consolidated balance sheet. The principal portion of these payments, which totaled $153 million in the first three months of 2009, are included in the “Other” line in the financing activities section of our consolidated statement of cash flows. 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, 2009, 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. In addition, unless otherwise stated we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.

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Construction Completion Guarantees

• In December 2005, we issued a construction completion guarantee for 30 percent of the $4 billion in loan facilities of Qatargas 3, which will be used to construct an LNG train in Qatar. Of the $4 billion in loan facilities, ConocoPhillips 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 2011. At March 31, 2009, the carrying value of the guarantee to the third-party lenders was $11 million.

Guarantees of Joint Venture Debt

• In June 2006, we issued a guarantee for 24 percent of the $2 billion in credit facilities of Rockies Express Pipeline LLC, operated by Kinder Morgan Energy Partners, L.P. Rockies Express is constructing a natural gas pipeline across a portion of the United States. At March 31, 2009, Rockies Express had $1,913 million outstanding under the credit facilities, with our 24 percent guarantee equaling $459 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 facilities are 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 in August 2009 issued by Rockies Express. The operator anticipates construction completion in late 2009. Refinancing will take place at that time, making the debt nonrecourse to ConocoPhillips. At March 31, 2009, the total carrying value of these guarantees to third-party lenders was $12 million.

• In December 2007, we acquired a 50 percent equity interest in four Keystone pipeline entities (Keystone), to create a joint venture with TransCanada Corporation. Keystone is constructing a crude oil pipeline originating in Alberta, with delivery points in Illinois and Oklahoma. In December 2008, we provided a guarantee for up to $250 million of balances outstanding under a commercial paper program. This program was established by Keystone to provide funding for a portion of Keystone’s construction costs attributable to our ownership interest in the project. Payment under the guarantee would be due in the event Keystone failed to repay principal and interest, when due, to short-term noteholders. The commercial paper program and our guarantee are expected to increase as funding needs increase during construction of the Keystone pipeline. Keystone’s other owner will guarantee a similar, but separate, funding vehicle. Post-construction Keystone financing is anticipated to be nonrecourse to us. At March 31, 2009, $200 million was outstanding under the Keystone commercial paper program guaranteed by us.

• At March 31, 2009, 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

• In connection with certain planning and construction activities of the Keystone pipeline, we agreed to reimburse TransCanada with respect to a portion of guarantees issued by TransCanada for certain of Keystone’s obligations to third parties. Our maximum potential amount of future payments associated with these guarantees is based on our ultimate ownership percentage in Keystone and is estimated to be $62 million, which could become payable if Keystone fails to meet its obligations and the obligations 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 payments would be required. All but $8 million of the guarantees will terminate after construction is completed, currently estimated to occur in 2010.

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	In October 2008, we elected to exercise an option to reduce our equity interest in Keystone from 50 percent to 20.01 percent. The change in equity will occur through a dilution mechanism, which is expected to gradually lower our ownership interest until it reaches 20.01 percent by the third quarter of 2009. At March 31, 2009, our ownership interest was approximately 29 percent.
	In addition to the above guarantee, in order to obtain long-term shipping commitments that would enable a pipeline expansion starting at Hardisty, Alberta, and extending to near Port Arthur, Texas, the Keystone owners executed an agreement in July 2008 to guarantee Keystone’s obligations under its agreement to provide transportation at a specified price for certain shippers to the Gulf Coast. Although our guarantee is for 50 percent of these obligations, TransCanada has agreed to reimburse us for amounts we pay in excess of our ownership percentage in Keystone. Our maximum potential amount of future payments, or cost of volume delivery, under this guarantee, after such reimbursement, is estimated to be $220 million ($550 million before reimbursement) based on a full 20-year term of the shipping commitments, which could become payable if Keystone fails to meet its obligations under the agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, are contingent upon Keystone defaulting on its obligation to construct the pipeline in accordance with the terms of the agreement.
•	In conjunction with our purchase of a 50 percent ownership interest in Australia Pacific LNG (APLNG) from Origin Energy in October 2008, we agreed to participate, if and when requested, in any parent company guarantees that were outstanding at the time we purchased our interest in APLNG. These parent company guarantees cover the obligation of APLNG to deliver gas under several sales agreements with remaining terms of eight to 22 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $930 million ($1,940 million in the event of intentional or reckless breach) based on our 50 percent share of the remaining contracted volumes, which could become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG does not have enough natural gas to meet these sales commitments and if the partners do not make necessary equity contributions into APLNG.
•	We have other guarantees with maximum future potential payment amounts totaling $530 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, a guarantee of minimum charter revenue for two LNG vessels, one small construction completion guarantee, guarantees relating to the startup of a refining joint venture, guarantees of the lease payment obligations of a joint venture, and guarantees of the residual value of leased corporate aircraft. These guarantees generally extend up to 16 years or life of the venture.

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, 2009, was $455 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 recorded carrying amount were $240 million of environmental accruals for known contamination that are included in asset retirement obligations and accrued environmental costs at March 31, 2009. For additional information about environmental liabilities, see Note 11—Contingencies and Commitments.

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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, 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 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 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 segment’s, 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.

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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 future costs will be incurred and these costs can be reasonably estimated. At March 31, 2009, our balance sheet included a total environmental accrual of $960 million, compared with $979 million at December 31, 2008. 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 our cases, our legal organization believes there is a remote likelihood future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements.

Other Contingencies
We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at March 31, 2009, we had performance obligations secured by letters of credit of $1,491 million (of which $40 million was issued under the provisions of our revolving credit facility, and the remainder was issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, services and items of permanent investment incident to the ordinary conduct of business.

Note 12—Financial Instruments and Derivative Contracts

Derivative Instruments
We use financial and commodity-based derivative contracts to manage exposures to fluctuations in foreign currency exchange rates, commodity prices, and interest rates, or to exploit market opportunities. Since we are not currently using SFAS No. 133 hedge accounting, all gains and losses, realized or unrealized, from derivative contracts have been recognized in the consolidated income statement. Gains and losses from derivative contracts held for trading not directly related to our physical business, whether realized or unrealized, have been reported net in other income.

SFAS No. 133 requires purchase and sales contracts for commodities that are readily convertible to cash (e.g., crude oil, natural gas and gasoline) to be recorded on the balance sheet as derivatives unless the contracts are for quantities we expect to use or sell over a reasonable period in the normal course of business (i.e., contracts eligible for the normal purchases and normal sales exception). We record most of our contracts to buy or sell natural gas as derivatives, but we do apply the normal purchases and normal sales exception to certain long-term contracts to sell our natural gas production. We generally apply this normal purchases and normal sales exception to eligible crude oil and refined product commodity purchase and sales contracts; however, we may elect not to apply this exception (e.g., when another derivative instrument will be used to mitigate the risk of the purchase or sale contract but hedge accounting will not be applied, in which case both the purchase or sales contract and the derivative contract mitigating the resulting risk will be recorded on the balance sheet at fair value).

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The fair value hierarchy for our derivative assets and liabilities accounted for at fair value on a recurring basis was:

	Millions of Dollars
	March 31, 2009												December 31, 2008
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets
Commodity derivatives	$	4,659			2,593			109			7,361			4,994			2,874			112			7,980
Foreign exchange derivatives		-			81			-			81			-			97			-			97
Total assets		4,659			2,674			109			7,442			4,994			2,971			112			8,077
Liabilities
Commodity derivatives		(4,973	)		(2,184	)		(13	)		(7,170	)		(5,221	)		(2,497	)		(72	)		(7,790	)
Foreign exchange derivatives		-			(41	)		-			(41	)		-			(93	)		-			(93	)
Total liabilities		(4,973	)		(2,225	)		(13	)		(7,211	)		(5,221	)		(2,590	)		(72	)		(7,883	)
Net assets (liabilities)	$	(314	)		449			96			231			(227	)		381			40			194

The derivative values above are based on analysis of each contract as the fundamental unit of account as required by SFAS No. 157; therefore, derivative assets and liabilities with the same counterparty are not reflected net where the legal right of offset exists. Gains or losses from contracts in one level may be offset by gains or losses on contracts in another level or by changes in values of physical contracts or positions that are not reflected in the table above.

The fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy changed as follows:

	Millions of Dollars
	Three Months Ended
	March 31
	2009			2008
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Beginning balance	$	40			(34	)
Total gains (losses), realized and unrealized
Included in earnings		26			(42	)
Included in other comprehensive income		-			-
Purchases, issuances and settlements		(10	)		24
Transfers in and/or out of Level 3		40			(1	)
Ending balance	$	96			(53	)

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The amounts of Level 3 gains (losses) included in earnings were:

	Millions of Dollars
	Three Months Ended
	March 31
	2009									2008
				Purchased									Purchased
	Other			Crude Oil,						Other			Crude Oil,
	Operating			Natural Gas						Operating			Natural Gas
	Revenues			and Products			Total			Revenues			and Products		Total
Total gains (losses) included in earnings	$	27			(1	)		26			(43	)		1		(42	)
Change in unrealized gains (losses) relating to assets held at March 31	$	36			-			36			1			-		1
Change in unrealized gains (losses) relating to liabilities held at March 31	$	(10	)		-			(10	)		(31	)		-		(31	)

Commodity Derivative Contracts—We operate in the worldwide crude oil, refined product, natural gas, natural gas liquids and electric power markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect our revenues as well as the cost of operating, investing and financing activities. Generally, our policy is to remain exposed to the market prices of commodities. However, we use futures, forwards, swaps and options in various markets to balance physical systems, meet customer needs, manage price exposures on specific transactions, and do a limited, immaterial amount of trading not directly related to our physical business. These activities may move our risk profile away from market average prices.

The fair value of commodity derivative assets and liabilities at March 31, 2009, and the line items where they appear on our consolidated balance sheet were:

	Millions
	of Dollars
Assets
Prepaid expenses and other current assets	$	6,880
Other assets		513
Liabilities
Other accruals		6,768
Other liabilities and deferred credits		434

Hedge accounting has not been used for any items in the table unless specified otherwise.

As required under SFAS No. 161, the amounts shown in the preceding table are presented gross (i.e., without netting assets and liabilities with the same counterparty where the right of offset and intent to net exist); however, derivative assets and liabilities resulting from eligible commodity contracts have been netted on our consolidated balance sheet in accordance with FIN 39, “Offsetting of Amounts Related to Certain Contracts.” In addition, the commodity derivative assets on our consolidated balance sheet appear net of $130 million of obligations to return cash collateral, and the commodity derivative liabilities appear net of $553 million of rights to reclaim cash collateral.

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The gains (losses) from commodity derivatives incurred during the quarter ended March 31, 2009, and the line items where they appear on our consolidated income statement were:

	Millions
	of Dollars
Sales and other operating revenues	$	573
Other income		8
Purchased crude oil, natural gas and products		(512	)

Hedge accounting has not been used for any items in the table unless specified otherwise.

As of March 31, 2009, we had the following net position of outstanding commodity derivative contracts, primarily to manage price exposure on our underlying operations. This exposure may be from other derivative contracts, such as forward sales contracts, or may be from non-derivative positions such as inventory volumes or firm natural gas transport contracts.

	Open Position
	Long / (Short)
Commodity
Crude oil, refined products and natural gas liquids (millions of barrels)		(45	)
Natural gas, power and carbon dioxide emissions (billions of cubic feet)
Flat price		(33	)
Basis		(127	)
Freight forwards (millions of metric tons)		3

Currency Exchange Rate Derivative Contracts—We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to currency rate changes, although we may choose to selectively hedge certain foreign currency exchange rate exposures, such as firm commitments for capital projects or local currency tax payments and dividends.

The fair value of foreign currency derivative assets and liabilities open at March 31, 2009, and the line items where they appear on our consolidated balance sheet were:

	Millions
	of Dollars
Assets
Prepaid expenses and other current assets	$	79
Other assets		2
Liabilities
Other accruals		39
Other liabilities and deferred credits		2

Hedge accounting has not been used for any items in the table unless specified otherwise.

As required under SFAS No. 161, the amounts shown in the preceding table are presented gross; however, derivative assets and liabilities resulting from eligible foreign currency contracts have been netted on our consolidated balance sheet in accordance with FIN 39. No collateral was deposited or held under these contracts.

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The impacts from foreign currency derivatives during the quarter ended March 31, 2009, and the line item where they appear on our consolidated income statement were:

	Millions
	of Dollars
Foreign currency transaction losses (gains)	$	(6	)

Hedge accounting has not been used for any items in the table unless specified otherwise.

As of March 31, 2009, we had the following net position of outstanding foreign currency swap contracts, entered into primarily to hedge price exposure in our international operations.

	In Millions
	Notional*
Foreign Currency Swaps
Sell U.S. dollar, buy euro	USD	761
Sell U.S. dollar, buy British pound	USD	1,382
Sell U.S. dollar, buy Canadian dollar	USD	1,262
Sell U.S. dollar, buy Danish kroner	USD	3
Sell U.S. dollar, buy Norwegian kroner	USD	627
Sell U.S. dollar, buy Swedish krona	USD	63
Sell U.S. dollar, buy Australian dollar	USD	117
Sell British pound, buy euro	GBP	6
Buy British pound, sell Canadian dollar	GBP	6

*Denominated in U.S. dollars (USD) and British pounds (GBP).

Credit Risk
Our financial instruments that are potentially exposed to concentrations of credit risk consist primarily of cash equivalents, over-the-counter derivative contracts and trade receivables. Our cash equivalents are placed in high-quality commercial paper, money market funds and time deposits with major international banks and financial institutions.

The credit risk from our over-the-counter derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction, typically a major bank or financial institution. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures contracts, but futures have a negligible credit risk because they are traded on the New York Mercantile Exchange or the ICE Futures.

Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of credit as collateral.

The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on March 31, 2009, was $517 million, for which we posted $27 million in collateral in the normal course of business. If our credit rating were lowered one level from its “A” rating (per Standard and Poors) on March 31, 2009, we would be required to post no additional collateral to our counterparties. If we were downgraded below investment grade, we would be required to post $490 million of additional collateral, either with cash or letters of credit.

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Note 13—Comprehensive Income

ConocoPhillips’ comprehensive income was as follows:

	Millions of Dollars
	Three Months Ended
	March 31
	2009			2008
Net income	$	856			4,158
After-tax changes in:
Defined benefit pension plans
Reclassification adjustment for amortization of prior service cost		3			4
Reclassification adjustment for amortization of prior net actuarial loss		34			9
Nonsponsored plans		(1	)		2
Foreign currency translation adjustments		(278	)		(435	)
Hedging activities		(1	)		(2	)
Comprehensive income		613			3,736
Less: comprehensive income attributable to noncontrolling interests		(16	)		(19	)
Comprehensive income attributable to ConocoPhillips	$	597			3,717

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

	Millions of Dollars
	March 31 2009			December 31 2008
Defined benefit pension plans	$	(1,398	)		(1,434	)
Foreign currency translation adjustments		(709	)		(431	)
Deferred net hedging loss		(11	)		(10	)
Accumulated other comprehensive loss	$	(2,118	)		(1,875	)

None of the items within accumulated other comprehensive loss relate to noncontrolling interests.

Note 14—Cash Flow Information

	Millions of Dollars
	Three Months Ended
	March 31
	2009		2008
Cash Payments
Interest	$	95		86
Income taxes		1,346		1,649

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Note 15—Employee Benefit Plans

Pension and Postretirement Plans

	Millions of Dollars
	Pension Benefits												Other Benefits
Three Months Ended	March 31												March 31
	2009						2008						2009			2008
	U.S.			Int’l.			U.S.			Int’l.
Components of Net Periodic Benefit Cost
Service cost	$	48			20			47			23			2			3
Interest cost		69			33			62			44			12			12
Expected return on plan assets		(46	)		(29	)		(56	)		(44	)		-			-
Amortization of prior service cost		3			-			2			-			2			3
Recognized net actuarial loss (gain)		47			8			16			3			(4	)		(4	)
Net periodic benefit cost	$	121			32			71			26			12			14

During the first three months of 2009, we contributed $74 million to our domestic benefit plans and $33 million to our international benefit plans.

Severance Accrual
As a result of the current business environment’s impact on our operating and capital plans, a reduction in our overall employee work force is expected in 2009. Various business units and staff groups recorded accruals in the fourth quarter of 2008 for severance and related employee benefits totaling $162 million. The following table summarizes our severance accrual activity:

	Millions of Dollars
	March 31			December 31
	2009			2008
Beginning balance	$	162			-
Accruals		1			162
Benefit payments		(7	)		-
Ending balance	$	156			162

The remaining balance at March 31, 2009, of $156 million is classified as short-term.

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Note 16—Related Party Transactions

Significant transactions with related parties were:

	Millions of Dollars
	Three Months Ended
	March 31
	2009		2008
Operating revenues (a)	$	1,473		3,171
Purchases (b)		2,482		4,398
Operating expenses and selling, general and administrative expenses (c)		85		116
Net interest expense (d)		19		21

(a) We sold natural gas to DCP Midstream, LLC 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 and Merey Sweeny, L.P. (MSLP) for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.

(b) We purchased refined products from WRB. 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 and refined products from MRC. We also paid fees to various pipeline equity companies for transporting finished refined products and natural gas, as well as 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.

20

Note 17—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, predominantly in the United States and Trinidad. The Midstream segment primarily consists of our 50 percent equity investment in DCP Midstream, LLC.
3)	R&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia.
4)	LUKOIL Investment—This segment represents our investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. At March 31, 2009, our ownership interest was 20 percent based on issued shares, and 20.09 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 Chevron Phillips Chemical Company LLC.
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 expense and various other corporate activities. Corporate assets include all cash and cash equivalents. We evaluate performance and allocate resources based on net income attributable to ConocoPhillips. Intersegment sales are at prices that approximate market.

21

Analysis of Results by Operating Segment

	Millions of Dollars
	Three Months Ended
	March 31
	2009			2008
Sales and Other Operating Revenues
E&P
United States	$	6,096			11,547
International		6,651			8,441
Intersegment eliminations—U.S.		(859	)		(2,112	)
Intersegment eliminations—international		(1,388	)		(2,297	)
E&P		10,500			15,579
Midstream
Total sales		922			1,642
Intersegment eliminations		(48	)		(88	)
Midstream		874			1,554
R&M
United States		13,000			26,961
International		6,464			10,926
Intersegment eliminations—U.S.		(117	)		(219	)
Intersegment eliminations—international		(8	)		(7	)
R&M		19,339			37,661
LUKOIL Investment		-			-
Chemicals		3			3
Emerging Businesses
Total sales		154			258
Intersegment eliminations		(137	)		(177	)
Emerging Businesses		17			81
Corporate and Other		8			5
Consolidated sales and other operating revenues	$	30,741			54,883
Net Income (Loss) Attributable to ConocoPhillips
E&P
United States	$	173			1,349
International		527			1,538
Total E&P		700			2,887
Midstream		123			137
R&M
United States		98			435
International		107			85
Total R&M		205			520
LUKOIL Investment		48			710
Chemicals		23			52
Emerging Businesses		-			12
Corporate and Other		(259	)		(179	)
Net income attributable to ConocoPhillips	$	840			4,139

22

	Millions of Dollars
	March 31		December 31
	2009		2008
Total Assets
E&P
United States	$	36,514		36,962
International		58,161		58,912
Total E&P		94,675		95,874
Midstream		1,554		1,455
R&M
United States		24,173		22,554
International		7,989		7,942
Goodwill		3,777		3,778
Total R&M		35,939		34,274
LUKOIL Investment		5,494		5,455
Chemicals		2,212		2,217
Emerging Businesses		937		924
Corporate and Other		2,440		2,666
Consolidated total assets	$	143,251		142,865

Note 18—Income Taxes

Our effective tax rates for the first quarters of 2009 and 2008 were 58 percent and 45 percent, respectively. The change in the effective tax rate for the first quarter of 2009, versus the same period of 2008, was primarily due to a higher proportion of income in higher tax rate jurisdictions in 2009. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.

Note 19—New Accounting Standards

In December 2008, the FASB issued FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” to improve the transparency associated with disclosures about the plan assets of a defined benefit pension or other postretirement plan. This FSP requires the disclosure of each major asset category at fair value using the fair value hierarchy in SFAS No. 157, “Fair Value Measurements.” Also, this FSP requires entities to disclose the net periodic benefit cost recognized for each annual period for which a statement of income is presented. This FSP is effective for annual financial statements beginning with the 2009 fiscal year.

23

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. Certain previously reported amounts appearing on the 2008 income statement have been reclassified to conform to the current year presentation.

24

	Millions of Dollars
	Three Months Ended March 31, 2009
							ConocoPhillips		ConocoPhillips			ConocoPhillips
							Australia		Canada			Canada
				ConocoPhillips			Funding		Funding			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	$	-			17,534			-		-			-			13,207			-			30,741
Equity in earnings of affiliates		929			955			-		-			-			281			(1,750	)		415
Other income (loss)		(2	)		203			-		-			-			(77	)		-			124
Intercompany revenues		1			382			17		18			11			3,504			(3,933	)		-
Total Revenues and Other Income		928			19,074			17		18			11			16,915			(5,683	)		31,280
Costs and Expenses
Purchased crude oil, natural gas and products		-			14,841			-		-			-			8,587			(3,669	)		19,759
Production and operating expenses		2			1,094			-		-			-			1,475			(26	)		2,545
Selling, general and administrative expenses		3			323			-		1			1			157			(10	)		475
Exploration expenses		-			65			-		-			-			160			-			225
Depreciation, depletion and amortization		-			425			-		-			-			1,805			-			2,230
Impairments		-			(5	)		-		-			-			8			-			3
Taxes other than income taxes		-			1,155			-		-			-			2,327			(18	)		3,464
Accretion on discounted liabilities		-			18			-		-			-			86			-			104
Interest and debt expense		130			69			15		19			13			274			(210	)		310
Foreign currency transaction losses (gains)		-			7			-		(38	)		(7	)		169			-			131
Total Costs and Expenses		135			17,992			15		(18	)		7			15,048			(3,933	)		29,246
Income before income taxes		793			1,082			2		36			4			1,867			(1,750	)		2,034
Provision for income taxes		(47	)		153			1		1			(4	)		1,074			-			1,178
Net income		840			929			1		35			8			793			(1,750	)		856
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(16	)		-			(16	)
Net Income Attributable to ConocoPhillips	$	840			929			1		35			8			777			(1,750	)		840
Income Statement	Three Months Ended March 31, 2008
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		-			305			-		-			-			5			-			310
Intercompany revenues		9			717			24		23			14			6,050			(6,837	)		-
Total Revenues and Other Income		4,194			38,886			24		23			14			27,443			(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		-			1,110			-		-			-			1,618			(37	)		2,691
Selling, general and administrative expenses		2			319			-		-			-			225			(20	)		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			221			22		19			13			259			(404	)		207
Foreign currency transaction (gains) losses		-			(4	)		-		(72	)		(73	)		106			-			(43	)
Total Costs and Expenses		79			34,838			22		(53	)		(60	)		20,995			(6,837	)		48,984
Income before income taxes		4,115			4,048			2		76			74			6,448			(7,195	)		7,568
Provision for income taxes		(24	)		437			1		4			8			2,984			-			3,410
Net income		4,139			3,611			1		72			66			3,464			(7,195	)		4,158
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(19	)		-			(19	)
Net Income Attributable to ConocoPhillips	$	4,139			3,611			1		72			66			3,445			(7,195	)		4,139

25

	Millions of Dollars
	March 31, 2009
						ConocoPhillips			ConocoPhillips			ConocoPhillips
						Australia			Canada			Canada
				ConocoPhillips		Funding			Funding			Funding			All Other		Consolidating			Total
Balance Sheet	ConocoPhillips			Company		Company			Company I			Company II			Subsidiaries		Adjustments			Consolidated
Assets
Cash and cash equivalents	$	-			123		-			9			1			669		-			802
Accounts and notes receivable		20			9,645		21			-			-			18,748		(18,115	)		10,319
Inventories		-			3,957		-			-			-			2,623		(100	)		6,480
Prepaid expenses and other current assets		9			1,395		-			16			11			1,171		-			2,602
Total Current Assets		29			15,120		21			25			12			23,211		(18,215	)		20,203
Investments, loans and long-term receivables*		61,829			79,679		1,698			1,168			790			43,571		(155,016	)		33,719
Net properties, plants and equipment		-			19,368		-			-			-			64,686		2			84,056
Goodwill		-			3,777		-			-			-			-		-			3,777
Intangibles		-			781		-			-			-			56		-			837
Other assets		41			319		2			146			188			289		(326	)		659
Total Assets	$	61,899			119,044		1,721			1,339			990			131,813		(173,555	)		143,251
Liabilities and Stockholders’ Equity
Accounts payable	$	-			15,670		-			3			2			15,761		(18,115	)		13,321
Short-term debt		(3	)		17		950			-			-			68		(950	)		82
Accrued income and other taxes		-			359		-			(1	)		(1	)		3,786		-			4,143
Employee benefit obligations		-			497		-			-			-			176		-			673
Other accruals		121			723		22			32			22			1,217		(26	)		2,111
Total Current Liabilities		118			17,266		972			34			23			21,008		(19,091	)		20,330
Long-term debt		12,589			5,352		749			1,250			848			7,559		950			29,297
Asset retirement obligations and accrued environmental costs		-			1,101		-			-			-			6,076		-			7,177
Joint venture acquisition obligation		-			-		-			-			-			5,507		-			5,507
Deferred income taxes		(4	)		3,015		-			10			29			14,944		(11	)		17,983
Employee benefit obligations		-			3,341		-			-			-			744		-			4,085
Other liabilities and deferred credits*		767			22,979		-			-			-			16,835		(37,902	)		2,679
Total Liabilities		13,470			53,054		1,721			1,294			900			72,673		(56,054	)		87,058
Retained earnings		24,274			5,721		(2	)		160			175			7,265		(6,807	)		30,786
Other common stockholders’ equity		24,155			60,269		2			(115	)		(85	)		50,777		(110,694	)		24,309
Noncontrolling interests		-			-		-			-			-			1,098		-			1,098
Total Liabilities and Stockholders’ Equity	$	61,899			119,044		1,721			1,339			990			131,813		(173,555	)		143,251
*Includes intercompany loans.
Balance Sheet	December 31, 2008
Assets
Cash and cash equivalents	$	-			8		-			10			1			750		(14	)		755
Accounts and notes receivable		13			10,541		15			-			-			21,314		(19,888	)		11,995
Inventories		-			2,909		-			-			-			2,287		(101	)		5,095
Prepaid expenses and other current assets		10			1,170		-			14			10			1,794		-			2,998
Total Current Assets		23			14,628		15			24			11			26,145		(20,003	)		20,843
Investments, loans and long-term receivables*		61,144			83,645		1,699			1,183			802			44,629		(160,203	)		32,899
Net properties, plants and equipment		-			19,017		-			-			-			64,928		2			83,947
Goodwill		-			3,778		-			-			-			-		-			3,778
Intangibles		-			784		-			-			-			62		-			846
Other assets		13			243		2			109			183			286		(284	)		552
Total Assets	$	61,180			122,095		1,716			1,316			996			136,050		(180,488	)		142,865
Liabilities and Stockholders’ Equity
Accounts payable	$	-			17,566		-			2			1			16,309		(19,888	)		13,990
Short-term debt		-			301		950			-			-			68		(949	)		370
Accrued income and other taxes		-			233		-			(1	)		(1	)		4,042		-			4,273
Employee benefit obligations		-			702		-			-			-			237		-			939
Other accruals		25			883		18			15			10			1,280		(23	)		2,208
Total Current Liabilities		25			19,685		968			16			10			21,936		(20,860	)		21,780
Long-term debt		7,703			5,364		749			1,250			848			10,221		950			27,085
Asset retirement obligations and accrued environmental costs		-			1,101		-			-			-			6,062		-			7,163
Joint venture acquisition obligation		-			-		-			-			-			5,669		-			5,669
Deferred income taxes		(4	)		2,882		-			9			34			15,258		(12	)		18,167
Employee benefit obligations		-			3,367		-			-			-			760		-			4,127
Other liabilities and deferred credits*		4,954			24,609		-			-			-			16,976		(43,930	)		2,609
Total Liabilities		12,678			57,008		1,717			1,275			892			76,882		(63,852	)		86,600
Retained earnings		24,130			4,792		(3	)		125			167			7,234		(5,803	)		30,642
Other common stockholders’ equity		24,372			60,295		2			(84	)		(63	)		50,834		(110,833	)		24,523
Noncontrolling interests		-			-		-			-			-			1,100		-			1,100
Total Liabilities and Stockholders’ Equity	$	61,180			122,095		1,716			1,316			996			136,050		(180,488	)		142,865

*Includes intercompany loans.

26

	Millions of Dollars
	Three Months Ended March 31, 2009
							ConocoPhillips			ConocoPhillips			ConocoPhillips
							Australia			Canada			Canada
				ConocoPhillips			Funding			Funding			Funding			All Other			Consolidating			Total
Statement of Cash Flows	ConocoPhillips			Company			Company			Company I			Company II			Subsidiaries			Adjustments			Consolidated
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	(4,130	)		2,661			-			(1	)		-			4,087			(732	)		1,885
Cash Flows From Investing Activities
Capital expenditures and investments		-			(834	)		-			-			-			(2,111	)		39			(2,906	)
Proceeds from asset dispositions		-			4			-			-			-			82			-			86
Long-term advances/loans—related parties		-			7			-			-			-			(95	)		-			(88	)
Collection of advances/loans—related parties		-			71			-			-			-			1,454			(1,514	)		11
Other		-			(44	)		-			-			-			15			-			(29	)
Net Cash Used in Investing Activities		-			(796	)		-			-			-			(655	)		(1,475	)		(2,926	)
Cash Flows From Financing Activities
Issuance of debt		5,946			-			-			-			-			87			-			6,033
Repayment of debt		(1,067	)		(1,750	)		-			-			-			(2,799	)		1,514			(4,102	)
Issuance of company common stock		(21	)		-			-			-			-			-			-			(21	)
Dividends paid on common stock		(696	)		-			-			-			-			(746	)		746			(696	)
Other		(32	)		-			-			-			-			(132	)		(39	)		(203	)
Net Cash Provided by (Used in) Financing Activities		4,130			(1,750	)		-			-			-			(3,590	)		2,221			1,011
Effect of Exchange Rate Changes on Cash and Cash Equivalents		-			-			-			-			-			77			-			77
Net Change in Cash and Cash Equivalents		-			115			-			(1	)		-			(81	)		14			47
Cash and cash equivalents at beginning of period		-			8			-			10			1			750			(14	)		755
Cash and Cash Equivalents at End of Period	$	-			123			-			9			1			669			-			802
Statement of Cash Flows	Three Months Ended March 31, 2008
Cash Flows From Operating Activities
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 period		-			195			-			7			1			1,626			(373	)		1,456
Cash and Cash Equivalents at End of Period	$	-			131			-			6			-			1,432			(146	)		1,423

27

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 attributable to ConocoPhillips of $700 million in the first quarter of 2009, which accounted for 83 percent of total net income attributable to ConocoPhillips in the quarter. This compares with E&P net income attributable to ConocoPhillips of $2,887 million in the first quarter of 2008.

Net income attributable to ConocoPhillips in the first quarter of 2009 was impacted by a decrease in crude oil prices. Industry crude oil prices for West Texas Intermediate averaged $42.97 per barrel in the first quarter of 2009, or $15.52 lower than the fourth quarter of 2008, and $54.97 lower than the same period a year earlier. Crude oil prices were influenced by falling worldwide oil demand due to the economic crisis. With the decreased demand, U.S. crude oil inventories reached their highest levels since 1993.

Industry natural gas prices for Henry Hub decreased during the first quarter of 2009 to $4.91 per million British thermal units, down $2.04 compared with the fourth quarter of 2008, and down $3.12 compared with the first quarter of 2008. Domestic natural gas prices trended lower during the first quarter of 2009 due to increasing production and decreasing demand in the industrial and power generation sectors. Colder than normal weather and coal-to-natural gas substitution in the power generation industry helped moderate this decline in demand. As a result of the changes in supply and demand, natural gas storage levels rose to levels higher than the five-year average, and were higher than in the first quarter of 2008.

Our Refining and Marketing (R&M) segment had net income attributable to ConocoPhillips of $205 million in the first quarter of 2009, compared with $520 million in the first quarter of 2008. First-quarter 2009 results were lower than those in the first quarter of 2008 primarily due to lower refining volumes related to increased turnaround activity in the United States, as well as the absence of a first-quarter 2008 benefit from asset rationalization efforts.

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RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three-month period ended March 31, 2009, is based on a comparison with the corresponding period of 2008.

Consolidated Results

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

	Millions of Dollars
	Three Months Ended
	March 31
	2009			2008
Exploration and Production (E&P)	$	700			2,887
Midstream		123			137
Refining and Marketing (R&M)		205			520
LUKOIL Investment		48			710
Chemicals		23			52
Emerging Businesses		-			12
Corporate and Other		(259	)		(179	)
Net income attributable to ConocoPhillips	$	840			4,139

Net income attributable to ConocoPhillips was $840 million in the first quarter of 2009, compared with $4,139 million in the first quarter of 2008. The decrease was primarily the result of:

• Substantially lower prices for crude oil, natural gas and natural gas liquids in our E&P segment.

• Significantly reduced earnings from LUKOIL primarily due to lower estimated prices for refined products and crude oil.

• Lower results from our R&M segment, reflecting lower domestic refining volumes due to increased turnaround activity, and the absence of a benefit from first-quarter 2008 asset rationalization efforts.

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

Income Statement Analysis

Sales and other operating revenues decreased 44 percent in the first quarter of 2009, whilepurchased crude oil, natural gas and products decreased 48 percent in the same period. Both decreases were mainly the result of significantly lower petroleum product prices, and lower prices for crude oil, natural gas and natural gas liquids.

Equity in earnings of affiliates decreased 69 percent in the first quarter of 2009, reflecting significantly reduced earnings from LUKOIL in addition to lower results from Merey Sweeney, L.P. (MSLP) and the FCCL Oil Sands Partnership.

Other income decreased 60 percent during the first three months of 2009. The decrease was primarily due to the absence of first-quarter 2008 gains related to asset rationalization efforts and a reduction in interest income.

Exploration expenses decreased 27 percent from $309 million to $225 million, predominantly due to decreases in geological and geophysical expenses, leasehold impairments, and dry hole costs.

Taxes other than income taxes decreased 33 percent during the first quarter of 2009, primarily due to reduced excise taxes on petroleum product sales and lower production taxes as a result of lower crude oil prices.

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Interest and debt expense increased 50 percent in the first three months of 2009 as a result of a higher average debt level and lower amounts of interest being capitalized.

Segment Results

E&P

	Three Months Ended
	March 31
	2009			2008
	Millions of Dollars
Net Income Attributable to ConocoPhillips
Alaska	$	244			603
Lower 48		(71	)		746
United States		173			1,349
International		527			1,538
	$	700			2,887
	Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)
United States	$	40.60			94.02
International		43.70			95.32
Total consolidated		42.36			94.71
Equity affiliates*		33.61			62.78
Worldwide E&P		41.56			92.88
Natural gas (per thousand cubic feet)
United States		3.82			7.63
International		5.87			8.32
Total consolidated		4.98			8.03
Equity affiliates*		2.10			-
Worldwide E&P		4.93			8.03
Natural gas liquids (per barrel)
United States		24.52			58.33
International		31.64			62.20
Total consolidated		27.53			60.14
Worldwide E&P		27.53			60.14
	Millions of Dollars
Worldwide Exploration Expenses
General and administrative; geological and geophysical; and lease rentals	$	102			155
Leasehold impairment		43			60
Dry holes		80			94
	$	225			309

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

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	Three Months Ended
	March 31
	2009		2008
	Thousands of Barrels Daily
Operating Statistics
Crude oil produced
Alaska		254		254
Lower 48		92		97
United States		346		351
Europe		240		201
Asia Pacific		123		92
Canada		24		23
Middle East and Africa		76		81
Other areas		8		10
Total consolidated		817		758
Equity affiliates*
Canada		35		29
Russia and Caspian		49		16
		901		803
Natural gas liquids produced
Alaska		21		19
Lower 48		71		69
United States		92		88
Europe		19		23
Asia Pacific		17		15
Canada		23		26
Middle East and Africa		2		2
		153		154
	Millions of Cubic Feet Daily
Natural gas produced**
Alaska		92		100
Lower 48		2,027		1,963
United States		2,119		2,063
Europe		1,001		1,025
Asia Pacific		713		586
Canada		1,066		1,101
Middle East and Africa		112		105
Other areas		-		20
Total consolidated		5,011		4,900
Equity affiliates*
Asia Pacific		76		-
		5,087		4,900
	Thousands of Barrels Daily
Mining operations
Syncrude produced		23		20

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

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The E&P segment explores for, produces, transports and markets crude oil, natural gas and natural gas liquids on a worldwide basis. It also mines deposits of oil sands in Canada to extract bitumen and upgrade it into a synthetic crude oil. At March 31, 2009, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Ecuador, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria, and Russia.

Net income attributable to ConocoPhillips from the E&P segment decreased 76 percent in the first quarter of 2009, primarily due to substantially lower crude oil, natural gas and natural gas liquids prices. This decrease was partially offset by higher volumes (mainly international crude oil) and lower Alaska and Lower 48 production taxes. 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 attributable to ConocoPhillips from our U.S. E&P operations decreased 87 percent in the first three months of 2009 due to significantly lower crude oil, natural gas and natural gas liquids prices, partially offset by lower production taxes.

U.S. E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 791,000 BOE per day in the first quarter of 2009; this compares with 783,000 averaged in the first quarter of 2008. The increase is primarily due to less planned and unplanned downtime, partially offset by field decline.

International E&P
Net income attributable to ConocoPhillips from our international E&P operations decreased 66 percent in the first quarter of 2009, primarily as a result of significantly lower crude oil, natural gas and natural gas liquids prices, partially offset by higher crude oil volumes.

International E&P production averaged 1,111,000 BOE per day in the first quarter of 2009, an increase of 12 percent from 991,000 in the first quarter of 2008. The increase was predominantly due to production from new developments in the United Kingdom, Russia, Norway, Vietnam, China and Canada, as well as production sharing contract impacts. Field decline partially offset these production increases. Our Syncrude mining operations produced 23,000 barrels per day in the first quarter of 2009, an increase from 20,000 barrels per day in the first quarter of 2008, due to less unplanned downtime.

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Midstream

	Three Months Ended
	March 31
	2009		2008
	Millions of Dollars
Net Income Attributable to ConocoPhillips*	$	123		137
*Includes DCP Midstream-related earnings:	$	90		118
	Dollars Per Barrel
Average Sales Prices
U.S. natural gas liquids*
Consolidated	$	26.04		60.09
Equity affiliates		23.86		56.48

*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*		172	198
Natural gas liquids fractionated**		160	154

  *Includes our share of equity affiliates, except LUKOIL, which is reported 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 attributable to ConocoPhillips from the Midstream segment decreased 10 percent in the first quarter of 2009. The decrease was primarily due to lower prices and volumes experienced by equity affiliates DCP Midstream and Phoenix Park Gas Processors Limited. In addition, DCP Midstream, as of December 31, 2008, had deferred gains on the sale of subordinated common equity of a subsidiary totaling $270 million. Upon conversion of the subordinated units in the subsidiary to common units during the first quarter of 2009, we recognized our share of this deferred gain—$88 million after-tax—as equity earnings. This one-time benefit mostly offset the impact of lower prices and volumes.

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R&M

	Three Months Ended
	March 31
	2009			2008
	Millions of Dollars
Net Income Attributable to ConocoPhillips
United States	$	98			435
International		107			85
	$	205			520
	Dollars Per Gallon
U.S. Average Sales Prices*
Gasoline
Wholesale	$	1.39			2.54
Retail		1.38			2.67
Distillates—wholesale		1.40			2.89
*Excludes excise taxes.
	Thousands of Barrels Daily
Operating Statistics
Refining operations*
United States
Crude oil capacity		1,986			2,008
Crude oil runs		1,589			1,806
Capacity utilization (percent)		80	%		90
Refinery production		1,716			1,991
International
Crude oil capacity		671			670
Crude oil runs		567			578
Capacity utilization (percent)		85	%		86
Refinery production		576			574
Worldwide
Crude oil capacity		2,657			2,678
Crude oil runs		2,156			2,384
Capacity utilization (percent)		81	%		89
Refinery production		2,292			2,565
*Includes our share of equity affiliates, except LUKOIL, which is reported in the LUKOIL Investment segment.
Petroleum products sales volumes
United States
Gasoline		1,037			1,070
Distillates		749			869
Other products		328			384
		2,114			2,323
International		609			616
		2,723			2,939

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

Net income attributable to ConocoPhillips from the R&M segment decreased 61 percent during the first quarter of 2009, primarily due to lower domestic refining volumes and a reduced net benefit from asset rationalization efforts. Other factors influencing R&M results included reduced international operating costs, higher marketing margins mostly offset by lower refining margins, and negative foreign currency impacts.

U.S. R&M
In the first quarter of 2009, our U.S. R&M operations reported a decrease in net income attributable to ConocoPhillips of 77 percent. The decrease was primarily the result of lower refining volumes related to increased turnaround activity in 2009, as well as the absence of first-quarter 2008 gains on asset sales.

Our U.S. refining capacity utilization rate was 80 percent in the first quarter of 2009, compared with 90 percent in the first quarter of 2008. The current year rate was mainly impacted by turnaround activity during the first quarter of 2009.

International R&M
Net income attributable to ConocoPhillips from international R&M operations increased 26 percent in the first quarter of 2009. The increase was due to lower operating costs and higher marketing margins, somewhat offset by lower refining margins and negative foreign currency impacts.

Our international refining capacity utilization rate of 85 percent in the first quarter of 2009 remained mostly flat compared with our rate of 86 percent in the first three months of 2008. Both periods were impacted by reduced crude throughput at our Wilhelmshaven, Germany, refinery due to economic conditions.

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LUKOIL Investment

	Millions of Dollars
	Three Months Ended
	March 31
	2009		2008
Net Income Attributable to ConocoPhillips	$	48		710
Operating Statistics*
Crude oil production (thousands of barrels daily)		386		392
Natural gas production (millions of cubic feet daily)		316		404
Refinery crude oil processed (thousands of barrels daily)		203		222
*Represents our net share of our estimate of LUKOIL’s production and processing.

This segment represents our investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia, which we account for under the equity method. As of March 31, 2009, our ownership interest in LUKOIL was 20 percent based on authorized and issued shares. Our ownership interest based on estimated shares outstanding, used for equity method accounting, was 20.09 percent at that date.

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 information, 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 estimated 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 book value of our investment, and also includes the costs associated with our employees seconded to LUKOIL.

Net income attributable to ConocoPhillips from the LUKOIL Investment segment decreased 93 percent in the first three months of 2009. The segment’s results were impacted by substantially lower refined product and crude oil prices, higher operating costs and lower volumes. These items were somewhat offset by lower extraction tax and export tariff rates, as well as by a benefit from basis difference amortization in 2009, versus a negative amortization impact in 2008.

Chemicals

	Millions of Dollars
	Three Months Ended
	March 31
	2009		2008
Net Income Attributable to ConocoPhillips	$	23		52

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 attributable to ConocoPhillips from the Chemicals segment decreased 56 percent in the first quarter of 2009, reflecting lower margins on a variety of products. These margin decreases were partially offset by lower utility and turnaround expenses.

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Emerging Businesses

	Millions of Dollars
	Three Months Ended
	March 31
	2009			2008
Net Income (Loss) Attributable to ConocoPhillips
Power	$	24			27
Other		(24	)		(15	)
	$	-			12

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 innovation of new technologies, such as those related to conventional and nonconventional hydrocarbon recovery (including heavy oil), refining, alternative energy, biofuels, and the environment.

The Emerging Businesses segment broke even in the first quarter of 2009, compared with $12 million of net income attributable to ConocoPhillips in the first quarter of 2008. The decline was mainly due to lower domestic power generation results.

Corporate and Other

	Millions of Dollars
	Three Months Ended
	March 31
	2009			2008
Net Loss Attributable to ConocoPhillips
Net interest	$	(190	)		(108	)
Corporate general and administrative expenses		(41	)		(44	)
Other		(28	)		(27	)
	$	(259	)		(179	)

Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased 76 percent in the first quarter of 2009, primarily due to higher average debt levels, a net decrease in interest income, and lower amounts of interest being capitalized. Corporate general and administrative expenses remained mostly flat over the two periods. The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, and other costs not directly associated with an operating segment.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

	Millions of Dollars
	March 31			December 31
	2009			2008
Short-term debt	$	82			370
Total debt*	$	29,379			27,455
Total equity	$	56,193			56,265
Percent of total debt to capital**		34	%		33
Percent of floating-rate debt to total debt		21	%		37

  *Total debt includes short-term and long-term debt, as shown on our consolidated balance sheet.
**Capital includes total debt and total 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 2009, we issued $6 billion of long-term notes. During the quarter, available cash was used to support our ongoing capital expenditures and investments program, repay commercial paper and other debt, provide loan financing to certain equity affiliates, pay dividends, and meet the funding requirements to FCCL Oil Sands Partnership. Total dividends paid on our common stock during the first quarter were $696 million. During the first quarter of 2009, cash and cash equivalents increased $47 million to $802 million.

In addition to cash flows from operating activities and proceeds from asset sales, we rely on our commercial paper and credit facility program, and our shelf registration statements to support our short- and long-term liquidity requirements. The credit markets, including the commercial paper markets in the United States, have recently experienced adverse conditions. Although we have not been materially impacted by these conditions, continuing volatility in the credit markets may increase costs associated with issuing commercial paper or other debt instruments due to increased spreads over relevant interest rate benchmarks. Such volatility may also affect our ability, the ability of our joint ventures and equity affiliates, and the ability of third parties with whom we seek to do business, to access those credit markets. Notwithstanding these adverse market conditions, we believe current cash and short-term investment balances and cash generated by operations, together with access to external sources of funds as described below in the “Significant Sources of Capital” section, will be sufficient to meet our funding requirements in the near- and long-term, including our capital spending program, dividend payments, required debt payments and the funding requirements to FCCL.

Significant Sources of Capital

Operating Activities
During the first quarter of 2009, cash of $1,885 million was provided by operating activities, a 71 percent decrease from cash from operations of $6,587 million in the corresponding period of 2008. The decline was primarily due to significantly lower commodity prices.

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 2009, crude oil and natural gas prices were significantly lower than in the same period of 2008. These prices and margins are driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.

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

Asset Sales
Proceeds from asset sales during the first quarter of 2009 were $86 million, compared with $370 million in the same period of 2008. Proceeds for both periods mainly reflect our ongoing efforts related to the disposition of assets that no longer fit our strategic plans or those that could bring more value by being monetized in the near term. In January of 2009, we closed on the sale of a large part of our U.S. retail marketing assets, which included seller financing in the form of a $370 million five-year note and letters of credit totaling $54 million.

Commercial Paper and Credit Facilities
At March 31, 2009, we had a $7.35 billion revolving credit facility, which expires in September 2012. The facility may be used as direct bank borrowings, as support for the ConocoPhillips $5.6 billion commercial paper program, as support for the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, as support for issuances of letters of credit totaling up to $750 million, or as support for up to $250 million of commercial paper issued by TransCanada Keystone Pipeline LP, a Keystone pipeline joint venture entity. At both March 31, 2009, and December 31, 2008, we had no outstanding borrowings under the credit facility, but $40 million in letters of credit had been issued. Under both ConocoPhillips commercial paper programs, $3,219 million of commercial paper was outstanding at March 31, 2009, compared with $6,933 million at December 31, 2008.

At March 31, 2009, our primary funding source for short-term working capital needs was the ConocoPhillips $5.6 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 $3,219 million of commercial paper outstanding, had issued $40 million of letters of credit and had up to a $250 million guarantee on commercial paper issued by Keystone, we had access to $3.8 billion in borrowing capacity under our revolving credit facility at March 31, 2009.

Shelf Registrations
We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities. Under this shelf registration, in early February 2009, we issued $1.5 billion of 4.75% Notes due 2014, $2.25 billion of 5.75% Notes due 2019, and $2.25 billion of 6.50% Notes due 2039. The proceeds of the notes were primarily used to reduce outstanding commercial paper balances.

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

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Noncontrolling Interests
At March 31, 2009, we had outstanding $1,098 million of equity in less than wholly owned consolidated subsidiaries held by noncontrolling interest owners, including a noncontrolling interest of $503 million in Ashford Energy Capital S.A. The remaining noncontrolling interest amounts are primarily related to operating joint ventures we control. The largest of these, amounting to $581 million, was related to Darwin liquefied natural gas (LNG) operations, located in Australia’s Northern Territory.

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, 2009, 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. Upon completion certification, currently expected in 2011, all project loan facilities, including the ConocoPhillips loan facilities, will become nonrecourse to the project participants. At March 31, 2009, Qatargas 3 had $3.3 billion outstanding under all the loan facilities, of which ConocoPhillips provided $923 million, and an additional $79 million of accrued interest.

• Rockies Express Pipeline:In June 2006, we issued a guarantee for 24 percent of $2 billion in credit facilities issued to Rockies Express Pipeline LLC, operated by Kinder Morgan Energy Partners, L.P. Rockies Express is constructing 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 facilities are fully utilized and Rockies Express fails to meet its obligations under the credit agreement. At March 31, 2009, Rockies Express had $1,913 million outstanding under the credit facilities, with our 24 percent guarantee equaling $459 million. In addition, we have a 24 percent guarantee on $600 million of Floating Rate Notes due in August 2009. The operator anticipates construction completion in late 2009. Refinancing will take place at that time, making the debt nonrecourse to ConocoPhillips. Construction cost estimates have increased significantly from original projections, and additional increases or other changes related to the investment may impact whether an other-than-temporary impairment of our equity investment is required under APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”

• Keystone Oil Pipeline:We own a 50 percent equity interest in four Keystone pipeline entities (Keystone), to create a joint venture with TransCanada Corporation. Keystone is constructing a crude oil pipeline originating in Alberta, with delivery points in Illinois and Oklahoma. In connection with certain planning and construction activities, we agreed to reimburse TransCanada with respect to a portion of guarantees issued by TransCanada for certain of Keystone’s obligations to third parties. Our maximum potential amount of future payments associated with these guarantees is based on our ultimate ownership percentage in Keystone and is estimated to be $62 million, which could become payable if Keystone fails to meet its obligations and the obligations 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 payments would be required. All but $8 million of the guarantees will terminate after construction is completed, currently estimated to occur in 2010.

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In October 2008, we elected to exercise an option to reduce our equity interest in Keystone from 50 percent to 20.01 percent. The change in equity will occur through a dilution mechanism, which is expected to gradually lower our ownership interest until it reaches 20.01 percent by the third quarter of 2009. At March 31, 2009, our ownership interest was approximately 29 percent.

In addition to the above guarantees, in order to obtain long-term shipping commitments that would enable a pipeline expansion starting at Hardisty, Alberta, and extending to near Port Arthur, Texas, the Keystone owners executed an agreement in July 2008 to guarantee Keystone’s obligations under its agreement to provide transportation at a specified price for certain shippers to the Gulf Coast. Although our guarantee is for 50 percent of these obligations, TransCanada has agreed to reimburse us for amounts we pay in excess of our ownership percentage in Keystone. Our maximum potential amount of future payments, or cost of volume delivery, under this guarantee, after such reimbursement, is estimated to be $220 million ($550 million before reimbursement) based on a full 20-year term of the shipping commitments, which could become payable if Keystone fails to meet its obligations under the agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, are contingent upon Keystone defaulting on its obligation to construct the pipeline in accordance with the terms of the agreement.

In December 2008, we provided a guarantee of up to $250 million of balances outstanding under a commercial paper program. This program was established by Keystone to provide funding for a portion of Keystone’s construction costs attributable to our ownership interest in the project. Payment under the guarantee would be due in the event Keystone failed to repay principal and interest, when due, to short-term noteholders. The commercial paper program and our guarantee are expected to increase as funding needs increase during construction of the Keystone pipeline. Keystone’s other owner will guarantee a similar, but separate, funding vehicle. Post-construction Keystone financing is anticipated to be nonrecourse to us. At March 31, 2009, $200 million was outstanding under the Keystone commercial paper program guaranteed by us.

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.

In late March 2009, we used proceeds from the issuance of commercial paper to redeem our $284 million 6.375% Notes upon their maturity. Our debt balance at March 31, 2009, was $29.4 billion, an increase of $1.9 billion from the balance at December 31, 2008.

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period, beginning in 2007, to FCCL. 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 $634 million was short-term and was included in the “Accounts payable—related parties” line on our March 31, 2009, consolidated balance sheet. The principal portion of these payments, which totaled $153 million in the first three months of 2009, are included in the “Other” line in the financing activities section of our consolidated statement of cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

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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, 2009, we had provided $923 million in loan financing, and an additional $79 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. to participate in a proposed LNG receiving terminal in Quintana, Texas. We entered into a credit agreement with Freeport to provide loan financing for the construction of the facility. The terminal became operational late in the second quarter of 2008, and in August 2008, when the loan was converted from a construction loan to a term loan, it consisted of $650 million in loan financing and $124 million of accrued interest. Freeport began making repayments in September 2008, and the loan balance outstanding at March 31, 2009, was $747 million.

In 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. Terminal construction was completed in June 2008, and the final loan amount was $249 million at March 2009 exchange rates, excluding accrued interest. Although repayments are not required to start until May 2010, beginning in the second half of 2008 and through March 31, 2009, Varandey used available cash to pay $23 million of interest. The outstanding accrued interest at March 31, 2009, was $31 million at current exchange rates.

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

In February 2009, we announced a quarterly dividend of 47 cents per share. The dividend was paid March 2, 2009, to stockholders of record at the close of business February 23, 2009.

In early April 2009, we used proceeds from the issuance of commercial paper to redeem $950 million of Floating Rate Notes upon their maturity.

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Capital Spending

Capital Expenditures and Investments

	Millions of Dollars
	Three Months Ended
	March 31
	2009		2008
E&P
United States—Alaska	$	254		191
United States—Lower 48		751		888
International		1,371		1,739
		2,376		2,818
Midstream		1		-
R&M
United States		408		295
International		88		68
		496		363
LUKOIL Investment		-		-
Chemicals		-		-
Emerging Businesses		17		61
Corporate and Other		16		80
	$	2,906		3,322
United States	$	1,430		1,454
International		1,476		1,868
	$	2,906		3,322

E&P
Capital spending for E&P during the first three months of 2009 totaled $2.4 billion. The expenditures supported key exploration and development projects including:

• Alaska activities related to development drilling in the Greater Kuparuk Area; the Greater Prudhoe Bay Area; the Western North Slope, including satellite field prospects; the Cook Inlet Area; cost estimating and open season planning for Denali—The Alaska Gas Pipeline; and exploration activities.

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

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

• Oil sands projects, primarily those associated with FCCL, and ongoing natural gas projects in Canada.

• In the North Sea, the Greater Ekofisk Area, J-Block fields and various southern North Sea assets.

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

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

• Advancement of coalbed methane projects in Australia associated with the Australia Pacific LNG joint venture.

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

• The Gumusut field offshore Malaysia.

• The North Belut field in Block B, as well as other projects offshore Block B and onshore South Sumatra in Indonesia.

• Fields offshore Vietnam.

• Onshore developments in Nigeria.

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R&M
Capital spending for R&M during the first three months of 2009 totaled $496 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 expand conversion capability and increase clean product yield.

Major project activities in progress include:

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

• Upgrade of the Wilhelmshaven refinery.

• Investment in the Keystone pipeline.

• 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, Financial Accounting Standards Board (FASB) Interpretation No. 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 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 63 through 65 of our 2008 Annual Report on Form 10-K.

We, from time to time, receive requests for information or notices of potential liability from the Environmental Protection Agency and state environmental agencies alleging that we are a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2008, we reported we had been notified of potential liability under CERCLA and comparable state laws at 65 sites around the United States. At March 31, 2009, we had resolved and closed one of these sites, leaving 64 unresolved sites where we have been notified of potential liability.

At March 31, 2009, our balance sheet included a total environmental accrual of $960 million, compared with $979 million at December 31, 2008. We expect to incur a substantial amount 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 current environmental laws and regulations.

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Climate Change
There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while they are likely to be increasingly widespread and stringent, at this stage it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation. Compliance with changes in laws, regulations and obligations that create a GHG emissions trading scheme or GHG reduction policies generally could significantly increase costs or reduce demand for fossil energy derived products. For examples of legislation or precursors for possible regulation that does or could affect our operations, see the “Climate Change” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 65 through 66 of our 2008 Annual Report on Form 10-K.

NEW ACCOUNTING STANDARDS

In December 2008, the FASB issued FASB Staff Position (FSP) FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” to improve the transparency associated with disclosures about the plan assets of a defined benefit pension or other postretirement plan. This FSP requires the disclosure of each major asset category at fair value using the fair value hierarchy in Statement of Financial Accounting Standards No. 157, “Fair Value Measurements.” Also, this FSP requires entities to disclose the net periodic benefit cost recognized for each annual period for which a statement of income is presented. This FSP is effective for annual financial statements beginning with the 2009 fiscal year.

OUTLOOK

On April 16, 2009, the Federal Energy Regulatory Commission (FERC) issued an order accepting tariff rates for interstate shipments in the Trans Alaska Pipeline System (TAPS) for 2007 and, on a preliminary basis, for 2008. FERC also ordered TAPS carriers to pay refunds to interstate shippers for those years. We are evaluating the decision’s effects on existing accruals recorded with respect to this matter.

On April 17, 2009, the United States Court of Appeals for the District of Columbia Circuit issued a decision in a lawsuit brought by an environmental group against the United States Department of the Interior (DOI) challenging the DOI’s approval of offshore oil and gas leasing under the Outer Continental Shelf Lands Act for the period 2007 through 2012. The Court intends to vacate and remand the five-year leasing program to DOI for reconsideration. DOI may request the Court’s reconsideration, may appeal the Court’s decision, or may accept the decision as issued. We are evaluating what, if any, impact this proceeding may have on leases we acquired under the leasing program.

In April 2008, we initiated arbitration before the World Bank’s International Centre for Settlement of Disputes (ICSID) against The Republic of Ecuador and PetroEcuador (collectively, Respondents) as a result of the government’s confiscatory fiscal measures enacted through the Windfall Profits Tax Law, implemented in 2006 and 2007, and the government-mandated renegotiation of our production sharing contracts into service agreements with inferior fiscal and legal terms. In February 2009, PetroEcuador issued notices to seize oil production from Blocks 7 and 21 as part of Ecuador’s efforts to collect prior allegedly unpaid taxes owed under the disputed Windfall Profits Tax Law. In March, the ICSID Tribunal granted a temporary restraining order that commanded Respondents to refrain from any conduct that aggravates the dispute between the parties or alters the status quo. However, Respondents ignored the order, confiscated approximately 470,000 net barrels of crude oil, and announced their intent to sell it through a public auction. On April 17, 2009, the Tribunal heard our motion for provisional measures, and we are awaiting the ICSID Tribunal’s decision as to whether Respondents must refrain from confiscating future production until a final decision has been rendered in the pending arbitration. While we continue funding operations, future confiscation of our crude oil and the resulting negative cash flow could make it difficult to continue operations.

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In E&P, we expect our second-quarter 2009 production to be lower than the level in the first quarter of 2009 primarily due to scheduled maintenance and seasonality.

In R&M, we expect our crude oil capacity utilization in the second quarter of 2009 to be in the upper-80-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 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 as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties 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 exploration and production, 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.

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• 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.

• Limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets.

• 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 Item 1A—Risk Factors in our 2008 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, 2009, does not differ materially from that discussed under Item 7A in our 2008 Annual Report on Form 10-K.

Item 4. CONTROLS AND PROCEDURES

As of March 31, 2009, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Senior 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 and Chief Executive Officer and our Senior Vice President, Finance, and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of March 31, 2009.

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

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the first quarter of 2009 and any material developments with respect to matters previously reported in ConocoPhillips’ 2008 Annual Report on 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 (SEC) regulations.

Our U.S. refineries are implementing two separate consent decrees regarding alleged violations of the Federal Clean Air Act with the U.S. Environmental Protection Agency (EPA), six states and one local air pollution agency. Some of the requirements and limitations contained in the decrees provide for stipulated penalties for violations. Stipulated penalties under the decrees are not automatic, but must be requested by one of the agency signatories. As part of periodic reports under the decrees 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 SEC 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
We received an offer dated February 10, 2009, from the New Mexico Environmental Department (NMED) to settle Notice of Violation CON-0624-0801, which had been previously issued on November 12, 2008. This Notice of Violation (NOV) alleges five violations of the New Mexico Air Quality Control Act at our MCA Tank Battery No. 2 near Maljamar, New Mexico. The settlement offer proposes that we pay a $183,600 penalty. We are working with NMED to resolve this NOV.

ConocoPhillips Pipe Line Company received a Notice of Probable Violation and Proposed Civil Penalty (NOPV) from the U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration (USDOT) dated March 30, 2009. The NOPV alleges that ConocoPhillips Pipe Line Company violated certain operation and safety regulations regarding the control room response to a release on the WA line. The release occurred on January 8, 2008, near Denver City, Texas. USDOT’s proposed penalty for the alleged violation is $200,000. We are working with USDOT to resolve this matter.

Matters Previously Reported
On July 16, 2008, we received a demand from the Bay Area Air Quality Management district (BAAQMD) to settle 24 NOVs issued in late 2006 and 2007 for alleged violations of air pollution control regulations at the San Francisco refinery. The amount of the settlement demand is $304,500. On December 29, 2008, BAAQMD added an additional seven NOVs issued in 2008 and a corresponding additional $340,500 to its settlement demand. And on March 3, 2009, BAAQMD added an additional NOV issued in 2007 and a corresponding additional $100,000 to its settlement demand. We are working with BAAQMD to resolve these NOVs.

The South Coast Air Quality Management District (SCAQMD) conducted an audit of the Los Angeles refinery to assess compliance with applicable local, state and federal regulations related to fugitive emissions. As a result of the audit, SCAQMD issued three NOVs alleging multiple counts of noncompliance. We resolved two of the three NOVs for a total payment of $42,500 in the third quarter of 2008 and reached an agreement with SCAQMD to resolve the third NOV for $12,500 in the fourth quarter of 2008. We completed payment for these NOVs in February 2009.

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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. A penalty of $32,000 was submitted to the TCEQ in September 2008. The TCEQ approved the settlement on February 25, 2009.

On December 15, 2008, the Trainer refinery received Citations and a Notification of Penalty (Citation) from the Occupational Safety and Health Administration (OSHA) for 26 alleged violations noted during the OSHA National Emphasis Program review of the refinery. In March 2009, ConocoPhillips and OSHA settled these NOVs for $79,000, and we subsequently provided the settlement payment.

On June 2, 2008, the Billings refinery received a Violation Letter from the Montana Department of Environmental Quality (MDEQ) for opacity and nickel emissions, which occurred during startup of the catalytic cracker in April 2007. The letter also alleged certain monitoring quality assurance/quality control violations. The parties have agreed to a penalty of approximately $350,000 and are discussing possible supplemental environmental projects to offset all or some of the penalty amount.

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A of our 2008 Annual Report on Form 10-K.

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

Issuer Purchases of Equity Securities

								Millions of Dollars
						Total Number of		Approximate Dollar
						Shares Purchased		Value of Shares
						as Part of Publicly		that May Yet Be
	Total Number of			Average Price		Announced Plans		Purchased Under the
Period	Shares Purchased		*	Paid per Share		or Programs		Plans or Programs
January 1-31, 2009		-		$	-		-	$	-
February 1-28, 2009		2,994			45.47		-		-
March 1-31, 2009		-			-		-		-
Total		2,994		$	45.47		-

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

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Item 6. 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.

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SIGNATURE

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

CONOCOPHILLIPS

/s/ Glenda M. Schwarz

Glenda M. Schwarz

Vice President and Controller

(Chief Accounting and Duly Authorized Officer)

April 29, 2009

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