ConocoPhillips (COP) 10-Q 2009 Q2 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	June 30, 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
(State or other jurisdiction of
incorporation or organization) 01-0562944
(I.R.S. Employer
Identification No.)

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

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

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

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

ConocoPhillips had 1,482,903,059 shares of common stock, $.01 par value, outstanding at June 30, 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		27
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		32
Item 3. Quantitative and Qualitative Disclosures About Market Risk		51
Item 4. Controls and Procedures		51
Part II – Other Information
Item 1. Legal Proceedings		52
Item 1A. Risk Factors		53
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		53
Item 4. Submission of Matters to a Vote of Security Holders		54
Item 6. Exhibits		55
Signature		56
EX-12
EX-31.1
EX-31.2
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

Item 1. FINANCIAL STATEMENTS

Consolidated Income Statement ConocoPhillips

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
Revenues and Other Income
Sales and other operating revenues*	$	35,448			71,411			66,189			126,294
Equity in earnings of affiliates		1,076			1,812			1,491			3,171
Other income		106			130			230			440
Total Revenues and Other Income		36,630			73,353			67,910			129,905
Costs and Expenses
Purchased crude oil, natural gas and products		24,609			51,214			44,368			89,034
Production and operating expenses		2,573			3,111			5,118			5,802
Selling, general and administrative expenses		476			629			951			1,155
Exploration expenses		243			288			468			597
Depreciation, depletion and amortization		2,347			2,178			4,577			4,387
Impairments
Expropriated assets		51			-			51			-
Other		-			19			3			25
Taxes other than income taxes*		3,715			5,796			7,179			10,951
Accretion on discounted liabilities		108			96			212			200
Interest and debt expense		268			210			578			417
Foreign currency transaction (gains) losses		(142	)		-			(11	)		(43	)
Total Costs and Expenses		34,248			63,541			63,494			112,525
Income before income taxes		2,382			9,812			4,416			17,380
Provision for income taxes		1,068			4,356			2,246			7,766
Net income		1,314			5,456			2,170			9,614
Less: net income attributable to noncontrolling interests		(16	)		(17	)		(32	)		(36	)
Net Income Attributable to ConocoPhillips	$	1,298			5,439			2,138			9,578
Net Income Attributable to ConocoPhillips Per Share of Common Stock(dollars)
Basic	$	.87			3.54			1.44			6.18
Diluted		.87			3.50			1.43			6.11
Dividends Paid Per Share of Common Stock(dollars)	$	.47			.47			.94			.94
Average Common Shares Outstanding(in thousands)
Basic		1,486,496			1,534,975			1,486,195			1,548,587
Diluted		1,495,700			1,555,447			1,495,474			1,568,867
*Includes excise taxes on petroleum products sales:	$	3,316			4,091			6,376			7,948
See Notes to Consolidated Financial Statements.

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Consolidated Balance Sheet ConocoPhillips

	Millions of Dollars
	June 30			December 31
	2009			2008
Assets
Cash and cash equivalents	$	888			755
Accounts and notes receivable (net of allowance of $70 million in 2009 and $61 million in 2008)		10,747			10,892
Accounts and notes receivable—related parties		1,750			1,103
Inventories		6,181			5,095
Prepaid expenses and other current assets		3,508			2,998
Total Current Assets		23,074			20,843
Investments and long-term receivables		33,551			30,926
Loans and advances—related parties		2,038			1,973
Net properties, plants and equipment		86,246			83,947
Goodwill		3,715			3,778
Intangibles		835			846
Other assets		614			552
Total Assets	$	150,073			142,865
Liabilities
Accounts payable	$	13,197			12,852
Accounts payable—related parties		1,777			1,138
Short-term debt		1,438			370
Accrued income and other taxes		3,816			4,273
Employee benefit obligations		695			939
Other accruals		2,166			2,208
Total Current Liabilities		23,089			21,780
Long-term debt		28,926			27,085
Asset retirement obligations and accrued environmental costs		7,580			7,163
Joint venture acquisition obligation—related party		5,343			5,669
Deferred income taxes		18,136			18,167
Employee benefit obligations		4,178			4,127
Other liabilities and deferred credits		2,814			2,609
Total Liabilities		90,066			86,600
Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2009—1,731,058,293 shares; 2008—1,729,264,859 shares)
Par value		17			17
Capital in excess of par		43,514			43,396
Grantor trusts (at cost: 2009—39,808,419 shares; 2008—40,739,129 shares)		(688	)		(702	)
Treasury stock (at cost: 2009 and 2008—208,346,815 shares)		(16,211	)		(16,211	)
Accumulated other comprehensive income (loss)		998			(1,875	)
Unearned employee compensation		(89	)		(102	)
Retained earnings		31,388			30,642
Total Common Stockholders’ Equity		58,929			55,165
Noncontrolling interests		1,078			1,100
Total Equity		60,007			56,265
Total Liabilities and Equity	$	150,073			142,865
See Notes to Consolidated Financial Statements.

2

Consolidated Statement of Cash Flows ConocoPhillips

	Millions of Dollars
	Six Months Ended
	June 30
	2009			2008
Cash Flows From Operating Activities
Net income	$	2,170			9,614
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		4,577			4,387
Impairments		54			25
Dry hole costs and leasehold impairments		238			281
Accretion on discounted liabilities		212			200
Deferred taxes		(596	)		11
Undistributed equity earnings		(1,092	)		(1,988	)
Gain on asset dispositions		(36	)		(213	)
Other		175			(117	)
Working capital adjustments
Decrease (increase) in accounts and notes receivable		65			(3,625	)
Decrease (increase) in inventories		(973	)		(2,537	)
Decrease (increase) in prepaid expenses and other current assets		(435	)		(2,349	)
Increase (decrease) in accounts payable		1,020			5,481
Increase (decrease) in taxes and other accruals		(927	)		2,851
Net Cash Provided by Operating Activities		4,452			12,021
Cash Flows From Investing Activities
Capital expenditures and investments		(5,578	)		(6,720	)
Proceeds from asset dispositions		232			441
Long-term advances/loans—related parties		(121	)		(154	)
Collection of advances/loans—related parties		36			4
Other		(77	)		7
Net Cash Used in Investing Activities		(5,508	)		(6,422	)
Cash Flows From Financing Activities
Issuance of debt		9,029			2,065
Repayment of debt		(6,109	)		(1,841	)
Issuance of company common stock		(21	)		185
Repurchase of company common stock		-			(5,008	)
Dividends paid on company common stock		(1,393	)		(1,449	)
Other		(406	)		(240	)
Net Cash Provided by (Used in) Financing Activities		1,100			(6,288	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		89			20
Net Change in Cash and Cash Equivalents		133			(669	)
Cash and cash equivalents at beginning of period		755			1,456
Cash and Cash Equivalents at End of Period	$	888			787
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. 165
Effective April 1, 2009, we adopted Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 165, “Subsequent Events.” This Statement establishes the accounting for, and disclosure of, material events that occur after the balance sheet date, but before the financial statements are issued. In general, these events will be recognized if the condition existed at the date of the balance sheet, and will not be recognized if the condition did not exist at the balance sheet date. Disclosure is required for nonrecognized events if required to keep the financial statements from being misleading. The guidance in this Statement is very similar to current guidance provided in auditing literature and, therefore, will not result in significant changes in practice. Subsequent events have been evaluated through the date our interim financial statements were issued—the filing time and date of our second-quarter 2009 Quarterly Report on Form 10-Q.

SFAS No. 141 (Revised)
In December 2007, the FASB issued 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 assets acquired and liabilities assumed in the transaction; establishes the acquisition date as the fair value measurement point; and modifies disclosure requirements. It also modifies 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 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 that 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 June 30, 2009.

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SFAS No. 161
Effective January 1, 2009, we implemented SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB No. 133.” 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,” to provide greater transparency for derivative instruments within the scope of that Statement. Disclosures previously required only for the annual financial statements are now required in interim 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. See Note 13—Financial Instruments and Derivative Contracts, for additional information.

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 six 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 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 this Statement 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 is 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 Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” 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.

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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 $6.7 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. At June 30, 2009, the book value of our investment in West2East was $437 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.

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 a related party, OAO LUKOIL, have disproportionate interests. When related parties are involved in a VIE, 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, primarily for the development of the Yuzhno Khylchuyu (YK) Field. Initial production from YK was achieved in June 2008. At June 30, 2009, the book value of our investment in the venture was $2,061 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 LUKOIL have disproportionate interests. We had an obligation to fund, through loans, 30 percent of the terminal’s expansion 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 expansion was completed in June 2008, and the final loan amount was $271 million at June 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 June 30, 2009, Varandey used available cash to pay $40 million of interest. The outstanding accrued interest at June 30, 2009, was $23 million at June 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

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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 June 30, 2009, was $737 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 June 30, 2009, was 2.51 percent. Also on that date, Ashford held $2.1 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. On July 15, 2009, Ashford agreed to redeem the investment in Ashford held by Cold Spring. The difference between the redemption amount and the carrying value of the investment was not material.

Note 4—Inventories

Inventories consisted of the following:

	Millions of Dollars
	June 30		December 31
	2009		2008
Crude oil and petroleum products	$	5,231		4,232
Materials, supplies and other		950		863
	$	6,181		5,095

Inventories valued on the last-in, first-out (LIFO) basis totaled $5,042 million and $3,939 million at June 30, 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 $4,873 million and $1,959 million at June 30, 2009, and December 31, 2008, respectively.

Note 5—Assets Held for Sale

In June 2009, we signed an agreement to sell our remaining interest in the Keystone Pipeline to TransCanada Corporation. Subject to final regulatory approvals, the transaction is expected to close in the third quarter of this year. As a result, at June 30, 2009, we reclassified $505 million from “Investments and long-term receivables” to “Prepaid expenses and other current assets” on our consolidated balance sheet, and recorded a

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noncash impairment of $59 million before-tax, including associated cumulative foreign currency translation losses of $36 million and allocable goodwill of $61 million. This impairment, which is based on a Level 1 measurement in the fair value hierarchy, was reflected in “Equity in earnings of affiliates” in our consolidated income statement.

Note 6—Investments, Loans and Long-Term Receivables

LUKOIL
Our ownership interest in LUKOIL was 20 percent at June 30, 2009, based on 851 million shares authorized and issued. For financial reporting under U.S. generally accepted accounting principles (GAAP), 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 June 30, 2009.

At June 30, 2009, the book value of our ordinary share investment in LUKOIL was $5,913 million. Our 20 percent share of the net assets of LUKOIL was estimated to be $10,471 million. A majority of this negative basis difference of $4,558 million is being amortized on a straight-line basis over a 22-year useful life as an increase to equity earnings. On June 30, 2009, the closing price of LUKOIL shares on the London Stock Exchange was $44.37 per share, making the total market value of our LUKOIL investment $7,548 million.

Because LUKOIL’s accounting cycle close and preparation of U.S. GAAP financial statements occur subsequent to our reporting deadline, our equity earnings 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. Net income attributable to ConocoPhillips for the second quarter of 2009 included a $192 million positive alignment of our first-quarter estimate of LUKOIL’s results to LUKOIL’s reported results.

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 June 30, 2009, included the following:

• $737 million in loan financing to Freeport LNG Development, L.P. for the construction of an LNG receiving terminal, 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.

• $271 million at June 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 June 30, 2009, Varandey used available cash to pay $40 million of interest. The outstanding accrued interest at June 30, 2009, was $23 million at June 2009 exchange rates.

• $956 million of project financing and an additional $82 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.

• $150 million of loan financing to WRB Refining LLC to assist it in meeting its operating and capital spending requirements. Due to its expected short-term nature, this loan financing is included in the “Other” line in the investing activities section of the consolidated statement of cash flows for the six months ended June 30, 2009.

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The long-term portion of these loans are included in the “Loans and advances—related parties” line on the consolidated balance sheet, while the short-term portion is in “Accounts and notes receivable—related parties.”

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 June 30, 2009, was $312 million, and substantially the entire value is categorized in Level 1 of the fair value hierarchy.

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
	June 30, 2009						December 31, 2008
	Gross		Accum.		Net		Gross		Accum.		Net
	PP&E		DD&A		PP&E		PP&E		DD&A		PP&E
Exploration and Production (E&P)	$	108,846		40,404		68,442		102,591		35,375		67,216
Midstream		122		71		51		120		70		50
Refining and Marketing (R&M)		22,514		6,410		16,104		21,116		5,962		15,154
LUKOIL Investment		-		-		-		-		-		-
Chemicals		-		-		-		-		-		-
Emerging Businesses		1,191		290		901		1,056		293		763
Corporate and Other		1,579		831		748		1,561		797		764
	$	134,252		48,006		86,246		126,444		42,497		83,947

Suspended Wells
Our capitalized cost of suspended wells at June 30, 2009, was $861 million, an increase of $201 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, $13 million was charged to dry hole expense during the first six months of 2009.

Note 8—Impairments

Expropriated Assets
In April 2008, we initiated arbitration before the World Bank’s International Centre for Settlement of Investment 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 alleged unpaid taxes owed under the disputed Windfall Profits Tax Law. In March 2009, the ICSID Tribunal granted a temporary restraining order that commanded the Respondents to refrain from any conduct that aggravates the dispute between the parties or alters the status quo. However, the Respondents ignored the order, confiscated approximately 470,000 net barrels of crude oil and attempted to sell it through a public auction. In the second quarter of 2009, the ICSID Tribunal heard our motion for provisional measures and issued a second decision that ordered the Respondents to refrain from confiscating future production until a final decision has been rendered in the pending arbitration. The Respondents also ignored this decision by the Tribunal, continued to confiscate our crude oil production and sold the illegally seized crude oil to PetroEcuador at a 50 percent discount off the market value. As a result, our assets in Ecuador have been effectively expropriated.

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Accordingly, in the second quarter of 2009, we recorded a noncash charge of $51 million before- and after-tax related to the full impairment of our exploration and production investments in Ecuador.

Note 9—Debt

In 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. In addition, in May 2009, we issued $1.5 billion of 4.60% Notes due 2015, $1.0 billion of 6.00% Notes due 2020 and $500 million of 6.50% Notes due 2039. The proceeds from the notes were primarily used to reduce outstanding commercial paper balances and for general corporate purposes.

During the first six months of 2009, we used proceeds from the issuance of commercial paper to redeem $284 million of 6.375% Notes and $950 million of Floating Rate Notes upon their maturity.

At June 30, 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 June 30, 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, $2,211 million of commercial paper was outstanding at June 30, 2009, compared with $6,933 million at December 31, 2008.

Since we had $2,211 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 $4.8 billion in borrowing capacity under our revolving credit facility at June 30, 2009.

Also at June 30, 2009, we classified $2,278 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 July 2009, we arranged a new $500 million credit facility, which expires in July 2012, bringing our total borrowing capacity under our revolving credit facilities to $7.85 billion.

Note 10—Joint Venture Acquisition Obligation

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period, beginning in 2007, to FCCL 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 $642 million was short-term and was included in the “Accounts payable—related parties” line on our June 30, 2009, consolidated balance sheet. The principal portion of these payments, which totaled $309 million in the first six 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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Note 11—Guarantees

At June 30, 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.

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, we 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, expected in 2011. At June 30, 2009, the carrying value of the guarantee to third-party lenders was $11 million.

Guarantees of Joint Venture Debt

• In June 2006, we issued a guarantee for 24 percent of $2 billion in credit facilities of Rockies Express Pipeline LLC, operated by Kinder Morgan Energy Partners, L.P. At June 30, 2009, Rockies Express had $1,883 million outstanding under the credit facilities, with our 24 percent guarantee equaling $452 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 of the $2 billion credit facility is expected to take place at that time, making the debt nonrecourse to ConocoPhillips. At June 30, 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 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 its 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. Keystone’s other owner will guarantee a similar, but separate, funding vehicle. At June 30, 2009, $197 million was outstanding under the Keystone commercial paper program guaranteed by us.

• At June 30, 2009, we had guarantees outstanding for our portion of joint venture debt obligations, which have terms of up to 16 years. The maximum potential amount of future payments under the guarantees is approximately $100 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

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$90 million at June 30, 2009, 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.

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 current 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) at June 30, 2009, 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 October 2008, we elected to exercise an option to reduce our equity interest in Keystone from 50 percent to 20.01 percent through a dilution mechanism. At June 30, 2009, our ownership interest was approximately 23 percent. In June 2009, we signed an agreement to sell our remaining ownership interest in Keystone to TransCanada. Upon the closing of this transaction, currently expected in the third quarter, all our guarantees related to Keystone will cease.

• 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 natural 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 $550 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 15 years or life of the venture.

Indemnifications
Over the years, we have entered into various agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, environmental liabilities, permits and licenses, employee claims, real estate indemnity against tenant defaults, and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications at June 30, 2009, was $464 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.

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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 $260 million of environmental accruals for known contamination that are included in asset retirement obligations and accrued environmental costs at June 30, 2009. For additional information about environmental liabilities, see Note 12—Contingencies and Commitments.

Note 12—Contingencies and Commitments

In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use 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 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 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 a potentially responsible party. If we were solely responsible, the costs, in some cases, could be material to our results of operations, capital resources or liquidity, or to those of one of our segments. 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 site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability.

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Where it appears other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly.

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

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except for those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. At June 30, 2009, our consolidated balance sheet included a total environmental accrual of $972 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 June 30, 2009, we had performance obligations secured by letters of credit of $1,689 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 13—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 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.

Purchase and sales contracts for commodities that are readily convertible to cash (e.g., crude oil, natural gas and gasoline) are 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

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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).

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

Exchange-cleared financial options are valued using exchange closing prices and are classified as Level 1. Financial OTC and physical commodity options are valued using industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to which these inputs are observable in the forward markets determines whether the options are classified as Level 2 or 3.

We use a mid-market pricing convention (the mid-point between bid and ask prices). When appropriate, valuations are adjusted to reflect credit considerations, generally based on available market evidence.

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

	Millions of Dollars
	June 30, 2009												December 31, 2008
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets
Commodity derivatives	$	3,720			2,418			87			6,225			4,994			2,874			112			7,980
Foreign exchange derivatives		-			82			-			82			-			97			-			97
Total assets		3,720			2,500			87			6,307			4,994			2,971			112			8,077
Liabilities
Commodity derivatives		(4,060	)		(2,155	)		(13	)		(6,228	)		(5,221	)		(2,497	)		(72	)		(7,790	)
Foreign exchange derivatives		-			(20	)		-			(20	)		-			(93	)		-			(93	)
Total liabilities		(4,060	)		(2,175	)		(13	)		(6,248	)		(5,221	)		(2,590	)		(72	)		(7,883	)
Net assets (liabilities)	$	(340	)		325			74			59			(227	)		381			40			194

The derivative values above are based on analysis of each contract as the fundamental unit of account; 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.

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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						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
Beginning balance	$	96			(53	)		40			(34	)
Total net gains (losses), realized and unrealized, included in earnings		(8	)		(11	)		18			(53	)
Net purchases, issuances and settlements		(17	)		-			(27	)		24
Net transfers in (out) of Level 3		3			8			43			7
Ending balance	$	74			(56	)		74			(56	)

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

	Millions of Dollars
	2009									2008
				Purchased									Purchased
	Other			Crude Oil,						Other			Crude Oil,
	Operating			Natural Gas						Operating			Natural Gas
	Revenues			and Products			Total			Revenues			and Products		Total
Three Months Ended June 30
Total gains (losses) included in earnings	$	(8	)		-			(8	)		(14	)		3		(11	)
Change in unrealized gains (losses) relating to assets held at June 30	$	3			-			3			10			4		14
Change in unrealized gains (losses) relating to liabilities held at June 30	$	(9	)		-			(9	)		(25	)		-		(25	)
Six Months Ended June 30
Total gains (losses) included in earnings	$	19			(1	)		18			(57	)		4		(53	)
Change in unrealized gains (losses) relating to assets held at June 30	$	21			-			21			13			4		17
Change in unrealized gains (losses) relating to liabilities held at June 30	$	(10	)		-			(10	)		(61	)		-		(61	)

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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 our 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 June 30, 2009, and the line items where they appear on our consolidated balance sheet were:

	Millions
	of Dollars
Assets
Prepaid expenses and other current assets	$	5,794
Other assets		450
Liabilities
Other accruals		5,854
Other liabilities and deferred credits		393

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

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).

The gains (losses) from commodity derivatives incurred during the three- and six-month periods ended June 30, 2009, and the line items where they appear on our consolidated income statement were:

	Millions of Dollars
	Three Months Ended			Six Months Ended
	June 30			June 30
Sales and other operating revenues	$	(182	)		391
Other income		14			22
Purchased crude oil, natural gas and products		(443	)		(955	)

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

As of June 30, 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)		(30	)
Natural gas, power and carbon dioxide emissions (billions of cubic feet)
Flat price		(10	)
Basis		(250	)

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Currency Exchange Rate Derivative Contracts—We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to movements in currency exchange rates, 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 June 30, 2009, and the line items where they appear on our consolidated balance sheet were:

	Millions
	of Dollars
Assets
Prepaid expenses and other current assets	$	77
Other assets		5
Liabilities
Other accruals		20

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

The amounts shown in the preceding table are presented gross.

The impacts from foreign currency derivatives during the three- and six-month periods ended June 30, 2009, and the line item where they appear on our consolidated income statement were:

	Millions of Dollars
	Three Months Ended			Six Months Ended
	June 30			June 30
Foreign currency transaction (gains) losses	$	(166	)		(172	)

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

As of June 30, 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 other currencies (primarily euro and British pound)	USD	2,339
Buy British pound, sell euro	GBP	21

*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.

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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 June 30, 2009, was $406 million, for which we posted $15 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 June 30, 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 $391 million of additional collateral, either in the form of cash or letters of credit.

Fair Values of Financial Instruments

We used the following methods and assumptions to estimate the fair value of financial instruments:

• Cash and cash equivalents: The carrying amount reported on the balance sheet approximates fair value.

• Accounts and notes receivable: The carrying amount reported on the balance sheet approximates fair value.

• Investment in LUKOIL shares: See Note 6—Investments, Loans and Long-Term Receivables, for a discussion of the carrying value and fair value of our investment in LUKOIL shares.

• Debt: The carrying amount of our floating-rate debt approximates fair value. The fair value of the fixed-rate debt is estimated based on quoted market prices.

• Fixed-rate 5.3 percent joint venture acquisition obligation: Fair value is estimated based on the net present value of the future cash flows, discounted at a June 30, 2009, effective yield rate of 3.54 percent, based on yields of U.S. Treasury securities of similar average duration adjusted for our average credit risk spread and the amortizing nature of the obligation principal. See Note 10—Joint Venture Acquisition Obligation, for additional information.

• Swaps: Fair value is estimated based on forward market prices and approximates the exit price at period end. When forward market prices are not available, they are estimated using the forward prices of a similar commodity with adjustments for differences in quality or location.

• Futures: Fair values are based on quoted market prices obtained from the New York Mercantile Exchange, the ICE Futures, or other traded exchanges.

• Forward-exchange contracts: Fair value is estimated by comparing the contract rate to the forward rate in effect on June 30, 2009, and approximates the exit price at that date.

Certain of our commodity derivative and financial instruments at June 30, 2009, were:

	Millions of Dollars
	Carrying Amount			Fair Value
Financial assets
Foreign currency derivatives		$	82		82
Commodity derivatives			1,264		1,264
Financial liabilities
Total debt, excluding capital leases			30,339		31,374
Joint venture acquisition obligation			5,985		6,457
Foreign currency derivatives			20		20
Commodity derivatives			797		797

The amounts shown for derivatives in the preceding table are presented net (i.e., assets and liabilities with the same counterparty are netted where the right of offset and intent to net exist). In addition, the commodity

19

derivative assets appear net of $56 million of obligations to return cash collateral, while the commodity derivative liabilities appear net of $526 million of rights to reclaim cash collateral. No collateral was deposited or held for the foreign currency derivatives.

Note 14—Comprehensive Income

ConocoPhillips’ comprehensive income was as follows:

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
Net income	$	1,314			5,456			2,170			9,614
After-tax changes in:
Defined benefit pension plans
Net prior service cost		3			(14	)		6			(10	)
Net actuarial loss		33			(2	)		67			7
Nonsponsored plans		(1	)		2			(2	)		4
Foreign currency translation adjustments		3,079			178			2,801			(257	)
Hedging activities		2			2			1			-
Comprehensive income		4,430			5,622			5,043			9,358
Less: comprehensive income attributable to noncontrolling interests		(16	)		(17	)		(32	)		(36	)
Comprehensive income attributable to ConocoPhillips	$	4,414			5,605			5,011			9,322

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

	Millions of Dollars
	June 30			December 31
	2009			2008
Defined benefit pension plans	$	(1,363	)		(1,434	)
Foreign currency translation adjustments		2,370			(431	)
Deferred net hedging loss		(9	)		(10	)
Accumulated other comprehensive income (loss)	$	998			(1,875	)

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

Note 15—Cash Flow Information

	Millions of Dollars
	Six Months Ended
	June 30
	2009		2008
Cash Payments
Interest	$	416		398
Income taxes		3,271		6,405

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Note 16—Employee Benefit Plans

Pension and Postretirement Plans

	Millions of Dollars
	Pension Benefits												Other Benefits
Components of Net Periodic Benefit Cost	2009						2008						2009			2008
	U.S.			Int’l.			U.S.			Int’l.
Three Months Ended June 30
Service cost	$	49			18			47			24			2			4
Interest cost		70			35			62			46			11			16
Expected return on plan assets		(46	)		(30	)		(56	)		(45	)		-			-
Amortization of prior service cost		2			-			2			-			2			2
Recognized net actuarial (gain) loss		46			9			17			3			(3	)		(6	)
Net periodic benefit costs	$	121			32			72			28			12			16
Six Months Ended June 30
Service cost	$	97			38			94			47			4			7
Interest cost		139			68			124			90			23			28
Expected return on plan assets		(92	)		(59	)		(112	)		(89	)		-			-
Amortization of prior service cost		5			-			4			-			4			5
Recognized net actuarial (gain) loss		93			17			33			6			(7	)		(10	)
Net periodic benefit costs	$	242			64			143			54			24			30

During the first six months of 2009, we contributed $160 million to our domestic benefit plans and $70 million to our international benefit plans. We currently expect to make additional contributions of approximately $590 million to our domestic benefit plans and $70 million to our international benefit plans for totals of $750 million and $140 million, respectively, in 2009.

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 occurring during 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
	June 30			December 31
	2009			2008
Beginning balance	$	162			-
Accruals		5			162
Benefit payments		(66	)		-
Ending balance	$	101			162

The remaining balance at June 30, 2009, of $101 million is classified as short-term.

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Note 17—Related Party Transactions

Significant transactions with related parties were:

	Millions of Dollars
	Three Months Ended				Six Months Ended
	June 30				June 30
	2009		2008		2009		2008
Operating revenues (a)	$	1,892		4,001		3,365		7,172
Purchases (b)		3,168		5,693		5,650		10,092
Operating expenses and selling, general and administrative expenses (c)		71		127		157		243
Net interest expense (d)		20		19		39		40

(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 Refining. We purchased natural gas and natural gas liquids from DCP Midstream and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchased crude oil from LUKOIL 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 Partnership. See Note 6—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

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Note 18—Segment Disclosures and Related Information

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

1)	E&P—This segment primarily explores for, produces, transports and markets crude oil, natural gas and natural gas liquids on a worldwide basis.
2)	Midstream—This segment gathers, processes and markets natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, 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 June 30, 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.

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Analysis of Results by Operating Segment

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
Sales and Other Operating Revenues
E&P
United States	$	5,397			15,964			11,493			27,511
International		5,048			8,471			11,699			16,912
Intersegment eliminations—U.S.		(1,187	)		(2,525	)		(2,046	)		(4,637	)
Intersegment eliminations—international		(1,397	)		(3,550	)		(2,785	)		(5,847	)
E&P		7,861			18,360			18,361			33,939
Midstream
Total sales		973			2,100			1,895			3,742
Intersegment eliminations		(53	)		(30	)		(101	)		(119	)
Midstream		920			2,070			1,794			3,623
R&M
United States		18,415			37,250			31,416			64,211
International		8,368			13,969			14,832			24,895
Intersegment eliminations—U.S.		(140	)		(285	)		(257	)		(504	)
Intersegment eliminations—international		(12	)		(13	)		(21	)		(20	)
R&M		26,631			50,921			45,970			88,582
LUKOIL Investment		-			-			-			-
Chemicals		3			3			6			6
Emerging Businesses
Total sales		133			230			287			488
Intersegment eliminations		(104	)		(179	)		(241	)		(356	)
Emerging Businesses		29			51			46			132
Corporate and Other		4			6			12			12
Consolidated sales and other operating revenues	$	35,448			71,411			66,189			126,294
Net Income (Loss) Attributable to ConocoPhillips
E&P
United States	$	336			1,852			509			3,201
International		389			2,147			916			3,685
Total E&P		725			3,999			1,425			6,886
Midstream		31			162			154			299
R&M
United States		(38	)		587			60			1,022
International		(14	)		77			93			162
Total R&M		(52	)		664			153			1,184
LUKOIL Investment		682			774			730			1,484
Chemicals		67			18			90			70
Emerging Businesses		2			8			2			20
Corporate and Other		(157	)		(186	)		(416	)		(365	)
Consolidated net income attributable to ConocoPhillips	$	1,298			5,439			2,138			9,578

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	Millions of Dollars
	June 30		December 31
	2009		2008
Total Assets
E&P
United States	$	36,198		36,962
International		61,349		58,912
Total E&P		97,547		95,874
Midstream		1,775		1,455
R&M
United States		25,414		22,554
International		9,497		7,942
Goodwill		3,715		3,778
Total R&M		38,626		34,274
LUKOIL Investment		6,186		5,455
Chemicals		2,294		2,217
Emerging Businesses		1,081		924
Corporate and Other		2,564		2,666
Consolidated total assets	$	150,073		142,865

Note 19—Income Taxes

Our effective tax rate for the second quarter and first six months of 2009 was 45 percent and 51 percent, respectively, compared with 44 percent and 45 percent for the same two periods of 2008. The change in the effective tax rate for the first six months of 2009, compared with the same period of 2008, was primarily due to a higher proportion of income in higher tax 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 20—New Accounting Standards

In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets, an amendment of FASB Statement No. 140.” This Statement removes the concept of a qualifying special purpose entity (SPE) from SFAS No. 140 and the exception for qualifying SPEs from the consolidation guidance of FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities” (FIN 46(R)). Additionally, the Statement clarifies the requirements for financial asset transfers eligible for sale accounting. This Statement is effective January 1, 2010, and we do not expect any significant impact to our consolidated financial statements.

Also in June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R),” which amends FIN 46(R) to address the effects of the elimination of the qualifying SPE concept in SFAS No. 166, and other concerns about the application of key provisions of
FIN 46(R). More specifically, SFAS No. 167 requires a qualitative rather than a quantitative approach to determine the primary beneficiary of a VIE, it amends certain guidance pertaining to the determination of the primary beneficiary when related parties are involved, and it amends certain guidance for determining whether an entity is a VIE. Additionally, this Statement requires continuous assessments of whether an enterprise is the primary beneficiary of a VIE. This Statement is effective January 1, 2010. We are currently evaluating the impact on our consolidated financial statements.

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The FASB issued SFAS No. 168, “The FASB Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement 162,” in late June 2009. The FASB Accounting Standards Codification will become the source of authoritative U.S. generally accepted accounting principles (GAAP) and will supersede all then-existing non-SEC accounting and reporting standards on the effective date, September 15, 2009. The Codification will not change GAAP, but consolidates it into a logical and consistent structure. We will be required to revise our references to GAAP in our financial statements beginning with the third quarter of 2009.

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.” This FSP is effective for annual financial statements beginning with the 2009 fiscal year, but will not impact our consolidated financial statements, other than requiring additional disclosures.

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Supplementary Information—Condensed Consolidating Financial Information

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

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

• All other nonguarantor subsidiaries of ConocoPhillips.

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

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

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	Millions of Dollars
	Three Months Ended June 30, 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	$	-			21,922			-		-			-			13,526			-			35,448
Equity in earnings of affiliates		1,387			1,555			-		-			-			733			(2,599	)		1,076
Other income (loss)		1			116			-		-			-			(11	)		-			106
Intercompany revenues		15			220			12		19			12			3,969			(4,247	)		-
Total Revenues and Other Income		1,403			23,813			12		19			12			18,217			(6,846	)		36,630
Costs and Expenses
Purchased crude oil, natural gas and products		-			19,297			-		-			-			9,349			(4,037	)		24,609
Production and operating expenses		-			1,120			-		-			-			1,478			(25	)		2,573
Selling, general and administrative expenses		5			309			-		(1	)		(1	)		167			(3	)		476
Exploration expenses		-			51			-		-			-			192			-			243
Depreciation, depletion and amortization		-			415			-		-			-			1,932			-			2,347
Impairments		-			-			-		-			-			51			-			51
Taxes other than income taxes		-			1,212			-		-			-			2,504			(1	)		3,715
Accretion on discounted liabilities		-			19			-		-			-			89			-			108
Interest and debt expense		149			16			11		20			14			239			(181	)		268
Foreign currency transaction (gains) losses		-			(50	)		-		93			116			(301	)		-			(142	)
Total Costs and Expenses		154			22,389			11		112			129			15,700			(4,247	)		34,248
Income (loss) before income taxes		1,249			1,424			1		(93	)		(117	)		2,517			(2,599	)		2,382
Provision for income taxes		(49	)		37			-		1			(13	)		1,092			-			1,068
Net income (loss)		1,298			1,387			1		(94	)		(104	)		1,425			(2,599	)		1,314
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(16	)		-			(16	)
Net Income (Loss) Attributable to ConocoPhillips	$	1,298			1,387			1		(94	)		(104	)		1,409			(2,599	)		1,298
Income Statement	Three Months Ended June 30, 2008
Revenues and Other Income
Sales and other operating revenues	$	-			47,793			-		-			-			23,618			-			71,411
Equity in earnings of affiliates		5,466			3,796			-		-			-			1,446			(8,896	)		1,812
Other income (loss)		(1	)		182			-		-			-			(51	)		-			130
Intercompany revenues		15			915			19		22			13			9,693			(10,677	)		-
Total Revenues and Other Income		5,480			52,686			19		22			13			34,706			(19,573	)		73,353
Costs and Expenses
Purchased crude oil, natural gas and products		-			44,038			-		-			-			17,540			(10,364	)		51,214
Production and operating expenses		-			1,337			-		-			-			1,807			(33	)		3,111
Selling, general and administrative expenses		5			466			-		-			-			171			(13	)		629
Exploration expenses		-			45			-		-			-			243			-			288
Depreciation, depletion and amortization		-			379			-		-			-			1,799			-			2,178
Impairments		-			17			-		-			-			2			-			19
Taxes other than income taxes		-			1,285			-		-			-			4,569			(58	)		5,796
Accretion on discounted liabilities		-			14			-		-			-			82			-			96
Interest and debt expense		51			104			18		20			13			213			(209	)		210
Foreign currency transaction (gains) losses		-			2			-		58			66			(126	)		-			-
Total Costs and Expenses		56			47,687			18		78			79			26,300			(10,677	)		63,541
Income (loss) before income taxes		5,424			4,999			1		(56	)		(66	)		8,406			(8,896	)		9,812
Provision for income taxes		(15	)		550			-		(17	)		(21	)		3,859			-			4,356
Net income (loss)		5,439			4,449			1		(39	)		(45	)		4,547			(8,896	)		5,456
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(17	)		-			(17	)
Net Income (Loss) Attributable to ConocoPhillips	$	5,439			4,449			1		(39	)		(45	)		4,530			(8,896	)		5,439

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	Millions of Dollars
	Six Months Ended June 30, 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	$	-			39,456			-		-			-			26,733			-			66,189
Equity in earnings of affiliates		2,316			2,510			-		-			-			1,014			(4,349	)		1,491
Other income (loss)		(1	)		319			-		-			-			(88	)		-			230
Intercompany revenues		16			602			29		37			23			7,473			(8,180	)		-
Total Revenues and Other Income		2,331			42,887			29		37			23			35,132			(12,529	)		67,910
Costs and Expenses
Purchased crude oil, natural gas and products		-			34,138			-		-			-			17,936			(7,706	)		44,368
Production and operating expenses		2			2,214			-		-			-			2,953			(51	)		5,118
Selling, general and administrative expenses		8			632			-		-			-			324			(13	)		951
Exploration expenses		-			116			-		-			-			352			-			468
Depreciation, depletion and amortization		-			840			-		-			-			3,737			-			4,577
Impairments		-			(5	)		-		-			-			59			-			54
Taxes other than income taxes		-			2,367			-		-			-			4,831			(19	)		7,179
Accretion on discounted liabilities		-			37			-		-			-			175			-			212
Interest and debt expense		279			85			26		39			27			513			(391	)		578
Foreign currency transaction (gains) losses		-			(43	)		-		55			109			(132	)		-			(11	)
Total Costs and Expenses		289			40,381			26		94			136			30,748			(8,180	)		63,494
Income (loss) before income taxes		2,042			2,506			3		(57	)		(113	)		4,384			(4,349	)		4,416
Provision for income taxes		(96	)		190			1		2			(17	)		2,166			-			2,246
Net income (loss)		2,138			2,316			2		(59	)		(96	)		2,218			(4,349	)		2,170
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(32	)		-			(32	)
Net Income (Loss) Attributable to ConocoPhillips	$	2,138			2,316			2		(59	)		(96	)		2,186			(4,349	)		2,138
Income Statement	Six Months Ended June 30, 2008
Revenues and Other Income
Sales and other operating revenues	$	-			82,596			-		-			-			43,698			-			126,294
Equity in earnings of affiliates		9,651			6,857			-		-			-			2,754			(16,091	)		3,171
Other income (loss)		(1	)		487			-		-			-			(46	)		-			440
Intercompany revenues		24			1,632			43		45			27			15,743			(17,514	)		-
Total Revenues and Other Income		9,674			91,572			43		45			27			62,149			(33,605	)	��	129,905
Costs and Expenses
Purchased crude oil, natural gas and products		-			75,530			-		-			-			30,183			(16,679	)		89,034
Production and operating expenses		-			2,447			-		-			-			3,425			(70	)		5,802
Selling, general and administrative expenses		7			785			-		-			-			396			(33	)		1,155
Exploration expenses		-			100			-		-			-			497			-			597
Depreciation, depletion and amortization		-			751			-		-			-			3,636			-			4,387
Impairments		-			21			-		-			-			4			-			25
Taxes other than income taxes		-			2,539			-		-			-			8,531			(119	)		10,951
Accretion on discounted liabilities		-			29			-		-			-			171			-			200
Interest and debt expense		128			325			40		39			26			472			(613	)		417
Foreign currency transaction (gains) losses		-			(2	)		-		(14	)		(7	)		(20	)		-			(43	)
Total Costs and Expenses		135			82,525			40		25			19			47,295			(17,514	)		112,525
Income before income taxes		9,539			9,047			3		20			8			14,854			(16,091	)		17,380
Provision for income taxes		(39	)		987			1		(13	)		(13	)		6,843			-			7,766
Net income		9,578			8,060			2		33			21			8,011			(16,091	)		9,614
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(36	)		-			(36	)
Net Income Attributable to ConocoPhillips	$	9,578			8,060			2		33			21			7,975			(16,091	)		9,578

29

	Millions of Dollars
	June 30, 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	$	-			132		-			14			1			741		-			888
Accounts and notes receivable		20			9,473		-			-			-			20,353		(17,349	)		12,497
Inventories		-			3,657		-			-			-			2,524		-			6,181
Prepaid expenses and other current assets		9			1,468		-			11			7			2,030		(17	)		3,508
Total Current Assets		29			14,730		-			25			8			25,648		(17,366	)		23,074
Investments, loans and long-term receivables*		66,933			83,214		757			1,250			847			45,577		(162,989	)		35,589
Net properties, plants and equipment		-			19,710		-			-			-			66,536		-			86,246
Goodwill		-			3,715		-			-			-			-		-			3,715
Intangibles		-			777		-			-			-			58		-			835
Other assets		53			255		2			50			72			296		(114	)		614
Total Assets	$	67,015			122,401		759			1,325			927			138,115		(180,469	)		150,073
Liabilities and Equity
Accounts payable	$	-			13,702		-			2			1			18,618		(17,349	)		14,974
Short-term debt		1,202			18		-			-			-			218		-			1,438
Accrued income and other taxes		-			348		-			(2	)		(1	)		3,471		-			3,816
Employee benefit obligations		-			491		-			-			-			204		-			695
Other accruals		183			742		9			15			10			1,224		(17	)		2,166
Total Current Liabilities		1,385			15,301		9			15			10			23,735		(17,366	)		23,089
Long-term debt		13,309			5,338		749			1,250			849			7,431		-			28,926
Asset retirement obligations and accrued environmental costs		-			1,112		-			-			-			6,468		-			7,580
Joint venture acquisition obligation		-			-		-			-			-			5,343		-			5,343
Deferred income taxes		(4	)		3,000		-			11			16			15,113		-			18,136
Employee benefit obligations		-			3,362		-			-			-			816		-			4,178
Other liabilities and deferred credits*		68			23,696		-			-			-			16,459		(37,409	)		2,814
Total Liabilities		14,758			51,809		758			1,276			875			75,365		(54,775	)		90,066
Retained earnings		24,875			7,108		(1	)		66			71			7,549		(8,280	)		31,388
Other common stockholders’ equity		27,382			63,484		2			(17	)		(19	)		54,123		(117,414	)		27,541
Noncontrolling interests		-			-		-			-			-			1,078		-			1,078
Total Liabilities and Equity	$	67,015			122,401		759			1,325			927			138,115		(180,469	)		150,073
*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 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 Equity	$	61,180			122,095		1,716			1,316			996			136,050		(180,488	)		142,865

*Includes intercompany loans.

30

	Millions of Dollars
	Six Months Ended June 30, 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	$	(5,340	)		5,976			-			4		-		5,669			(1,857	)		4,452
Cash Flows From Investing Activities
Capital expenditures and investments		-			(1,779	)		-			-		-		(4,035	)		236			(5,578	)
Proceeds from asset dispositions		-			5			-			-		-		227			-			232
Long-term advances/loans—related parties		-			11			-			-		-		(136	)		4			(121	)
Collection of advances/loans—related parties		-			97			950			-		-		3,783			(4,794	)		36
Other		-			(107	)		-			-		-		30			-			(77	)
Net Cash Provided by (Used in) Investing Activities		-			(1,773	)		950			-		-		(131	)		(4,554	)		(5,508	)
Cash Flows From Financing Activities
Issuance of debt		8,910			-			-			-		-		123			(4	)		9,029
Repayment of debt		(2,109	)		(4,081	)		(950	)		-		-		(3,763	)		4,794			(6,109	)
Issuance of company common stock		(21	)		-			-			-		-		-			-			(21	)
Dividends paid on company common stock		(1,393	)		-			-			-		-		(1,871	)		1,871			(1,393	)
Other		(47	)		2			-			-		-		(125	)		(236	)		(406	)
Net Cash Provided by (Used in) Financing Activities		5,340			(4,079	)		(950	)		-		-		(5,636	)		6,425			1,100
Effect of Exchange Rate Changes on Cash and Cash Equivalents		-			-			-			-		-		89			-			89
Net Change in Cash and Cash Equivalents		-			124			-			4		-		(9	)		14			133
Cash and cash equivalents at beginning of period		-			8			-			10		1		750			(14	)		755
Cash and Cash Equivalents at End of Period	$	-			132			-			14		1		741			-			888
Statement of Cash Flows	Six Months Ended June 30, 2008
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	5,815			189			4			5		-		6,830			(822	)		12,021
Cash Flows From Investing Activities
Capital expenditures and investments		-			(2,462	)		-			-		-		(4,611	)		353			(6,720	)
Proceeds from asset dispositions		-			73			-			-		-		372			(4	)		441
Long-term advances/loans—related parties		-			(53	)		-			-		-		(2,523	)		2,422			(154	)
Collection of advances/loans—related parties		-			212			-			-		-		9			(217	)		4
Other		-			10			-			-		-		(3	)		-			7
Net Cash Provided by (Used in) Investing Activities		-			(2,220	)		-			-		-		(6,756	)		2,554			(6,422	)
Cash Flows From Financing Activities
Issuance of debt		1,967			2,412			-			-		-		108			(2,422	)		2,065
Repayment of debt		(1,500	)		(338	)		-			-		-		(220	)		217			(1,841	)
Issuance of company common stock		185			-			-			-		-		-			-			185
Repurchase of company common stock		(5,008	)		-			-			-		-		-			-			(5,008	)
Dividends paid on company common stock		(1,449	)		-			(4	)		-		-		(1,191	)		1,195			(1,449	)
Other		(10	)		128			-			-		-		(9	)		(349	)		(240	)
Net Cash Provided by (Used in) Financing Activities		(5,815	)		2,202			(4	)		-		-		(1,312	)		(1,359	)		(6,288	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		-			-			-			-		-		20			-			20
Net Change in Cash and Cash Equivalents		-			171			-			5		-		(1,218	)		373			(669	)
Cash and cash equivalents at beginning of period		-			195			-			7		1		1,626			(373	)		1,456
Cash and Cash Equivalents at End of Period	$	-			366			-			12		1		408			-			787

31

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 50.

The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss) attributable to ConocoPhillips.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is an international, integrated energy company. We are the third-largest integrated energy company in the United States, based on market capitalization. At June 30, 2009, we had approximately 30,000 employees and total assets of $150 billion.

The energy industry continued to be characterized by economic volatility during the second quarter and first six months of 2009. The price of West Texas Intermediate (WTI) benchmark crude oil peaked during mid-2008 at almost $150 per barrel, and fell sharply throughout the remainder of the year to the low-$30-per-barrel range. Since the end of 2008, crude oil prices have trended upward, with WTI averaging $59.54 per barrel in the second quarter of 2009, or $16.57 higher than the first quarter of 2009. The improvement in crude oil prices during 2009 was influenced by expectations of stabilization and eventual recovery of the world economy.

Industry natural gas prices for Henry Hub decreased during the second quarter of 2009, averaging $3.51 per million British thermal units, down $1.40 compared with the first quarter of 2009, and down $7.43 compared with the second quarter of 2008. Domestic natural gas prices trended downward mostly due to higher unconventional (shale) production in the Lower 48 and lower demand in all sectors due to the U.S. recession. As a result of the changes in supply and demand, natural gas storage levels are higher than both the five-year average and the levels at the end of the second quarter of 2008.

Against this economic backdrop, our Exploration and Production (E&P) segment had earnings of $725 million in the second quarter of 2009. This compares with E&P earnings of $700 million in the first quarter of 2009 and $3,999 million in the second quarter of 2008.

Global refining margins remained weak in the second quarter of 2009, as demand, particularly for distillates, continued to be suppressed by the global economic slowdown. In addition, the compressed differential in prices for high-quality crude oil compared with those of lower-quality crude oil reduced margins for those refineries configured to capitalize on the ability to process lower-quality crudes. Weak refining margins significantly impacted our Refining and Marketing (R&M) segment, which reported a loss of $52 million in the second quarter of 2009, compared with earnings of $205 million in the first quarter of 2009 and earnings of $664 million in the second quarter of 2008.

Our LUKOIL Investment segment had earnings of $682 million in the second quarter of 2009, compared with $48 million in the first quarter of 2009, and $774 million in the second quarter of 2008. For the six-month periods, our equity earnings from LUKOIL were $730 million in 2009, compared with $1,484 million in 2008. These results indicate LUKOIL was also negatively impacted by lower commodity prices and refining margins.

32

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and six-month periods ended June 30, 2009, is based on a comparison with the corresponding periods of 2008.

Consolidated Results

A summary of earnings (loss) by business segment follows:

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
Exploration and Production (E&P)	$	725			3,999			1,425			6,886
Midstream		31			162			154			299
Refining and Marketing (R&M)		(52	)		664			153			1,184
LUKOIL Investment		682			774			730			1,484
Chemicals		67			18			90			70
Emerging Businesses		2			8			2			20
Corporate and Other		(157	)		(186	)		(416	)		(365	)
Net income attributable to ConocoPhillips	$	1,298			5,439			2,138			9,578

Earnings were $1,298 million in the second quarter of 2009, compared with $5,439 million in the second quarter of 2008. For the six-month periods ended June 30, 2009 and 2008, earnings were $2,138 million and $9,578 million, respectively. The decrease from both 2008 periods was primarily the result of:

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

• Lower results from our R&M segment, reflecting lower refining margins.

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

Income Statement Analysis

Sales and other operating revenues decreased 50 percent in the second quarter of 2009 and 48 percent in the six-month period, whilepurchased crude oil, natural gas and products decreased 52 percent and 50 percent, respectively. These 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 41 percent in the second quarter of 2009 and 53 percent in the six-month period, reflecting reduced earnings from LUKOIL; DCP Midstream, LLC; Malaysian Refining Company Sdn. Bhd.; Merey Sweeny, L.P. (MSLP); and WRB Refining LLC.

Other income decreased 48 percent during the first six months of 2009. The decrease was primarily due to 2008 gains related to asset rationalization efforts in our R&M segment.

Production and operating expenses decreased 17 percent in the second quarter of 2009 and 12 percent in the six-month period. Contributing to these decreases were lower utilities expense, favorable foreign exchange impacts, and our emphasis on cost reduction.

Selling, general and administrative expenses decreased 24 percent in the second quarter of 2009 and 18 percent in the six-month period mostly due to reduced expenses as a result of disposition of U.S. and international marketing assets.

33

Exploration expenses decreased 22 percent during the first six months of 2009, predominantly due to decreases in geological and geophysical expenses, leasehold impairments and dry hole costs.

Taxes other than income taxes decreased 36 percent in the second quarter of 2009 and 34 percent in the six-month period, primarily due to lower production taxes resulting from lower crude oil prices, as well as reduced excise taxes on petroleum product sales.

Interest and debt expense increased 28 percent and 39 percent in the second quarter and first six months of 2009 as a result of a higher average debt level and lower amounts of interest being capitalized, partially offset by lower interest rates.

Segment Results

E&P

	Three Months Ended					Six Months Ended
	June 30					June 30
	2009			2008		2009			2008
	Millions of Dollars
Net Income (Loss) Attributable to ConocoPhillips
Alaska	$	404			700		648			1,303
Lower 48		(68	)		1,152		(139	)		1,898
United States		336			1,852		509			3,201
International		389			2,147		916			3,685
	$	725			3,999		1,425			6,886
	Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)
United States	$	55.13			118.66		47.82			106.51
International		56.93			119.75		49.94			107.94
Total consolidated		56.11			119.24		49.00			107.27
Equity affiliates*		51.89			93.20		43.48			76.86
Worldwide E&P		55.63			118.01		48.43			105.68
Natural gas (per thousand cubic feet)
United States		3.00			9.69		3.41			8.67
International		4.27			10.02		5.07			9.15
Total consolidated		3.72			9.87		4.35			8.94
Equity affiliates*		2.10			-		2.10			-
Worldwide E&P		3.69			9.87		4.31			8.94
Natural gas liquids (per barrel)
United States		27.73			65.96		26.17			62.31
International		30.04			71.40		30.80			66.86
Total consolidated		28.73			68.42		28.15			64.40
Worldwide E&P		28.73			68.42		28.15			64.40
	Millions of Dollars
Worldwide Exploration Expenses
General administrative; geological and geophysical; and lease rentals	$	128			161		230			316
Leasehold impairment		49			59		92			119
Dry holes		66			68		146			162
	$	243			288		468			597

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

34

	Three Months Ended				Six Months Ended
	June 30				June 30
	2009		2008		2009		2008
	Thousands of Barrels Daily
Operating Statistics
Crude oil produced
Alaska		236		244		245		249
Lower 48		92		95		92		96
United States		328		339		337		345
Europe		223		194		232		198
Asia Pacific		109		86		115		88
Canada		23		24		24		23
Middle East and Africa		73		78		74		80
Other areas		7		10		8		10
Total consolidated		763		731		790		744
Equity affiliates*
Canada		41		25		38		27
Russia and Caspian		55		16		52		16
		859		772		880		787
Natural gas liquids produced
Alaska		16		17		18		18
Lower 48		78		76		74		73
United States		94		93		92		91
Europe		17		19		19		21
Asia Pacific		17		17		17		15
Canada		24		25		24		26
Middle East and Africa		3		2		2		2
		155		156		154		155
	Millions of Cubic Feet Daily
Natural gas produced**
Alaska		83		98		88		99
Lower 48		2,012		2,034		2,020		1,998
United States		2,095		2,132		2,108		2,097
Europe		849		880		924		952
Asia Pacific		721		616		717		602
Canada		1,174		1,055		1,120		1,078
Middle East and Africa		118		116		115		110
Other areas		-		19		-		20
Total consolidated		4,957		4,818		4,984		4,859
Equity affiliates*
Asia Pacific		94		-		85		-
		5,051		4,818		5,069		4,859
	Thousands of Barrels Daily
Mining operations Syncrude produced		16		19		20		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.

35

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 June 30, 2009, our E&P operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria, and Russia.

Earnings from the E&P segment decreased 82 percent and 79 percent in the second quarter and first six months of 2009, primarily due to substantially lower crude oil, natural gas and natural gas liquids prices. This decrease was partially offset by lower Alaska and Lower 48 production taxes due to lower prices, higher international volumes and improved operating costs. See the “Business Environment and Executive Overview” section for additional information on industry crude oil and natural gas prices.

U.S. E&P
Earnings from our U.S. E&P operations decreased 82 percent in the second quarter and 84 percent in the first six months of 2009 due to significantly lower crude oil, natural gas and natural gas liquids prices, partially offset by lower production taxes. As a result of an order issued by the Federal Energy Regulatory Commission (FERC) in April 2009, we re-evaluated the transportation tariff-rate component of our Alaska production tax accrual, which resulted in a downward adjustment of the accrual in the second quarter of 2009.

U.S. E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 771,000 BOE per day in the second quarter of 2009; this compares with 787,000 in the second quarter of 2008. The decrease was primarily due to field decline, partially offset by improved well performance and less unplanned downtime.

International E&P
Earnings from our international E&P operations decreased 82 percent in the second quarter and 75 percent in the first six months of 2009, primarily as a result of significantly lower crude oil, natural gas and natural gas liquids prices, partially offset by higher volumes and lower operating costs.

International E&P production averaged 1,085,000 BOE per day in the second quarter of 2009, an increase of 15 percent from 944,000 in the second quarter of 2008. The increase was predominantly due to production from new developments in the United Kingdom, Russia, Canada, Norway, China and Vietnam, which was partially offset by field decline. In addition, production increased due to impacts from the royalty framework in Alberta, Canada, and from production sharing contracts. Our Syncrude mining operations produced 16,000 barrels per day in the second quarter of 2009, a decrease from 19,000 barrels per day in the second quarter of 2008, due to unplanned downtime.

In the second quarter of 2009, we recorded a noncash charge of $51 million before- and after-tax related to the full impairment of our exploration and production investments in Ecuador. For more information see the “Expropriated Assets” section of Note 8—Impairments, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

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Midstream

	Three Months Ended				Six Months Ended
	June 30				June 30
	2009		2008		2009		2008
	Millions of Dollars
Net Income Attributable to ConocoPhillips*	$	31		162		154		299
*Includes DCP Midstream-related earnings:	$	12		137		102		255
	Dollars Per Barrel
Average Sales Prices
U.S. natural gas liquids*
Consolidated	$	29.99		68.21		28.01		64.15
Equity affiliates		26.02		62.53		24.94		59.51
*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		188		196		180		197
Natural gas liquids fractionated**		174		162		167		158

*	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.

Earnings from the Midstream segment decreased 81 percent and 48 percent in the second quarter and first six months of 2009. The decrease in both periods was primarily due to lower prices and volumes experienced by equity affiliates DCP Midstream and Phoenix Park Gas Processors Limited. In addition, as a result of a DCP Midstream subsidiary converting subordinated units to common units, we recognized an $88 million after-tax benefit in the first quarter of 2009.

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R&M

	Three Months Ended					Six Months Ended
	June 30					June 30
	2009			2008		2009		2008
	Millions of Dollars
Net Income (Loss) Attributable to ConocoPhillips
United States	$	(38	)		587		60		1,022
International		(14	)		77		93		162
	$	(52	)		664		153		1,184
	Dollars Per Gallon
U.S. Average Sales Prices*
Gasoline
Wholesale	$	1.84			3.23		1.62		2.89
Retail		1.80			3.36		1.39		3.01
Distillates—wholesale		1.67			3.73		1.54		3.33
*Excludes excise taxes.
	Thousands of Barrels Daily
Operating Statistics
Refining operations*
United States
Crude oil capacity		1,986			2,008		1,986		2,008
Crude oil processed		1,852			1,891		1,721		1,848
Capacity utilization (percent)		93	%		94		87		92
Refinery production		2,018			2,095		1,868		2,043
International
Crude oil capacity		671			670		671		670
Crude oil processed		485			589		526		583
Capacity utilization (percent)		72	%		88		78		87
Refinery production		499			592		537		583
Worldwide
Crude oil capacity		2,657			2,678		2,657		2,678
Crude oil processed		2,337			2,480		2,247		2,431
Capacity utilization (percent)		88	%		93		85		91
Refinery production		2,517			2,687		2,405		2,626
*Includes our share of equity affiliates, except LUKOIL, which is reported in the LUKOIL Investment segment.
Petroleum products sales volumes
United States
Gasoline		1,180			1,127		1,109		1,098
Distillates		924			912		837		890
Other products		378			404		353		394
		2,482			2,443		2,299		2,382
International		630			683		619		650
		3,112			3,126		2,918		3,032

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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 fuel); 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.

R&M reported a loss of $52 million during the second quarter of 2009, compared with earnings of $664 million in the same period of 2008. R&M’s earnings for the first six months of 2009 and 2008 were $153 million and $1,184 million, respectively. U.S. and International R&M earnings decreased in both periods primarily due to lower refining margins and lower volumes, partially offset by lower operating expenses. Other factors influencing U.S. R&M results in both periods included a second-quarter 2009 $72 million noncash after-tax impairment primarily related to goodwill allocated to the planned sale of our investment in the Keystone Pipeline. U.S. results for the six-month period were also impacted by the absence of 2008 gains on asset sales.

U.S. R&M
In the second quarter of 2009, our U.S. R&M operations reported a loss of $38 million, compared with earnings of $587 million in the same period of 2008. Earnings for the first six months of 2009 and 2008 were $60 million and $1,022 million, respectively.

Our U.S. refining capacity utilization rate was 93 percent in the second quarter of 2009, compared with 94 percent in the same quarter of 2008. The current-year rate was mainly affected by run reductions due to market impacts.

International R&M
International R&M reported a loss of $14 million in the second quarter of 2009 and earnings of $93 million in the first six months of 2009. This compares with earnings of $77 million and $162 million for the corresponding periods of 2008.

Our international refining capacity utilization rate was 72 percent in the second quarter of 2009, compared with 88 percent in the same quarter of 2008. The current-year rate reflects increased turnaround activity in Europe and run reductions at the Wilhelmshaven, Germany, refinery in response to current market conditions.

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LUKOIL Investment

	Millions of Dollars
	Three Months Ended				Six Months Ended
	June 30				June 30
	2009		2008		2009		2008
Net Income Attributable to ConocoPhillips	$	682		774		730		1,484
Operating Statistics*
Net crude oil produced (thousands of barrels daily)		396		387		391		390
Net natural gas produced (millions of cubic feet daily)		274		363		295		383
Net refinery crude oil processed (thousands of barrels daily)		281		215		242		218

*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 June 30, 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.

Earnings from the LUKOIL Investment segment decreased 12 percent in the second quarter of 2009 and 51 percent in the first six months of 2009. The segment’s results were impacted by substantially lower refined product and crude oil prices, somewhat offset by lower extraction tax and export tariff rates. Results for both periods included a second-quarter 2009 $192 million positive alignment of first-quarter estimated earnings to LUKOIL’s reported results, compared with a $120 million negative alignment in the second quarter of 2008.

Chemicals

	Millions of Dollars
	Three Months Ended				Six Months Ended
	June 30				June 30
	2009		2008		2009		2008
Net Income Attributable to ConocoPhillips	$	67		18		90		70

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.

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Earnings from the Chemicals segment were $67 million in the second quarter of 2009, compared with $18 million in the second quarter of 2008. Chemicals earnings were $90 million in the first half of 2009, compared with $70 million in 2008. The increase in both periods reflects lower utility and turnaround expenses, which were partially offset by lower margins.

Emerging Businesses

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
Net Income (Loss) Attributable to ConocoPhillips
Power	$	27			26			51			53
Other		(25	)		(18	)		(49	)		(33	)
	$	2			8			2			20

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.

Emerging Businesses segment earnings were $2 million in the second quarter of 2009, compared with $8 million in the same quarter of 2008. Earnings for the first six months of 2009 were $2 million, compared with $20 million in the six-month period of 2008. The decline in both periods was affected by higher technology development expenses. The six-month period was also impacted by lower domestic power results.

Corporate and Other

	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2009			2008			2009			2008
Net Income (Loss) Attributable to ConocoPhillips
Net interest	$	(175	)		(119	)		(365	)		(227	)
Corporate general and administrative expenses		(31	)		(68	)		(72	)		(112	)
Other		49			1			21			(26	)
	$	(157	)		(186	)		(416	)		(365	)

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 47 percent in the second quarter of 2009 and 61 percent in the first six months of 2009. The increase in both periods was primarily due to higher average debt levels and lower amounts of interest being capitalized, partially offset by lower interest rates. Corporate general and administrative expenses decreased 54 percent in the second quarter of 2009 and 36 percent in the first six months of 2009 due to decreased costs related to compensation plans and overhead. 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. The “Other” category reflects higher foreign currency transaction gains in both 2009 periods.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

	Millions of Dollars
	June 30			December 31
	2009			2008
Short-term debt	$	1,438			370
Total debt*	$	30,364			27,455
Total equity	$	60,007			56,265
Percent of total debt to capital**		34	%		33
Percent of floating-rate debt to total debt		14	%		37

*	Total debt includes short- 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 half of 2009, we issued $9 billion of long-term notes. During the first six months of 2009, available cash was primarily used to support our ongoing capital expenditures and investments program, repay commercial paper and other debt, pay dividends, and meet the funding requirements to FCCL Partnership. Total dividends paid on our common stock during the first six months were $1,393 million. During the first half of 2009, cash and cash equivalents increased $133 million to $888 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 six months of 2009, cash of $4,452 million was provided by operating activities, a 63 percent decrease from cash from operations of $12,021 million in the corresponding period of 2008. The decline was primarily due to significantly lower commodity prices and lower refining margins.

While the stability of our cash flows from operating activities benefits from geographic diversity and the effects of upstream and downstream integration, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, natural gas and natural gas liquids, as well as refining and marketing margins. During the first six months of 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.

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, and new discoveries

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through exploratory success and their timely and cost-effective development. 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 six months of 2009 were $232 million, compared with $441 million in the same period of 2008. In January of 2009, we closed on the sale of a large part of our remaining 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 June 30, 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 June 30, 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, $2,211 million of commercial paper was outstanding at June 30, 2009, compared with $6,933 million at December 31, 2008.

At June 30, 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 $2,211 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 $4.8 billion in borrowing capacity under our revolving credit facility at June 30, 2009.

In July 2009, we arranged a new $500 million credit facility, which expires in July 2012, bringing our total borrowing capacity under our revolving credit facilities to $7.85 billion.

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 SEC shelf registration, in 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. In addition, in May 2009, we issued $1.5 billion of 4.60% Notes due 2015, $1.0 billion of 6.00% Notes due 2020 and $500 million of 6.50% Notes due 2039. The proceeds from these notes were primarily used to reduce outstanding commercial paper balances and for general corporate purposes.

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

Noncontrolling Interests
At June 30, 2009, we had $1,078 million of equity in less than wholly owned consolidated subsidiaries held by noncontrolling interest owners, including a noncontrolling interest of $491 million in Ashford Energy

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Capital S.A. The remaining noncontrolling interest amounts were primarily related to operating joint ventures we control. The largest of these, amounting to $560 million, was related to Darwin liquefied natural gas (LNG) operations, located in Australia’s Northern Territory. On July 15, 2009, Ashford agreed to redeem for $500 million, plus accrued dividends, the investment in Ashford held by Cold Spring Finance S.a.r.l. The redemption resulted indirectly in ConocoPhillips increasing its issuance of commercial paper in July.

Off-Balance Sheet Arrangements

As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. At June 30, 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 June 30, 2009, Qatargas 3 had approximately $3.5 billion outstanding under all the loan facilities, of which ConocoPhillips provided $956 million, and an additional $82 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. 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 June 30, 2009, Rockies Express had $1,883 million outstanding under the credit facilities, with our 24 percent guarantee equaling $452 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 of the $2 billion credit facility is expected to 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.

• Keystone Oil Pipeline: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 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 $90 million at June 30, 2009, 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 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 current 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) at June 30, 2009, 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 its 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. Keystone’s other owner will guarantee a similar, but separate, funding vehicle. At June 30, 2009, $197 million was outstanding under the Keystone commercial paper program guaranteed by us.

In October 2008, we elected to exercise an option to reduce our equity interest in Keystone from 50 percent to 20.01 percent through a dilution mechanism. At June 30, 2009, our ownership interest was approximately 23 percent. In June 2009, we signed an agreement to sell our remaining ownership interest in Keystone to TransCanada. Upon the closing of this transaction, currently expected in the third quarter, all our guarantees related to Keystone will cease.

For additional information about guarantees, see Note 11—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.

During the first six months of 2009, we used proceeds from the issuance of commercial paper to redeem $284 million of 6.375% Notes and $950 million of Floating Rate Notes upon their maturity. Our debt balance at June 30, 2009, was $30.4 billion, an increase of $2.9 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 $642 million was short-term and was included in the “Accounts payable—related parties” line on our June 30, 2009, consolidated balance sheet. The principal portion of these payments, which totaled $309 million in the first six 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 June 30, 2009, we had provided $956 million in loan financing, and an additional $82 million of accrued interest. See the “Off-Balance Sheet Arrangements” section for additional information on Qatargas 3.

We have provided intermittent short-term loan financing to WRB Refining LLC, to assist it in meeting its operating and capital spending requirements. At June 30, 2009, $150 million of such financing was outstanding.

Capital Spending

Capital Expenditures and Investments

	Millions of Dollars
	Six Months Ended
	June 30
	2009		2008
E&P
United States—Alaska	$	481		890
United States—Lower 48		1,451		1,735
International		2,503		2,999
		4,435		5,624
Midstream		4		-
R&M
United States		826		677
International		193		196
		1,019		873
LUKOIL Investment		-		-
Chemicals		-		-
Emerging Businesses		73		112
Corporate and Other		47		111
	$	5,578		6,720
United States	$	2,819		3,413
International		2,759		3,307
	$	5,578		6,720

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E&P
Capital spending for E&P during the first six months of 2009 totaled $4,435 million. 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) and the Cook Inlet Area; and exploration.

• 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, and various southern and central 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.

R&M
Capital spending for R&M during the first six months of 2009 totaled $1,019 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 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.

• Design activities toward the upgrade of the Wilhelmshaven Refinery.

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

Contingencies

Legal and Tax Matters
We accrue a liability for known contingencies (other than those related to income taxes) when a loss is probable and the amounts can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. In the case of income-tax-related contingencies, we use 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.

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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 June 30, 2009, we had resolved and closed one of these sites, leaving 64 unresolved sites where we have been notified of potential liability.

At June 30, 2009, our balance sheet included a total environmental accrual of $972 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.

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 emission 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 do 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 June 2009, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 166, “Accounting for Transfers of Financial Assets, an amendment of FASB Statement No. 140.” This Statement removes the concept of a qualifying special purpose entity (SPE) from SFAS No. 140 and the exception for qualifying SPEs from the consolidation guidance of FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities” (FIN 46(R)). Additionally, the Statement clarifies the requirements for financial asset transfers eligible for sale accounting. This Statement is effective January 1, 2010, and we do not expect any significant impact to our consolidated financial statements.

Also in June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R),” which amends FIN 46(R) to address the effects of the elimination of the qualifying SPE concept in SFAS No. 166, and other concerns about the application of key provisions of
FIN 46(R). More specifically, SFAS No. 167 requires a qualitative rather than a quantitative approach to determine the primary beneficiary of a variable interest entity (VIE), it amends certain guidance pertaining to the determination of the primary beneficiary when related parties are involved, and it amends certain guidance for determining whether an entity is a VIE. Additionally, this Statement requires continuous assessments of whether an enterprise is the primary beneficiary of a VIE. This Statement is effective January 1, 2010. We are currently evaluating the impact on our consolidated financial statements.

The FASB issued SFAS No. 168, “The FASB Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement 162,” in late June 2009. The FASB

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Accounting Standards Codification will become the source of authoritative U.S. generally accepted accounting principles (GAAP) and will supersede all then-existing non-SEC accounting and reporting standards on the effective date, September 15, 2009. The Codification will not change GAAP, but consolidates it into a logical and consistent structure. We will be required to revise our references to GAAP in our financial statements beginning with the third quarter of 2009.

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 SFAS No. 157, “Fair Value Measurements.” This FSP is effective for annual financial statements beginning with the 2009 fiscal year, but will not impact our consolidated financial statements, other than requiring additional disclosures.

OUTLOOK

In July 2009, we signed the Shah Gas Field Joint Venture and Field Entry agreements with the Abu Dhabi National Oil Company to progress the Shah Gas Field project. A final investment decision is expected in 2010, and we hold a 40 percent interest in the proposed project.

In June 2009, we signed project agreements allowing for the joint exploration and development of the Nursultan Block (N Block) located offshore Kazakhstan. We have a 24.5 percent interest in the project.

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 U.S. 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 decision required the five-year leasing program be vacated and remanded to DOI for reconsideration, but the decision is not effective until issuance of a mandate by the Court. On July 28, 2009, in response to petitions for rehearing by the DOI and the American Petroleum Institute, the Court issued an order that stays issuance of the mandate until DOI completes its reconsideration on remand, and also clarifies that its decision only applies to areas offshore Alaska. We are evaluating what, if any, impact this proceeding may have on leases we acquired under the leasing program.

In E&P, we expect our full-year 2009 production to be up slightly, compared with 2008. However, over the next two quarters, we expect that some of the year-to-date production gains achieved through the first half of 2009 will be partly offset, primarily due to normal seasonal maintenance activities and the impacts of reduced natural gas drilling activity in North America.

In R&M, we expect our crude oil capacity utilization rate for the full year of 2009 to be in the mid-80-percent range, as a result of planned maintenance at several facilities and the potential for ongoing weak margins.

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

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

We based the forward-looking statements 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 six months ended June 30, 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 June 30, 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 June 30, 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 second quarter of 2009 and any material developments with respect to matters previously reported in ConocoPhillips’ 2008 Annual Report on Form 10-K or first-quarter 2009 Quarterly Report on Form 10-Q.  While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position.  Nevertheless, such proceedings are reported pursuant to the U.S. Securities and Exchange Commission’s (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
In April 2009, the Borger Refinery received a Proposed Agreed Order and Penalty demand from the Texas Commission on Environmental Quality (TCEQ) pertaining primarily to several allegations of emission-limit exceedances, permit deviations and the failure to provide notification of air authorization under Texas regulations for several remediation projects. We and TCEQ settled this matter on July 10, 2009, with a penalty payment of $128,010, a Supplemental Environmental Project contribution of $128,010, and our written commitment to implement previously-planned operational improvements.

Matters Previously Reported
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 parties have agreed to settle this dispute with a penalty payment of $96,400.

On June 2, 2008, the Billings Refinery received a Violation Letter from the Montana Department of Environmental Quality (MDEQ) for alleged 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. We paid a penalty of $351,500 in May 2009 to fully resolve this matter.

On July 16, 2008, we received a demand from the Bay Area Air Quality Management District (BAAQMD) to settle 24 Notices of Violation (NOVs) issued in late 2006 and 2007 for alleged violations of air pollution control regulations at the San Francisco Refinery. During the remainder of 2008 and the first half of 2009, the BAAQMD proposed additional penalties for several other previously-issued NOVs as part of its settlement demand. We and BAAQMD have reached an agreement to settle these NOVs for $659,500. We paid $629,500 and the parties have agreed that the remaining payment of $30,000 will be made upon approval of a permit modification that addresses self-inspections at the refinery’s wastewater treatment plant.

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The South Coast Air Quality Management District (SCAQMD) conducted an audit of the Los Angeles Refinery in August 2008 to assess compliance with applicable local, state and federal regulations related to fugitive emissions. As a result of the audit, on August 28, 2008, SCAQMD issued five NOVs alleging noncompliance. SCAQMD assessed a penalty of $85,000 for three of the NOVs, which we have paid. On July 6, 2009, SCAQMD issued a demand to settle one of the two remaining NOVs, along with a demand to settle seven additional NOVs issued in 2008 and 2009 that allege violations of SCAQMD and other air pollution control regulations, for a total payment of $180,500. We are working with SCAQMD to resolve these NOVs.

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
April 1-30, 2009		2,839			$      40.19		-		$        -
May 1-31, 2009		2,604			45.96		-		-
June 1-30, 2009		-			-		-		-
Total		5,443			$      42.95		-

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

We held our annual stockholders meeting on May 13, 2009. A brief description of each proposal and the voting results follow:

A company proposal to elect 13 directors.

	Number of Shares
	Voted For		Voted Against		Abstain
Richard L. Armitage		1,231,518,390		67,893,047		7,168,226
Richard H. Auchinleck		1,235,302,264		63,730,495		7,546,903
James E. Copeland, Jr.		1,149,379,939		149,133,624		8,066,100
Kenneth M. Duberstein		1,209,062,594		89,848,414		7,668,656
Ruth R. Harkin		1,232,016,338		66,589,051		7,974,275
Harold W. McGraw III		1,164,993,391		133,495,166		8,091,007
James J. Mulva		1,218,431,165		81,311,412		6,836,986
Harald J. Norvik		1,186,254,764		112,992,116		7,332,784
William K. Reilly		1,215,695,672		82,711,791		8,172,200
Bobby S. Shackouls		1,231,488,330		67,053,202		8,038,130
Victoria J. Tschinkel		1,183,646,902		115,025,089		7,907,673
Kathryn C. Turner		1,211,802,700		87,185,473		7,591,390
William E. Wade, Jr.		1,212,903,687		85,365,297		8,310,580

Results of other matters submitted to a vote were:

	Number of Shares
	Voted For		Voted Against		Abstain		Broker Nonvotes
Ratification to Appoint Ernst & Young as ConocoPhillips’ Independent Registered Public Accounting Firm		1,223,259,717		79,431,004		3,889,341		-
Proposal to Approve the 2009 Omnibus Stock and
Performance Plan		984,312,575		119,499,295		5,323,025		197,445,167
Stockholder Proposal to Adopt Universal Health Care Principles		66,675,292		866,194,063		176,266,670		197,444,037
Stockholder Proposal for Advisory Vote on Executive Compensation		537,957,877		533,914,023		37,261,099		197,447,063
Stockholder Proposal on Political Contributions		262,237,633		695,747,761		151,149,730		197,444,938
Stockholder Proposal on Greenhouse Gas Reduction		257,294,253		680,873,616		170,960,633		197,451,560
Stockholder Proposal on Oil Sands Drilling		286,987,567		659,598,520		162,549,136		197,444,839

All 13 nominated directors were elected, the appointment of the independent auditors was ratified, and a management proposal providing for the 2009 Omnibus Stock and Performance Plan was approved. The five stockholder proposals presented were not approved.

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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.
101.INS	XBRL Instance Document
101.SCH	XBRL Schema Document
101.CAL	XBRL Calculation Linkbase Document
101.DEF	XBRL Definition Linkbase Document
101.LAB	XBRL Labels Linkbase Document
101.PRE	XBRL Presentation Linkbase Document

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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)

August 4, 2009

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