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

(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

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

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.

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.

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.

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.

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.

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

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.

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

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.

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.”

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.

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.

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.

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

$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.

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.

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

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.

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	)

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	)

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.

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

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.

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.

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

		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.

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.

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

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.

		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

		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.

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.

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.

Supplementary Information—Condensed Consolidating Financial Information

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

	•		ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).
	•		All other nonguarantor subsidiaries of ConocoPhillips.
	•		The consolidating adjustments necessary to present ConocoPhillips’ results on a consolidated basis.

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

		Millions of Dollars
		Three Months Ended 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