Edgar Filing: CONOCOPHILLIPS

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2012

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

For the transition period from to

Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

Delaware

01-0562944

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)


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

281-293-1000

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant 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.

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

The registrant had 1,264,556,506 shares of common stock, $.01 par value, outstanding at March 31, 2012.

CONOCOPHILLIPS

TABLE OF CONTENTS


	Page
Part I—Financial Information

Item 1. Financial Statements
Consolidated Income Statement		1
Consolidated Statement of Comprehensive Income		2
Consolidated Balance Sheet		3
Consolidated Statement of Cash Flows		4
Notes to Consolidated Financial Statements		5
Supplementary Information—Condensed Consolidating Financial Information		27

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		31

Item 3. Quantitative and Qualitative Disclosures About Market Risk		50

Item 4. Controls and Procedures		50

Part II—Other Information

Item 1. Legal Proceedings		51

Item 1A. Risk Factors		52

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		52

Item 6. Exhibits		53

Signature		54

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS


Consolidated Income Statement			ConocoPhillips


	Millions of Dollars
	Three Months Ended March 31
	2012			2011

Revenues and Other Income
Sales and other operating revenues*	$	56,132			56,530
Equity in earnings of affiliates		1,220			1,017
Gain on dispositions		942			616
Other income		60			84

Total Revenues and Other Income		58,354			58,247

Costs and Expenses
Purchased crude oil, natural gas and products		41,889			42,376
Production and operating expenses		2,696			2,628
Selling, general and administrative expenses		685			499
Exploration expenses		679			176
Depreciation, depletion and amortization		1,838			2,070
Impairments		259			—
Taxes other than income taxes*		4,521			4,364
Accretion on discounted liabilities		114			112
Interest and debt expense		209			262
Foreign currency transaction (gains) losses		(11	)		(36	)

Total Costs and Expenses		52,879			52,451

Income before income taxes		5,475			5,796
Provision for income taxes		2,520			2,754

Net income		2,955			3,042
Less: net income attributable to noncontrolling interests		(18	)		(14	)

Net Income Attributable to ConocoPhillips	$	2,937			3,028


Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic	$	2.29			2.11
Diluted		2.27			2.09


Dividends Paid Per Share of Common Stock (dollars)	$	.66			.66


Average Common Shares Outstanding (in thousands)
Basic		1,283,493			1,432,285
Diluted		1,293,104			1,445,477

*Includes excise taxes on petroleum products sales:	$	*3,321*			3,382

See Notes to Consolidated Financial Statements.


Consolidated Statement of Comprehensive Income			ConocoPhillips


	Millions of Dollars
	Three Months Ended March 31
	2012			2011

Net Income	$	2,955			3,042

Other comprehensive income
Defined benefit plans
Prior service cost arising during the period		—			—
Reclassification adjustment for amortization of prior service credit included in net income		(1	)		—

Net change		(1	)		—

Net actuarial loss arising during the period		—			—
Reclassification adjustment for amortization of prior net losses included in net income		78			51

Net change		78			51
Nonsponsored plans*		3			6
Income taxes on defined benefit plans		(29	)		(20	)

Defined benefit plans, net of tax		51			37

Unrealized holding gain on securities**		—			8
Reclassification adjustment for gain included in net income		—			(255	)
Income taxes on unrealized holding gain on securities		—			89

Unrealized gain on securities, net of tax		—			(158	)

Foreign currency translation adjustments		852			914
Reclassification adjustment for gain included in net income		1			—
Income taxes on foreign currency translation adjustments		(19	)		(20	)

Foreign currency translation adjustments, net of tax		834			894

Hedging activities		1			1
Income taxes on hedging activities		—			—

Hedging activities, net of tax		1			1

Other Comprehensive Income, Net of Tax		886			774

Comprehensive Income		3,841			3,816
Less: comprehensive income attributable to noncontrolling interests		(18	)		(14	)

Comprehensive Income Attributable to ConocoPhillips	$	3,823			3,802

*Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates.

**Available-for-sale securities of LUKOIL.

See Notes to Consolidated Financial Statements.


Consolidated Balance Sheet			ConocoPhillips


	Millions of Dollars
	March 31			December 31
	2012			2011

Assets
Cash and cash equivalents	$	3,707			5,780
Short-term investments*		508			581
Restricted cash		6,050			—
Accounts and notes receivable (net of allowance of $52 million in 2012 and $30 million in 2011)		15,575			14,648
Accounts and notes receivable—related parties		1,908			1,878
Inventories		6,072			4,631
Prepaid expenses and other current assets		3,246			2,700

Total Current Assets		37,066			30,218
Investments and long-term receivables		33,574			32,108
Loans and advances—related parties		1,615			1,675
Net properties, plants and equipment		85,559			84,180
Goodwill		3,330			3,332
Intangibles		742			745
Other assets		995			972

Total Assets	$	162,881			153,230


Liabilities
Accounts payable	$	19,637			17,973
Accounts payable—related parties		1,913			1,680
Short-term debt		7,002			1,013
Accrued income and other taxes		4,751			4,220
Employee benefit obligations		700			1,111
Other accruals		2,427			2,071

Total Current Liabilities		36,430			28,068
Long-term debt		21,358			21,610
Asset retirement obligations and accrued environmental costs		9,073			9,329
Joint venture acquisition obligation—related party		3,393			3,582
Deferred income taxes		18,709			18,055
Employee benefit obligations		4,033			4,068
Other liabilities and deferred credits		2,842			2,784

Total Liabilities		95,838			87,496


Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2012—1,753,755,416 shares; 2011—1,749,550,587 shares)
Par value		18			17
Capital in excess of par		44,936			44,725
Treasury stock (at cost: 2012—489,198,910 shares; 2011—463,880,628 shares)		(33,678	)		(31,787	)
Accumulated other comprehensive income		3,972			3,086
Unearned employee compensation		—			(11	)
Retained earnings		51,286			49,194

Total Common Stockholders’ Equity		66,534			65,224
Noncontrolling interests		509			510

Total Equity		67,043			65,734

Total Liabilities and Equity	$	162,881			153,230

*Includes marketable securities of:	$	*407*			232

See Notes to Consolidated Financial Statements.


Consolidated Statement of Cash Flows			ConocoPhillips


	Millions of Dollars
	Three Months Ended March 31
	2012			2011

Cash Flows From Operating Activities
Net income	$	2,955			3,042
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		1,838			2,070
Impairments		259			—
Dry hole costs and leasehold impairments		518			50
Accretion on discounted liabilities		114			112
Deferred taxes		258			87
Undistributed equity earnings		(423	)		(523	)
Gain on dispositions		(942	)		(616	)
Other		(404	)		(185	)
Working capital adjustments
Decrease (increase) in accounts and notes receivable		(913	)		(681	)
Decrease (increase) in inventories		(1,402	)		(2,669	)
Decrease (increase) in prepaid expenses and other current assets		(67	)		(546	)
Increase (decrease) in accounts payable		1,859			1,753
Increase (decrease) in taxes and other accruals		532			53

Net Cash Provided by Operating Activities		4,182			1,947


Cash Flows From Investing Activities
Capital expenditures and investments		(4,260	)		(2,884	)
Proceeds from asset dispositions		1,109			1,787
Net sales (purchases) of short-term investments		92			(1,170	)
Long-term advances/loans—related parties		4			4
Collection of advances/loans—related parties		38			40
Other		7			12

Net Cash Used in Investing Activities		(3,010	)		(2,211	)


Cash Flows From Financing Activities
Issuance of debt		5,794			—
Repayment of debt		(54	)		(373	)
Change in restricted cash		(6,050	)		—
Issuance of company common stock		36			75
Repurchase of company common stock		(1,899	)		(1,636	)
Dividends paid on company common stock		(843	)		(944	)
Other		(254	)		(183	)

Net Cash Used in Financing Activities		(3,270	)		(3,061	)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		25			43


Net Change in Cash and Cash Equivalents		(2,073	)		(3,282	)
Cash and cash equivalents at beginning of period		5,780			9,454

Cash and Cash Equivalents at End of Period	$	3,707			6,172

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. Certain notes and other information have been condensed or omitted from the interim financial statements included in this report. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and notes included in our 2011 Annual Report on Form 10-K.

Note 2—Variable Interest Entities (VIEs)

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

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. Freeport LNG began making loan repayments in September 2008, and the loan balance outstanding was $602 million at March 31, 2012, and $612 million at December 31, 2011. 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.

Note 3—Inventories

Inventories consisted of the following:


	Millions of Dollars
	March 31 2012		December 31 2011

Crude oil and petroleum products	$	5,071		3,633
Materials, supplies and other		1,001		998

	$	6,072		4,631

Inventories valued on the last-in, first-out (LIFO) basis totaled $4,789 million and $3,387 million at March 31, 2012, and December 31, 2011, respectively. The estimated excess of current replacement cost over LIFO cost of inventories amounted to approximately $9,500 million and $8,400 million at March 31, 2012, and December 31, 2011, respectively.

Note 4—Assets Held for Sale or Sold

In March 2012, we sold our Vietnam Exploration and Production (E&P) business for $1,100 million, including customary working capital adjustments, and recognized a gain of $937 million before-tax, which was included in the “Gain on dispositions” line on the consolidated income statement. The business had a net carrying value of approximately $163 million, which included $352 million of properties, plants and equipment (PP&E), $69 million of asset retirement obligations and $145 million of deferred income taxes.

In January 2012, we entered into an agreement to sell our interest in the Statfjord Field and associated satellites, all of which are located in the North Sea and included in our E&P segment. The sale is expected to be completed in the second quarter of 2012. Accordingly, on our consolidated balance sheet as of March 31, 2012, we reclassified $199 million of PP&E to “Prepaid expenses and other current assets,” $446 million of asset retirement obligations to “Other accruals,” and $322 million of noncurrent deferred income tax assets as current, based on their held for sale status.

Note 5—Investments, Loans and Long-Term Receivables

Australia Pacific LNG

In January 2012, Australia Pacific LNG (APLNG) and China Petrochemical Corporation (Sinopec) signed an amendment to their existing LNG sales agreement for the sale and purchase of an additional 3.3 million tonnes of LNG per year through 2035. This agreement, in combination with the binding Heads of Agreement with Kansai Electric Power Co. Inc., signed in November 2011, finalizes the marketing of the second train. In conjunction with the LNG sales agreement, the parties have also agreed for Sinopec to subscribe for additional shares in APLNG, which upon completion will raise its equity interest from 15 percent to 25 percent. As a result, both our ownership interest and Origin Energy’s ownership interest would dilute from 42.5 percent to 37.5 percent. The Subscription Agreement is subject to customary governmental approvals and, along with the amendment to the sales agreement, is conditional on a final investment decision on the second train, which is expected in the second quarter of 2012. We expect to record a loss of approximately $135 million after-tax from the dilution in the second quarter of 2012.

Loans and Long-Term Receivables

As part of our normal ongoing business operations and consistent with industry practice, we enter into numerous agreements with other parties to pursue business opportunities. Included in such activity are loans made to certain affiliated and non-affiliated companies. Significant loans to affiliated companies at March 31, 2012, included the following:

•

$602 million in loan financing to Freeport LNG.

•

$1,131 million in project financing to Qatar Liquefied Gas Company Limited (3) (QG3).

The long-term portion of these loans is 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.”

Long-term receivables from non-affiliated companies are included in the “Investments and long-term receivables” line on the consolidated balance sheet, while the short-term portion related to non-affiliate loans is in “Accounts and notes receivable.”

Other

We have investments remeasured at fair value on a recurring basis to support certain nonqualified deferred compensation plans. The fair value of these assets at March 31, 2012, was $352 million, and at December 31, 2011, was $336 million. The entire value is categorized in Level 1 of the fair value hierarchy. These investments are measured at fair value using a market approach based on quotations from national securities exchanges.

Merey Sweeny, L.P. (MSLP) owns a delayed coker and related facilities at the Sweeny Refinery. MSLP processes our long residue, which is produced from heavy sour crude oil, for a processing fee. Fuel-grade petroleum coke is produced as a by-product and becomes the property of MSLP. Prior to August 28, 2009, MSLP was owned 50/50 by us and Petróleos de Venezuela S.A. (PDVSA). Under the agreements that govern the relationships between the partners, certain defaults by PDVSA with respect to supply of crude oil to the Sweeny Refinery gave us the right to acquire PDVSA’s 50 percent ownership interest in MSLP, which we exercised on August 28, 2009. PDVSA has initiated arbitration with the International Chamber of Commerce challenging the exercise of the call right and claiming it was invalid. The arbitral tribunal is scheduled to hold hearings on the merits of the dispute in December 2012. We continue to use the equity method of accounting for our investment in MSLP.

Note 6—Properties, Plants and Equipment

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

		$00000000		$00000000		$00000000		$00000000		$00000000		$00000000
	Millions of Dollars
	March 31, 2012						December 31, 2011
	Gross PP&E		Accum. DD&A		Net PP&E		Gross PP&E		Accum. DD&A		Net PP&E

Exploration and Production (E&P)	$	125,827		55,990		69,837		124,111		55,565		68,546
Midstream		134		85		49		135		86		49
Refining and Marketing (R&M)		22,364		8,329		14,035		22,096		8,128		13,968
LUKOIL Investment		—		—		—		—		—		—
Chemicals		—		—		—		—		—		—
Emerging Businesses		1,063		240		823		1,023		220		803
Corporate and Other		1,865		1,050		815		1,844		1,030		814

	$	151,253		65,694		85,559		149,209		65,029		84,180

Note 7—Suspended Wells

The capitalized cost of suspended wells at March 31, 2012, was $1,008 million, a decrease of $29 million from $1,037 million at year-end 2011. For the category of exploratory well costs capitalized for a period greater than one year as of December 31, 2011, no wells were charged to dry hole expense during the first three months of 2012.

Note 8—Impairments

During the three-month periods of 2012 and 2011, we recognized the following before-tax impairment charges:


	Millions of Dollars
	Three Months Ended March 31
	2012		2011

E&P
United States	$	2		—
International		214		—
R&M
United States		1		—
International		42		—

	$	259		—

In the first quarter of 2012, we recorded a $213 million property impairment in our E&P segment for the carrying value of capitalized project development costs associated with our Mackenzie Gas Project. Advancement of the project was suspended indefinitely in the first quarter of 2012 due to a continued decline in market conditions and the lack of acceptable commercial terms. In addition, we recorded a $481 million impairment for the undeveloped leasehold costs associated with the project. The leasehold impairment was included in the “Exploration expenses” line on our consolidated income statement. We also recorded a $42 million impairment in our R&M segment related to equipment formerly associated with the canceled Wilhelmshaven Refinery upgrade project.

Note 9—Debt

We have two commercial paper programs supported by our $8.0 billion revolving credit facilities: the ConocoPhillips $6.35 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, which is used to fund commitments relating to the QG3 Project. Commercial paper maturities are generally limited to 90 days.

At both March 31, 2012, and December 31, 2011, we had no direct outstanding borrowings under our revolving credit facilities, but $26 million in letters of credit had been issued as of March 31, 2012, and $40 million as of December 31, 2011. In addition, under the two commercial paper programs, there was $1,097 million of commercial paper outstanding at March 31, 2012, compared with $1,128 million at December 31, 2011. Since we had $1,097 million of commercial paper outstanding and had issued $26 million of letters of credit, we had access to $6.9 billion in borrowing capacity under our revolving credit facilities at March 31, 2012.

At March 31, 2012, we classified $1,010 million of short-term debt as long-term debt, based on our ability and intent to refinance the obligation on a long-term basis under our revolving credit facilities.

In anticipation of the separation of our downstream businesses into Phillips 66 (see Note 21—Planned Separation of Downstream Businesses, for additional information), in March 2012, Phillips 66 issued, through a private placement, the following Senior Notes. The Notes are fully and unconditionally guaranteed by Phillips 66 Company, a 100 percent owned subsidiary. These Notes are classified as short-term debt on the consolidated balance sheet as, under the terms of the Notes, they must be redeemed within one year unless retained by Phillips 66 in the separation.

•

$800 million aggregate principal amount at 1.950% due 2015.

•

$1.5 billion aggregate principal amount at 2.950% due 2017.

•

$2.0 billion aggregate principal amount at 4.300% due 2022.

•

$1.5 billion aggregate principal amount at 5.875% due 2042.

As of March 31, 2012, the net proceeds from this offering were deposited in two segregated escrow accounts for the benefit of the holders of the Notes. These funds were restricted as to withdrawal or usage pending a written notice from Phillips 66 to the escrow agents that, among other items, the contribution to Phillips 66 of the downstream business of ConocoPhillips, in connection with the separation from ConocoPhillips, has been consummated in all material respects. Accordingly, these funds, along with approximately $290 million of funds sufficient to pay a mandatory redemption price plus accrued interest to the note holders should the separation not occur, are included in the “Restricted cash” line on our consolidated balance sheet as of March 31, 2012.

Note 10—Joint Venture Acquisition Obligation

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began 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 $742 million was short-term and was included in the “Accounts payable—related parties” line on our March 31, 2012, consolidated balance sheet. The principal portion of these payments, which totaled $180 million in the first three months of 2012, is included in the “Other” line in the financing activities section on 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—Noncontrolling Interests

Activity for the equity attributable to noncontrolling interests for the first three months of 2012 and 2011 was as follows:


	Millions of Dollars
	2012									2011
	Common Stockholders’ Equity			Non- Controlling Interest			Total Equity			Common Stockholders’ Equity			Non- Controlling Interest			Total Equity

Balance at January 1	$	65,224			510			65,734			68,562			547			69,109
Net income		2,937			18			2,955			3,028			14			3,042
Dividends		(843	)		—			(843	)		(944	)		—			(944	)
Repurchase of company common stock		(1,899	)		—			(1,899	)		(1,636	)		—			(1,636	)
Distributions to noncontrolling interests		—			(19	)		(19	)		—			(12	)		(12	)
Other changes, net*		1,115			—			1,115			962			—			962

Balance at March 31	$	66,534			509			67,043			69,972			549			70,521

*Includes components of other comprehensive income, which are disclosed separately in the Consolidated Statement of Comprehensive Income.

Note 12—Guarantees

At March 31, 2012, 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.

Guarantees of Joint Venture Debt

At March 31, 2012, we had guarantees outstanding for our portion of joint venture debt obligations, which have terms of up to 24 years. The maximum potential amount of future payments under the guarantees is approximately $120 million. Payment would be required if a joint venture defaults on its debt obligations.

Other Guarantees

•

In conjunction with our purchase of a 50 percent ownership interest in 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 5 to 20 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1,288 million ($2,879 million in the event of intentional or reckless breach) at March 2012 exchange rates based on our 42.5 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 co-venturers do not make necessary equity contributions into APLNG. Additionally, we have guaranteed the performance of APLNG with regard to certain contracts executed in connection with APLNG’s issuance of the Train 1 Notice to Proceed. Our maximum potential amount of future payments related to these guarantees is estimated to be $250 million at March 2012 exchange rates based on our 42.5 percent ownership in APLNG.

•

We have other guarantees with maximum future potential payment amounts totaling $500 million, which consist primarily of guarantees to fund the short-term cash liquidity deficits of certain joint ventures, a guarantee of minimum charter revenue for an LNG vessel, 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, guarantees of the residual value of leased corporate aircraft, and guarantees of the performance of a business partner or some of its customers. These guarantees generally extend up to 13 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 March 31, 2012, was $349 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 $207 million of environmental accruals for known contamination that are included in asset retirement obligations and accrued environmental costs at March 31, 2012. For additional information about environmental liabilities, see Note 13—Contingencies and Commitments.

Note 13—Contingencies and Commitments

A number of lawsuits involving a variety of claims have been made against ConocoPhillips that arise in the ordinary course of business. We also may be required 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 active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. 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 international, federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.

Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit and some of the indemnifications are subject to dollar and time limits.

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 in respect of sites acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. At March 31, 2012, our balance sheet included a total environmental accrual of $920 million, compared with $922 million at December 31, 2011. We expect to incur a substantial amount 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 that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, are required.

Other Contingencies

We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at March 31, 2012, we had performance obligations secured by letters of credit of $2,551 million (of which $26 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.

In 2007, we announced we had been unable to reach agreement with respect to our migration to an empresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, PDVSA, or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, we filed a request for international arbitration on November 2, 2007, with the World Bank’s International Centre for Settlement of Investment Disputes (ICSID). An arbitration hearing was held before an ICSID tribunal during the summer of 2010, and we are currently awaiting an interim decision on key legal and factual issues. A different arbitration hearing was held in January 2012 with the International Chamber of Commerce on ConocoPhillips’ separate claims against PDVSA for certain breaches of their Association Agreements prior to the expropriation.

In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before ICSID against The Republic of Ecuador, as a result of the newly enacted Windfall Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite a restraining order issued by ICSID, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the illegally seized crude oil. In 2009, Ecuador took over operations in Blocks 7 and 21, fully expropriating our assets. In June 2010, the ICSID tribunal concluded it has jurisdiction to hear the expropriation claim. An arbitration hearing on case merits occurred in March 2011, and we are awaiting a decision. On September 30, 2011, Ecuador filed a supplemental counterclaim asserting environmental damages, which we believe will not be material. The arbitration process is ongoing.

Note 14—Financial Instruments and Derivative Contracts

Financial Instruments

We invest excess cash in financial instruments with maturities based on our cash forecasts for the various currency pools we manage. The maturities of these investments may from time to time extend beyond 90 days. The types of financial instruments in which we currently invest include:

•

Time Deposits: Interest bearing deposits placed with approved financial institutions.

•

Commercial Paper: Unsecured promissory notes issued by a corporation, commercial bank, or government agency purchased at a discount, maturing at par.

•

Government or government agency obligations: Negotiable debt obligations issued by a government or government agency.

These financial instruments appear in the “Cash and cash equivalents” line on our consolidated balance sheet if the maturities at the time we made the investments were 90 days or less; otherwise, these held-to-maturity investments are included in the “Short-term investments” line. We held the following financial instruments:


	Millions of Dollars
	Carrying Amount
	Cash & Cash Equivalents				Short-Term Investments*
	March 31 2012		December 31 2011		March 31 2012		December 31 2011

Cash	$	1,066		1,169		—		—

Time Deposits
Remaining maturities from 1 to 90 days		2,209		4,318		101		349
Remaining maturities from 91 to 180 days		—		—		—		—
Commercial Paper
Remaining maturities from 1 to 90 days		96		293		407		232
Remaining maturities from 91 to 180 days		—		—		—		—
Government Obligations
Remaining maturities from 1 to 90 days		336		—		—		—
Remaining maturities from 91 to 180 days		—		—		—		—

	$	3,707		5,780		508		581

*Carrying value approximates fair value.

At March 31, 2012, we had $6,050 million of financial instruments designated as “Restricted cash” on our consolidated balance sheet, which represented the net funds received from a private bond offering by Phillips 66 issued in connection with its planned separation from ConocoPhillips, along with approximately $290 million of funds sufficient to pay a mandatory redemption price plus accrued interest to the note holders should the separation not occur. These amounts were deposited into two segregated escrow accounts for the benefit of the note holders and were restricted as to withdrawal and usage. At March 31, 2012, the funds in the escrow accounts were invested in U.S. Treasury Bills ($5,920 million) and U.S. Treasury Notes ($130 million), all with maturities within 30 days from March 31, 2012. For additional information, see Note 9—Debt.

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 capture market opportunities. Since we are not currently using cash flow 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 with fixed minimum notional volumes 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 eligible for and we elect the normal purchases and normal sales exception (i.e., contracts to purchase or sell quantities we expect to use or sell over a reasonable period in the normal course of business). We record most of our contracts to buy or sell natural gas and the majority of our contracts to sell power 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 sales 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-traded 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. Where exchange-provided prices are adjusted, non-exchange quotes are used, or when the instrument lacks sufficient liquidity, we generally classify those exchange-cleared contracts as Level 2. Over-the-counter (OTC) financial swaps and physical commodity forward purchase and sales 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 sales 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. A contract that is initially classified as Level 3 due to absence or insufficient corroboration of broker quotes over a material portion of the contract will transfer to Level 2 when the portion of the trade having no quotes or insufficient corroboration becomes an insignificant portion of the contract. A contract would also transfer to Level 2 if we began using a corroborated broker quote that has become available. Conversely, if a corroborated broker quote ceases to be available or used by us, the contract would transfer from Level 2 to Level 3. There were no material transfers in or out of 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
	March 31, 2012									December 31, 2011
	Level 1			Level 2		Level 3		Total		Level 1			Level 2		Level 3		Total

Assets
Commodity derivatives	$	3,344			2,009		66		5,419		2,807			1,947		72		4,826
Interest rate derivatives		—			27		—		27		—			31		—		31
Foreign currency exchange derivatives		—			22		—		22		—			13		—		13

Total assets		3,344			2,058		66		5,468		2,807			1,991		72		4,870


Liabilities
Commodity derivatives		3,620			1,826		6		5,452		2,970			1,722		10		4,702
Foreign currency exchange derivatives		—			7		—		7		—			23		—		23

Total liabilities		3,620			1,833		6		5,459		2,970			1,745		10		4,725

Net assets (liabilities)	$	(276	)		225		60		9		(163	)		246		62		145

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 right of setoff 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.

As reflected in the table above, Level 3 activity was not material.

Commodity Derivative Contracts—We operate in the worldwide crude oil, bitumen, refined product, natural gas, LNG, natural gas liquids and electric power markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect our revenues, as well as the cost of operating, investing and financing activities. Generally, our policy is to remain exposed to the market prices of commodities; however, we use futures, forwards, swaps and options in various markets to balance physical systems, meet customer needs, manage price exposures on specific transactions, and do a limited, immaterial amount of trading not directly related to our physical business. We also use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and blending commodities to capture quality upgrades. Derivatives may be used to optimize these activities which may move our risk profile away from market average prices.

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


	Millions of Dollars
	March 31 2012		December 31 2011

Assets
Prepaid expenses and other current assets	$	5,048		4,433
Other assets		399		415
Liabilities
Other accruals		5,047		4,350
Other liabilities and deferred credits		433		374

Hedge accounting has not been used for any item in the table. The amounts shown are presented gross (i.e., without netting assets and liabilities with the same counterparty where the right of setoff exists).

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


	Millions of Dollars
	Three Months Ended March 31
	2012			2011

Sales and other operating revenues*	$	(726	)		(1,027	)
Other income		2			(7	)
Purchased crude oil, natural gas and products*		576			321

Hedge

accounting has not been used for any items in the table.

*	2011 has been restated to eliminate certain non-derivative transactions and realign certain derivative transactions between sales and purchases.

The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts. These financial and physical derivative contracts are primarily used to manage price exposure on our underlying operations. The underlying exposures may be from non-derivative positions such as inventory volumes or firm natural gas transport contracts. Financial derivative contracts may also offset physical derivative contracts, such as forward sales contracts.


	Open Position Long / (Short)
	March 31 2012			December 31 2011

Commodity
Crude oil, refined products and natural gas liquids (millions of barrels)		(23	)		(13	)
Natural gas and power (billions of cubic feet equivalent)
Fixed price		(20	)		(57	)
Basis		50			(25	)

Interest Rate Derivative Contracts—During the second quarter of 2010, we executed interest rate swaps to synthetically convert $500 million of our 4.60% fixed-rate notes due in 2015 to a London Interbank Offered Rate (LIBOR)-based floating rate. These swaps qualify for and are designated as fair-value hedges using the short-cut method of hedge accounting. The short-cut method permits the assumption that changes in the value of the derivative perfectly offset changes in the value of the debt; therefore, no gain or loss has been recognized due to hedge ineffectiveness.

The adjustments to the fair values of the interest rate swaps and hedged debt have not been material.

Foreign Currency Exchange Derivatives—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, dividends, and cash returns from net investments in foreign affiliates to be remitted within the coming year.

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


	Millions of Dollars
	March 31 2012		December 31 2011

Assets
Prepaid expenses and other current assets	$	21		12
Other assets		1		1
Liabilities
Other accruals		6		23
Other liabilities and deferred credits		1		—

Hedge

accounting has not been used for any item in the table. The amounts shown are presented gross.

Gains and losses from foreign currency exchange derivatives, and the line item where they appear on our consolidated income statement were:


	Millions of Dollars
	Three Months Ended March 31
	2012			2011

Foreign exchange transaction (gains) losses	$	(66	)		3

Hedge

accounting has not been used for any item in the table.

We had the following net notional position of outstanding foreign currency exchange derivatives:

In Millions
Notional Currency⁽¹⁾

March 31
2012

December 31
2011

Foreign Currency Exchange Derivatives

Sell U.S. dollar, buy other currencies⁽²⁾

USD

2,064

1,949

Buy British pound, sell Canadian dollar

GBP

—

Buy euro, sell other currencies⁽³⁾

EUR

154

—

Sell euro, buy other currencies⁽⁴⁾

EUR

—

(1) Denominated in U.S. dollar, British pound and euro.

(2) Primarily euro, Canadian dollar, Norwegian krone and British pound.

(3) Primarily Canadian dollar and British pound.

(4) Primarily Canadian dollar and Norwegian krone.

Credit Risk

Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, OTC derivative contracts and trade receivables. Our cash equivalents and short-term investments are placed in high-quality commercial paper, money market funds, government debt securities and time deposits with major international banks and financial institutions.

The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. 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, swaps and option contracts that have a negligible credit risk because these trades are cleared with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.

Our trade receivables result primarily from our petroleum operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less, and we continually monitor this exposure and the creditworthiness of the counterparties. We do not generally require collateral to limit the exposure to loss; however, we will sometimes use letters of credit, prepayments, and master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due us.

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

The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on March 31, 2012, and December 31, 2011, was $249 million and $237 million, respectively, for which collateral of $4 million and $3 million, respectively, was posted. If our credit rating were lowered one level from its “A” rating (per Standard and Poor’s) on March 31, 2012, 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 $245 million of additional collateral, either with 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, cash equivalents, restricted cash and short-term investments: 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.

•

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 as a Level 2 fair value.

•

Fixed-rate 5.3 percent joint venture acquisition obligation: Fair value is estimated based on the net present value of the future cash flows as a Level 2 fair value, discounted at March 31, 2012, and December 31, 2011, effective yield rates of 0.97 percent and 1.24 percent, respectively, 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.

•

Commodity 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, fair value is 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 IntercontinentalExchange (ICE) Futures, or other traded exchanges.

•

Interest rate swap contracts: Fair value is estimated based on a pricing model and market observable interest rate swap curves obtained from a third-party market data provider.

•

Forward-exchange contracts: Fair values are estimated by comparing the contract rate to the forward rates in effect at the end of the respective reporting periods, and approximate the exit prices at those dates.

Our commodity derivative and financial instruments were:


	Millions of Dollars
	Carrying Amount				Fair Value
	March 31 2012		December 31 2011		March 31 2012		December 31 2011

Financial Assets
Foreign currency exchange derivatives	$	22		13		22		13
Interest rate derivatives		27		31		27		31
Commodity derivatives		781		814		781		814
Financial Liabilities
Total debt, excluding capital leases		28,331		22,592		32,496		27,065
Joint venture acquisition obligation		4,135		4,314		4,627		4,820
Foreign currency exchange derivatives		7		23		7		23
Commodity derivatives		444		446		444		446

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 setoff and intent to net exist). In addition, the March 31, 2012, commodity derivative assets and liabilities appear net of $21 million of obligations to return cash collateral and $391 million of rights to reclaim cash collateral, respectively. The December 31, 2011, commodity derivative assets and liabilities appear net of no obligations to return cash collateral and $244 million of rights to reclaim cash collateral. No collateral was deposited or held for the foreign currency derivatives or interest rate derivatives.

Note 15—Accumulated Other Comprehensive Income

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


	Millions of Dollars
	Defined Benefit Plans			Net Unrealized Gain on Securities		Foreign Currency Translation		Hedging			Accumulated Other Comprehensive Income

December 31, 2011	$	(1,971	)		—		5,063		(6	)		3,086
Other comprehensive income		51			—		834		1			886

March 31, 2012	$	(1,920	)		—		5,897		(5	)		3,972

Note 16—Cash Flow Information


	Millions of Dollars
	Three Months Ended March 31
	2012			2011

Cash Payments
Interest	$	291			286
Income taxes		1,462			2,722


Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased	$	(497	)		(2,101	)
Short-term investments sold		589			931

	$	92			(1,170	)

Note 17—Employee Benefit Plans

Pension and Postretirement Plans


	Millions of Dollars
	Pension Benefits												Other Benefits
	March 31												March 31
	2012						2011						2012			2011
Three Months Ended	U.S.			Int’l.			U.S.			Int’l.
Components of Net Periodic Benefit Cost
Service cost	$	58			28			64			24			2			3
Interest cost		63			43			62			44			10			10
Expected return on plan assets		(74	)		(43	)		(70	)		(43	)		—			—
Amortization of prior service cost (credit)		2			(2	)		2			—			(1	)		(2	)
Recognized net actuarial loss (gain)		59			18			41			11			(1	)		(1	)

Net periodic benefit cost	$	108			44			99			36			10			10

During the first three months of 2012, we contributed $114 million to our domestic benefit plans and $56 million to our international benefit plans.

Note 18—Related Party Transactions

Significant transactions with related parties were:


	Millions of Dollars
	Three Months Ended March 31
	2012		2011

Operating revenues and other income (a)	$	1,991		1,816
Purchases (b)		5,088		4,354
Operating expenses and selling, general and administrative expenses (c)		67		105
Net interest expense (d)		14		19

(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), and gas oil and hydrogen feedstocks were sold to Excel Paralubes. Natural gas, crude oil, blendstock and other intermediate products were sold to WRB Refining LP. In addition, we charged several of our affiliates, including CPChem and MSLP, for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.

(b)

We purchased refined products from WRB. We purchased natural gas and natural gas liquids from DCP Midstream and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchased 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 transportation fees to pipeline equity companies.

(d)	We paid and/or received interest to/from various affiliates, including FCCL Partnership. See Note 5—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

Note 19—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:

E&P—This segment primarily explores for, produces, transports and markets crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis.

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.

R&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia.

LUKOIL Investment—This segment represents our prior investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We completed the divestiture of our entire interest in LUKOIL in the first quarter of 2011.

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

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, short-term investments and restricted cash.

We evaluate performance and allocate resources based on net income attributable to ConocoPhillips. Intersegment sales are at prices that approximate market.

Analysis of Results by Operating Segment


	Millions of Dollars
	Three Months Ended March 31
	2012			2011

Sales and Other Operating Revenues
E&P
United States	$	7,514			7,755
International		7,221			7,920
Intersegment eliminations—U.S.		(2,028	)		(1,688	)
Intersegment eliminations—international		(2,192	)		(2,067	)

E&P		10,515			11,920

Midstream
Total sales		2,027			2,328
Intersegment eliminations		(114	)		(156	)

Midstream		1,913			2,172

R&M
United States		29,445			29,953
International		14,468			12,744
Intersegment eliminations—U.S.		(231	)		(265	)
Intersegment eliminations—international		(13	)		(13	)

R&M		43,669			42,419

LUKOIL Investment		—			—
Chemicals		3			3

Emerging Businesses
Total sales		208			156
Intersegment eliminations		(182	)		(145	)

Emerging Businesses		26			11

Corporate and Other		6			5

Consolidated sales and other operating revenues	$	56,132			56,530


Net Income Attributable to ConocoPhillips
E&P
United States	$	870			863
International		1,678			1,489

Total E&P		2,548			2,352

Midstream		93			73

R&M
United States		415			402
International		37			80

Total R&M		452			482

LUKOIL Investment		—			239
Chemicals		218			193
Emerging Businesses		(14	)		(7	)
Corporate and Other		(360	)		(304	)

Net income attributable to ConocoPhillips	$	2,937			3,028


	Millions of Dollars
	March 31 2012		December 31 2011

Total Assets
E&P
United States	$	37,505		37,150
International		66,854		64,752

Total E&P		104,359		101,902

Midstream		1,981		2,338

R&M
United States		26,073		24,976
International		10,600		8,061
Goodwill		3,330		3,332

Total R&M		40,003		36,369

LUKOIL Investment		—		—
Chemicals		3,312		2,999
Emerging Businesses		1,033		974
Corporate and Other		12,193		8,648

Consolidated total assets	$	162,881		153,230

Note 20—Income Taxes

Our effective tax rates for the first quarter of 2012 and 2011 were 46 percent and 48 percent, respectively. The change in the effective tax rate for the first quarter of 2012, versus the same period of 2011, was due to asset dispositions in 2012, offset in part by a higher proportion of income in higher tax rate jurisdictions and asset impairments in 2012. The effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.

Note 21—Planned Separation of Downstream Businesses

On April 4, 2012, our Board of Directors approved the separation of our downstream businesses into a stand-alone, publicly traded corporation via a tax-free distribution. The new downstream company, Phillips 66, will be headquartered in Houston, Texas, and will include our refining, marketing and transportation businesses, most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations included in our Emerging Businesses segment.

In accordance with a separation and distribution agreement, the two companies will be separated through a stock dividend distribution after the market closes on April 30, 2012. Each ConocoPhillips shareholder will receive one share of Phillips 66 stock for every two shares of ConocoPhillips stock held at the close of business on the record date of April 16, 2012. Fractional shares of Phillips 66 common stock will not be distributed, and any fractional shares of Phillips 66 common stock otherwise issuable to a ConocoPhillips shareholder will be sold in the open market on such shareholder’s behalf, and such shareholder will receive cash payment with respect to that fractional share.

In conjunction with the separation, we received a private letter ruling from the Internal Revenue Service to the effect that, based on certain facts, assumptions, representations and undertakings set forth in the ruling, for U.S. federal income tax purposes, the distribution of Phillips 66 stock is not taxable to ConocoPhillips or U.S. holders of ConocoPhillips common stock, except in respect of cash received in lieu of fractional share interests. Following the separation, ConocoPhillips will retain no ownership interest in Phillips 66, and each company will have separate public ownership, boards of directors and management. A registration statement on Form 10, as amended through the time of its effectiveness and describing the separation, was filed by Phillips 66 with the U.S. Securities and Exchange Commission and was declared effective on April 12, 2012. On May 1, 2012, Phillips 66 stock will begin trading the “regular-way” on the New York Stock Exchange under the “PSX” stock symbol.

Note 22—Subsequent Events

In late April, we and China National Offshore Oil Corp. (CNOOC) reached agreement with China’s State Oceanic Administration (SOA) to resolve outstanding claims related to the 2011 seepage incidents. Under the terms of the agreement, we agreed to pay $173 million to the SOA over the next two years. We also agreed to contribute $18 million by December 2014 toward social projects benefiting Bohai Bay. As a result of this agreement, we expect to reflect an $89 million after-tax charge in our second quarter 2012 earnings.

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 100 percent owned by ConocoPhillips. ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding Company II are indirect, 100 percent owned subsidiaries of ConocoPhillips Company. 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.

		$000,000			$000,000			$000,000		$000,000			$000,000			$000,000			$000,000			$000,000
	Millions of Dollars
	Three Months Ended March 31, 2012
Income Statement	ConocoPhillips			ConocoPhillips Company			ConocoPhillips Australia Funding Company		ConocoPhillips Canada Funding Company I			ConocoPhillips Canada Funding Company II			All Other Subsidiaries			Consolidating Adjustments			Total Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—			33,652			—		—			—			22,480			—			56,132
Equity in earnings of affiliates		3,290			3,984			—		—			—			686			(6,740	)		1,220
Gain on dispositions		—			1			—		—			—			941			—			942
Other income		1			42			—		—			—			17			—			60
Intercompany revenues		1			872			11		22			8			8,934			(9,848	)		—

Total Revenues and Other Income		3,292			38,551			11		22			8			33,058			(16,588	)		58,354

Costs and Expenses
Purchased crude oil, natural gas and products		—			31,367			—		—			—			19,800			(9,278	)		41,889
Production and operating expenses		—			1,166			—		—			—			1,603			(73	)		2,696
Selling, general and administrative expenses		5			485			—		—			—			166			29			685
Exploration expenses		—			89			—		—			—			590			—			679
Depreciation, depletion and amortization		—			360			—		—			—			1,478			—			1,838
Impairments		—			2			—		—			—			257			—			259
Taxes other than income taxes		—			1,363			—		—			—			3,158			—			4,521
Accretion on discounted liabilities		—			18			—		—			—			96			—			114
Interest and debt expense		540			82			10		19			8			76			(526	)		209
Foreign currency transaction (gains) losses		—			(28	)		—		11			16			(10	)		—			(11	)

Total Costs and Expenses		545			34,904			10		30			24			27,214			(9,848	)		52,879

Income (loss) before income taxes		2,747			3,647			1		(8	)		(16	)		5,844			(6,740	)		5,475
Provision for income taxes		(190	)		357			—		6			(1	)		2,348			—			2,520

Net income (loss)		2,937			3,290			1		(14	)		(15	)		3,496			(6,740	)		2,955
Less: net income attributable to noncontrolling interests		—			—			—		—			—			(18	)		—			(18	)

Net Income (Loss) Attributable to ConocoPhillips	$	2,937			3,290			1		(14	)		(15	)		3,478			(6,740	)		2,937

Comprehensive Income Attributable to ConocoPhillips	$	2,937			3,371			1		19			(2	)		4,237			(6,740	)		3,823


Income Statement	Three Months Ended March 31, 2011
Revenues and Other Income
Sales and other operating revenues	$	—			35,729			—		—			—			20,801			—			56,530
Equity in earnings of affiliates		3,235			3,439			—		—			—			543			(6,200	)		1,017
Gain on dispositions		—			268			—		—			—			348			—			616
Other income		—			53			—		—			—			31			—			84
Intercompany revenues		1			903			11		23			9			8,643			(9,590	)		—

Total Revenues and Other Income		3,236			40,392			11		23			9			30,366			(15,790	)		58,247

Costs and Expenses
Purchased crude oil, natural gas and products		—			33,441			—		—			—			18,144			(9,209	)		42,376
Production and operating expenses		—			1,152			—		—			—			1,566			(90	)		2,628
Selling, general and administrative expenses		5			318			—		—			—			160			16			499
Exploration expenses		—			50			—		—			—			126			—			176
Depreciation, depletion and amortization		—			387			—		—			—			1,683			—			2,070
Taxes other than income taxes		—			1,248			—		—			—			3,116			—			4,364
Accretion on discounted liabilities		—			17			—		—			—			95			—			112
Interest and debt expense		315			107			10		19			8			110			(307	)		262
Foreign currency transaction (gains) losses		—			(17	)		—		37			(3	)		(53	)		—			(36	)

Total Costs and Expenses		320			36,703			10		56			5			24,947			(9,590	)		52,451

Income (loss) before income taxes		2,916			3,689			1		(33	)		4			5,419			(6,200	)		5,796
Provision for income taxes		(112	)		454			—		1			10			2,401			—			2,754

Net income (loss)		3,028			3,235			1		(34	)		(6	)		3,018			(6,200	)		3,042
Less: net income attributable to noncontrolling interests		—			—			—		—			—			(14	)		—			(14	)

Net Income (Loss) Attributable to ConocoPhillips	$	3,028			3,235			1		(34	)		(6	)		3,004			(6,200	)		3,028

Comprehensive Income Attributable to ConocoPhillips	$	3,028			3,294			1		5			10			3,664			(6,200	)		3,802


	Millions of Dollars
	March 31, 2012
Balance Sheet	ConocoPhillips			ConocoPhillips Company		ConocoPhillips Australia Funding Company		ConocoPhillips Canada Funding Company I			ConocoPhillips Canada Funding Company II			All Other Subsidiaries		Consolidating Adjustments			Total Consolidated
Assets
Cash and cash equivalents	$	—			169		1		37			1			3,499		—			3,707
Short-term investments		—			—		—		—			—			508		—			508
Restricted cash		—			—		—		—			—			6,050		—			6,050
Accounts and notes receivable		64			7,478		—		—			—			16,738		(6,797	)		17,483
Inventories		—			2,659		—		—			—			3,413		—			6,072
Prepaid expenses and other current assets		20			1,026		—		1			—			2,199		—			3,246

Total Current Assets		84			11,332		1		38			1			32,407		(6,797	)		37,066
Investments, loans and long-term receivables*		100,748			138,137		771		1,473			586			63,602		(270,128	)		35,189
Net properties, plants and equipment		—			19,825		—		—			—			65,734		—			85,559
Goodwill		—			3,330		—		—			—			—		—			3,330
Intangibles		—			721		—		—			—			21		—			742
Other assets		58			299		—		2			4			632		—			995

Total Assets	$	100,890			173,644		772		1,513			591			162,396		(276,925	)		162,881

Liabilities and Stockholders’ Equity
Accounts payable	$	—			12,333		1		3			1			16,009		(6,797	)		21,550
Short-term debt		891			207		—		—			—			5,904		—			7,002
Accrued income and other taxes		—			559		—		3			—			4,189		—			4,751
Employee benefit obligations		—			542		—		—			—			158		—			700
Other accruals		154			539		19		32			14			1,669		—			2,427

Total Current Liabilities		1,045			14,180		20		38			15			27,929		(6,797	)		36,430
Long-term debt		10,952			3,397		750		1,250			499			4,510		—			21,358
Asset retirement obligations and accrued environmental costs		—			1,755		—		—			—			7,318		—			9,073
Joint venture acquisition obligation		—			—		—		—			—			3,393		—			3,393
Deferred income taxes		(5	)		4,112		—		16			8			14,578		—			18,709
Employee benefit obligations		—			3,048		—		—			—			985		—			4,033
Other liabilities and deferred credits*		29,235			42,346		—		116			46			18,299		(87,200	)		2,842

Total Liabilities		41,227			68,838		770		1,420			568			77,012		(93,997	)		95,838
Retained earnings		44,787			38,355		1		(85	)		(72	)		30,985		(62,685	)		51,286
Other common stockholders’ equity		14,876			66,451		1		178			95			53,890		(120,243	)		15,248
Noncontrolling interests		—			—		—		—			—			509		—			509

Total Liabilities and Stockholders’ Equity	$	100,890			173,644		772		1,513			591			162,396		(276,925	)		162,881


Balance Sheet	December 31, 2011
Assets
Cash and cash equivalents	$	—			2,028		1		37			1			3,713		—			5,780
Short-term investments		—			—		—		—			—			581		—			581
Accounts and notes receivable		60			9,186		—		—			—			20,898		(13,618	)		16,526
Inventories		—			2,239		—		—			—			2,392		—			4,631
Prepaid expenses and other current assets		22			1,090		—		1			—			1,587		—			2,700

Total Current Assets		82			14,543		1		38			1			29,171		(13,618	)		30,218
Investments, loans and long-term receivables*		96,269			135,603		760		1,417			565			59,651		(260,482	)		33,783
Net properties, plants and equipment		—			19,595		—		—			—			64,585		—			84,180
Goodwill		—			3,332		—		—			—			—		—			3,332
Intangibles		—			722		—		—			—			23		—			745
Other assets		64			301		—		2			3			602		—			972

Total Assets	$	96,415			174,096		761		1,457			569			154,032		(274,100	)		153,230

Liabilities and Stockholders’ Equity
Accounts payable	$	10			18,747		—		1			1			14,512		(13,618	)		19,653
Short-term debt		892			27		—		—			—			94		—			1,013
Accrued income and other taxes		—			315		—		2			—			3,903		—			4,220
Employee benefit obligations		—			835		—		—			—			276		—			1,111
Other accruals		244			634		9		14			6			1,164		—			2,071

Total Current Liabilities		1,146			20,558		9		17			7			19,949		(13,618	)		28,068
Long-term debt		10,951			3,599		749		1,250			498			4,563		—			21,610
Asset retirement obligations and accrued environmental costs		—			1,766		—		—			—			7,563		—			9,329
Joint venture acquisition obligation		—			—		—		—			—			3,582		—			3,582
Deferred income taxes		(5	)		3,982		—		11			9			14,058		—			18,055
Employee benefit obligations		—			3,092		—		—			—			976		—			4,068
Other liabilities and deferred credits*		25,959			40,479		—		104			29			20,047		(83,834	)		2,784

Total Liabilities		38,051			73,476		758		1,382			543			70,738		(97,452	)		87,496
Retained earnings		42,694			35,065		1		(70	)		(55	)		29,928		(58,369	)		49,194
Other common stockholders’ equity		15,670			65,555		2		145			81			52,856		(118,279	)		16,030
Noncontrolling interests		—			—		—		—			—			510		—			510

Total Liabilities and Stockholders’ Equity	$	96,415			174,096		761		1,457			569			154,032		(274,100	)		153,230

*Includes intercompany loans.

		$000,000			$000,000			$000,000		$000,000			$000,000			$000,000			$000,000			$000,000
	Millions of Dollars
	Three Months Ended March 31, 2012
Statement of Cash Flows	ConocoPhillips			ConocoPhillips Company			ConocoPhillips Australia Funding Company		ConocoPhillips Canada Funding Company I			ConocoPhillips Canada Funding Company II			All Other Subsidiaries			Consolidating Adjustments			Total Consolidated
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	2,708			3,904			—		(1	)		—			(8	)		(2,421	)		4,182

Cash Flows From Investing Activities
Capital expenditures and investments		—			(633	)		—		—			—			(3,627	)		—			(4,260	)
Proceeds from asset dispositions		—			—			—		—			—			1,109			—			1,109
Net purchases of short-term investments		—			—			—		—			—			92			—			92
Long-term advances/loans—related parties		—			(2	)		—		—			—			—			6			4
Collection of advances/loans—related parties		—			92			—		—			—			5,228			(5,282	)		38
Other		—			—			—		—			—			7			—			7

Net Cash Provided by (Used in) Investing Activities		—			(543	)		—		—			—			2,809			(5,276	)		(3,010	)

Cash Flows From Financing Activities
Issuance of debt		—			—			—		—			—			5,800			(6	)		5,794
Repayment of debt		—			(5,220	)		—		—			—			(116	)		5,282			(54	)
Change in restricted cash		—			—			—		—			—			(6,050	)		—			(6,050	)
Issuance of company common stock		36			—			—		—			—			—			—			36
Repurchase of company common stock		(1,899	)		—			—		—			—			—			—			(1,899	)
Dividends paid on common stock		(843	)		—			—		—			—			(2,421	)		2,421			(843	)
Other		(2	)		—			—		—			—			(252	)		—			(254	)

Net Cash Used in Financing Activities		(2,708	)		(5,220	)		—		—			—			(3,039	)		7,697			(3,270	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			—		—			—			25			—			25

Net Change in Cash and Cash Equivalents		—			(1,859	)		—		(1	)		—			(213	)		—			(2,073	)
Cash and cash equivalents at beginning of period		—			2,028			1		38			1			3,712			—			5,780

Cash and Cash Equivalents at End of Period	$	—			169			1		37			1			3,499			—			3,707


Statement of Cash Flows	Three Months Ended March 31, 2011
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	2,506			(1,974	)		—		(1	)		(7	)		1,711			(288	)		1,947

Cash Flows From Investing Activities
Capital expenditures and investments		—			(426	)		—		—			—			(2,458	)		—			(2,884	)
Proceeds from asset dispositions		—			329			—		—			—			1,458			—			1,787
Net purchases of short-term investments		—			—			—		—			—			(1,170	)		—			(1,170	)
Long-term advances/loans—related parties		—			2			—		(4	)		—			(2,077	)		2,083			4
Collection of advances/loans—related parties		—			104			—		—			—			29			(93	)		40
Other		—			—			—		—			—			12			—			12

Net Cash Provided by (Used in) Investing Activities		—			9			—		(4	)		—			(4,206	)		1,990			(2,211	)

Cash Flows From Financing Activities
Issuance of debt		—			2,073			—		—			4			6			(2,083	)		—
Repayment of debt		—			(343	)		—		—			—			(123	)		93			(373	)
Issuance of company common stock		75			—			—		—			—			—			—			75
Repurchase of company common stock		(1,636	)		—			—		—			—			—			—			(1,636	)
Dividends paid on common stock		(944	)		—			—		—			—			(288	)		288			(944	)
Other		(1	)		—			—		—			—			(182	)		—			(183	)

Net Cash Provided by (Used in) Financing Activities		(2,506	)		1,730			—		—			4			(587	)		(1,702	)		(3,061	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			—		—			—			43			—			43

Net Change in Cash and Cash Equivalents		—			(235	)		—		(5	)		(3	)		(3,039	)		—			(3,282	)
Cash and cash equivalents at beginning of period		—			718			—		29			4			8,703			—			9,454

Cash and Cash Equivalents at End of Period	$	—			483			—		24			1			5,664			—			6,172

Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis is the company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes. It contains forward-looking statements including, without limitation, statements relating to the company’s 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 “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s 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 49.

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 March 31, 2012, we had approximately 29,700 employees worldwide and total assets of $163 billion.

Earnings of the company depend largely on the profitability of our Exploration and Production (E&P) and Refining and Marketing (R&M) segments. Crude oil and natural gas prices, along with refining margins, are the most significant factors in our profitability. Industry crude oil prices for West Texas Intermediate (WTI) averaged $102.99 per barrel in the first quarter of 2012, an increase of 10 percent compared with the first quarter of 2011, and an increase of 9 percent compared with the fourth quarter of 2011. The increase in oil prices in the first quarter of 2012 was primarily due to concerns about the potential for supply disruptions associated with European sanctions on Iran. This impact on prices was partially offset by the continued slowing of economic growth in much of the world, including China, and concerns about the European sovereign debt crisis.

Henry Hub natural gas prices averaged $2.72 per million British thermal units (MMBTU) in the first quarter of 2012, a decrease of 34 percent compared with the first quarter of 2011, and a decrease of 23 percent compared with the fourth quarter of 2011. U.S. natural gas prices remained under pressure in the first quarter of 2012 due to continued production growth from shale plays, combined with lower heating demand as a result of an exceptionally warm winter across much of the United States. This combination led to record-high storage inventory levels by the end of the first quarter, with U.S. natural gas prices trending below $2.00 per MMBTU in April. Prolonged substantial decreases in U.S. natural gas prices could have an adverse effect on our results of operations.

E&P segment earnings were $2,548 million in the first quarter of 2012, which accounted for 87 percent of our total earnings in the quarter. This compares with E&P earnings of $2,352 million in the first quarter of 2011 and $1,604 million in the fourth quarter of 2011.

Domestic refining margins significantly improved in the first quarter of 2012, while international refining margins decreased. The U.S. 3:2:1 crack spread, which is primarily WTI-based, increased 24 percent in the first quarter of 2012, compared with the first quarter of 2011, and 21 percent compared with the fourth quarter of 2011. The improvement in domestic refining margins primarily resulted from increased crude oil production from shale plays and rising imports from Canada, in addition to infrastructure constraints, causing WTI to continue to trade at a deeper discount relative to waterborne crudes. Refineries capable of processing WTI and crude oils that are WTI-based, primarily the Midcontinent and Gulf Coast refineries, benefitted from these lower regional feedstock prices.

The Northwest Europe benchmark increased 3 percent in the first quarter of 2012, compared with the first quarter of 2011, and decreased 9 percent compared with the fourth quarter of 2011. Despite a cold winter in Europe, demand for refined products decreased in the first quarter of 2012, driven by slowing economic activity as a result of their recession.

Our R&M segment reported earnings of $452 million in the first quarter of 2012, compared with earnings of $482 million in the first quarter of 2011, and earnings of $1,714 million in the fourth quarter of 2011.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three-month period ended March 31, 2012, is based on a comparison with the corresponding period of 2011.

Consolidated Results

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


	Millions of Dollars
	Three Months Ended March 31
	2012			2011


E&P	$	2,548			2,352
Midstream		93			73
R&M		452			482
LUKOIL Investment		-			239
Chemicals		218			193
Emerging Businesses		(14	)		(7	)
Corporate and Other		(360	)		(304	)

Net income attributable to ConocoPhillips	$	2,937			3,028

Earnings for ConocoPhillips were $2,937 million in the first quarter of 2012, a decrease of 3 percent compared with earnings of $3,028 million in the first quarter of 2011. The decrease was primarily the result of:

•

Higher impairments. In the first quarter of 2012, non-cash impairments totaled $562 million after-tax.

•

Lower production volumes from our E&P segment.

•

Lower natural gas prices.

These items were partially offset by:

•

Higher gains from asset sales. Gains from asset dispositions in the first quarter of 2012 primarily consisted of the $937 million after-tax gain from the disposition of our Vietnam business, compared with gains of $394 million after-tax in the first quarter of 2011, which mostly consisted of remaining LUKOIL share sales and Lower 48 asset dispositions.

•

Substantially higher crude oil and liquefied natural gas (LNG) prices in our E&P segment. Commodity price benefits were somewhat offset by increased production taxes.

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

Income Statement Analysis

Equity in earnings of affiliates increased 20 percent in the first quarter of 2012, which primarily resulted from:

•

Improved earnings from Qatar Liquefied Gas Company Limited (3) (QG3), mainly due to significantly higher LNG prices.

•

Improved earnings from WRB Refining LP, primarily due to higher refining margins in the Midcontinent region.

•

Higher earnings from FCCL Partnership, mainly as a result of the ramp-up of production from Christina Lake Phase C.

•

Improved earnings from Chevron Phillips Chemical Company LLC (CPChem), mostly due to higher margins in the olefins and polyolefins business line.

The increase in equity earnings was partially offset by:

•

Lower earnings from Merey Sweeny, L.P., mainly due to lower refining margins.

•

Lower earnings from Naryanmarneftegaz (NMNG), largely due to lower volumes.

Gain on dispositions increased 53 percent in the first quarter of 2012. The increase was mainly due to the $937 million gain on sale of our Vietnam business in the first quarter of 2012, partly offset by the first quarter 2011 disposition of certain E&P assets located in the Lower 48 and our remaining LUKOIL shares.

Selling, general and administrative expenses increased 37 percent in the first quarter of 2012, primarily as a result of costs associated with the separation of Phillips 66.

Exploration expenses increased $503 million in the first quarter of 2012. The increase was mostly due to the impairment of undeveloped leasehold costs associated with the Mackenzie Gas Project as a result of the suspension of the project.

Depreciation, depletion and amortization (DD&A) decreased 11 percent in the first quarter of 2012. The decrease was mostly associated with our E&P segment, reflecting lower production volumes primarily due to unplanned downtime and asset dispositions. These decreases were partially offset by higher production volumes in the Lower 48.

Impairments increased $259 million in the first quarter of 2012, primarily as a result of the impairment of capitalized project development costs associated with the Mackenzie Gas Project, in addition to the impairment of equipment formerly associated with the canceled Wilhelmshaven Refinery (WRG) upgrade project.

Interest and debt expense decreased 20 percent in the first quarter of 2012, primarily due to higher capitalized interest on projects.

See Note 20—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.

Segment Results

E&P


	Three Months Ended March 31
	2012		2011

	Millions of Dollars
Net Income Attributable to ConocoPhillips
Alaska	$	616		549
Lower 48		254		314

United States		870		863
International		1,678		1,489

	$	2,548		2,352


	Dollars Per Unit
Average Sales Prices
Crude oil and natural gas liquids (per barrel)
United States	$	95.71		85.36
International		109.10		96.86
Total consolidated operations		101.23		91.30
Equity affiliates		107.41		94.95
Total E&P		101.56		91.55
Bitumen (per barrel)
International		64.95		47.94
Equity affiliates		60.04		56.15
Total E&P		60.66		54.77
Natural gas (per thousand cubic feet)
United States		2.72		4.10
International		6.65		6.43
Total consolidated operations		5.09		5.54
Equity affiliates		2.58		2.59
Total E&P		4.80		5.22


	Millions of Dollars
Worldwide Exploration Expenses
General and administrative; geological and geophysical; and lease rentals	$	161		126
Leasehold impairment		512		41
Dry holes		6		9

	$	679		176


	Three Months Ended March 31
	2012		2011

	Thousands of Barrels Daily
Operating Statistics
Crude oil and natural gas liquids produced
Alaska		226		214
Lower 48		201		150

United States		427		364
Canada		38		37
Europe		166		196
Asia Pacific/Middle East		79		142
Africa		64		61

Total consolidated operations		774		800
Equity affiliates
Asia Pacific/Middle East		24		22
Russia		18		38

		816		860


Bitumen produced
Consolidated operations—Canada		11		11
Equity affiliates—Canada		73		53

		84		64


	Millions of Cubic Feet Daily
Natural gas produced*
Alaska		59		67
Lower 48		1,502		1,522

United States		1,561		1,589
Canada		863		944
Europe		632		751
Asia Pacific/Middle East		697		720
Africa		164		158

Total consolidated operations		3,917		4,162
Equity affiliates
Asia Pacific/Middle East		505		507

		4,422		4,669

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

The E&P segment explores for, produces, transports and markets crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At March 31, 2012, 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, Libya, Nigeria, Algeria, Qatar and Russia. Total E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 1,637,000 BOE per day in the first quarter of 2012, compared with 1,702,000 BOE per day in the first quarter of 2011.

Our E&P operations reported earnings of $2,548 million in the first quarter of 2012, an 8 percent increase compared with earnings of $2,352 million in the first quarter of 2011. See the “Business Environment and Executive Overview” section for additional information on industry crude oil and natural gas prices.

U.S. E&P

U.S. E&P earnings were $870 million in the first quarter of 2012, a 1 percent increase compared with earnings of $863 million for the same period in 2011. Earnings benefitted from higher crude oil prices and crude oil and natural gas liquids volumes, which were mostly offset by higher production taxes in Alaska, lower natural gas prices, lower gains from asset sales and higher DD&A.

U.S. E&P production averaged 687,000 BOE per day in the first quarter of 2012, an increase of 9 percent from 629,000 BOE per day in the first quarter of 2011. The increase was mainly due to new production, primarily from shale plays in the Lower 48, and lower unplanned downtime, partially offset by field decline.

International E&P

International E&P earnings were $1,678 million in the first quarter of 2012, a 13 percent increase compared with earnings of $1,489 million for the same period in 2011. The increase was primarily due to the $937 million after-tax gain on sale of our Vietnam business, higher crude oil and LNG prices and lower DD&A. These increases were partially offset by lower crude oil volumes, primarily in China, the $520 million after-tax impairment of the Mackenzie Gas Project and associated undeveloped leaseholds and higher taxes. For additional information, see Note 8—Impairments, in the Notes to Consolidated Financial Statements.

International E&P production averaged 950,000 BOE per day in the first quarter of 2012, a decrease of 11 percent from 1,073,000 BOE per day in the first quarter of 2011. The decrease primarily resulted from field decline, suspended operations in China and dispositions, partly offset by new production.

Midstream


	Three Months Ended March 31
	2012		2011

	Millions of Dollars

Net Income Attributable to ConocoPhillips*	$	93		73

*Includes DCP Midstream-related earnings:	$	56		48

	Dollars Per Barrel
Average Sales Prices
U.S. natural gas liquids*
Consolidated	$	52.44		53.55
Equity affiliates		42.10		47.64

*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*		213		188
Natural gas liquids fractionated**		136		139

*Includes our share of equity affiliates.

**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, trading and marketing businesses, primarily in the United States and Trinidad.

Earnings from the Midstream segment were $93 million in the first quarter of 2012, an increase of 27 percent compared with the same period in 2011. This increase was largely due to higher gathering and processing volumes, primarily as a result of less weather-related downtime, increased volumes from expansion projects and improved marketing results. These increases were partially offset by lower natural gas liquids prices.

R&M


	Three Months Ended March 31
	2012			2011

	Millions of Dollars
Net Income Attributable to ConocoPhillips
United States	$	415			402
International		37			80

	$	452			482


	Dollars Per Gallon
U.S. Average Wholesale Prices*
Gasoline	$	2.98			2.73
Distillates		3.21			2.92

*Excludes excise taxes.

	Thousands of Barrels Daily
Operating Statistics
Refining operations*
United States
Crude oil capacity		1,801			1,986
Crude oil runs		1,610			1,735
Capacity utilization (percent)		89	%		87
Refinery production		1,775			1,914
International
Crude oil capacity		430			426
Crude oil runs		417			410
Capacity utilization (percent)		97	%		96
Refinery production		433			417
Worldwide
Crude oil capacity		2,231			2,412
Crude oil runs		2,027			2,145
Capacity utilization (percent)		91	%		89
Refinery production		2,208			2,331


Petroleum products sales volumes
United States
Gasoline		958			1,099
Distillates		837			852
Other products		298			437

		2,093			2,388
International		625			672

		2,718			3,060

*Includes our share of equity affiliates.

The R&M segment refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels); buys, sells and transports crude oil; and buys, transports, distributes and markets petroleum products. R&M has operations mainly in the United States, Europe and Asia.

R&M reported earnings of $452 million during the first quarter of 2012, a 6 percent decrease compared with earnings of $482 million in the corresponding quarter of 2011. See the “Business Environment and Executive Overview” section for additional information on industry refining margins.

U.S. R&M

U.S. R&M earnings were $415 million in the first quarter of 2012, a 3 percent increase compared with earnings of $402 million in the same period of 2011. This increase mainly resulted from processing higher refining volumes in our Central Region and from higher marketing margins, in addition to a favorable tax adjustment related to a fourth quarter 2011 disposition. These increases were partially offset by lower refining margins and higher operating expenses. Refining margins decreased as the impact of less favorable crude differentials more than offset improved market crack spreads.

In 2011, we idled the Trainer Refinery and announced plans to permanently close the facility by the end of the first quarter of 2012 if a sales transaction was unsuccessful. We have extended the sales deadline to the end of May 2012.

Our U.S. refining capacity utilization rate was 89 percent in the first quarter of 2012, compared with 87 percent in the first quarter of 2011. The current year rate primarily reflects lower maintenance and unplanned downtime, partly offset by higher turnaround activity.

International R&M

International R&M earnings were $37 million in the first quarter of 2012, a 54 percent decrease compared with earnings of $80 million in the same period of 2011. The decrease was mainly due to the $42 million after-tax property impairment related to equipment formerly associated with the canceled WRG upgrade project, lower refining margins and lower gains from foreign currency transactions. These decreases were partially offset by higher refining volumes and marketing margins, as well as lower operating expenses. For additional information on the impairment, see Note 8—Impairments, in the Notes to Consolidated Financial Statements.

Our international refining capacity utilization rate was 97 percent in the first quarter of 2012, compared with 96 percent in the first quarter of 2011. The current year rate primarily reflects lower maintenance, partly offset by higher turnaround activity.

LUKOIL Investment


	Millions of Dollars
	Three Months Ended March 31
	2012		2011


Net Income Attributable to ConocoPhillips	$	-		239

This segment represents our former investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We sold our remaining interest in LUKOIL in the first quarter of 2011. Earnings in the first quarter of 2011 primarily reflected the realized gain on remaining share sales.

Chemicals


	Millions of Dollars
	Three Months Ended March 31
	2012		2011


Net Income Attributable to ConocoPhillips	$	218		193

The Chemicals segment consists of our 50 percent interest in 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.

Earnings from the Chemicals segment increased $25 million in the first quarter of 2012, or 13 percent compared with the first quarter of 2011. The improvement in earnings primarily resulted from higher margins and lower operating costs in the olefins and polyolefins business line. These increases were partially offset by lower margins in the specialties, aromatics and styrenics business line.

Emerging Businesses


	Millions of Dollars
	Three Months Ended March 31
	2012			2011

Net Income (Loss) Attributable to ConocoPhillips
Power	$	23			22
Other		(37	)		(29	)

	$	(14	)		(7	)

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, refining, alternative energy, biofuels and the environment.

The Emerging Businesses segment reported a loss of $14 million in the first quarter of 2012, compared with a loss of $7 million in the first quarter of 2011. The increase in “Other” losses was mainly due to higher technology development expenses.

Corporate and Other


	Millions of Dollars
	Three Months Ended March 31
	2012			2011

Net Loss Attributable to ConocoPhillips
Net interest	$	(156	)		(181	)
Corporate general and administrative expenses		(78	)		(63	)
Separation costs*		(95	)		-
Other		(31	)		(60	)

	$	(360	)		(304	)

*Includes $10 million of interest expense.

Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest decreased 14 percent in the first quarter of 2012, primarily as a result of higher capitalized interest on projects.

Corporate general and administrative expenses increased 24 percent in the first quarter of 2012. Higher contributions and advertising expenses were partly offset by lower costs related to compensation plans.

Separation costs consist of expenses incurred for the planned separation of our downstream businesses into a stand-alone, publicly traded company, Phillips 66. Expenses incurred in the first quarter of 2012 primarily included legal, accounting and information systems costs; expenses related to compensation and benefit plans; and interest expense associated with Phillips 66 senior notes.

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 decrease in “Other” expenses primarily resulted from the absence of various tax-related adjustments recorded in the first quarter of 2011 and lower environmental expenses in the first quarter of 2012.

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators


	Millions of Dollars
	March 31 2012			December 31 2011

Short-term debt	$	7,002			1,013
Total debt		28,360			22,623
Total equity		67,043			65,734
Percent of total debt to capital*		30	%		26
Percent of floating-rate debt to total debt**		7	%		10

*Capital includes total debt and total equity.
**Includes effect of interest rate swaps.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from operating activities is the primary source of funding. In addition, during the first quarter of 2012, we received $1,109 million in proceeds from asset sales. During the first quarter of 2012, available cash was used to support our ongoing capital expenditures and investments program, repurchase common stock and pay dividends. Total dividends paid on our common stock during the first quarter were $843 million. During the first quarter of 2012, cash and cash equivalents decreased by $2,073 million to $3,707 million.

In addition to cash flows from operating activities and proceeds from asset sales, we rely on our commercial paper and credit facility programs, and our shelf registration statement to support our short- and long-term liquidity requirements. 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 Partnership.

Significant Sources of Capital

Operating Activities

During the first quarter of 2012, cash of $4,182 million was provided by operating activities, a 115 percent increase from cash from operations of $1,947 million in the corresponding period of 2011. The increase is primarily due to lower discretionary inventory builds in the first quarter of 2012 compared to the first quarter of 2011.

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, bitumen, natural gas, LNG and natural gas liquids, as well as refining and marketing margins. Prices and margins in our industry are typically volatile, and 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 also impacts our cash flows. These production levels are impacted by such factors as acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiency, weather conditions, the addition of proved reserves through exploratory success, and their timely and cost-effective development. While we actively manage these factors, production levels can cause variability in cash flows, although generally 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, market conditions, feedstock availability and weather conditions. We actively manage the operations of our refineries and, typically, any variability in their operations has not been as significant to cash flows as that caused by refining margins.

Asset Sales

Proceeds from asset sales during the first quarter of 2012 were $1,109 million, primarily from the sale of our Vietnam E&P business. This compares with proceeds of $1,787 million in the first quarter of 2011. We plan to raise up to an additional $10 billion from asset sales over the next 12 months.

Commercial Paper and Credit Facilities

At March 31, 2012, we had two revolving credit facilities totaling $8.0 billion, consisting of a $7.5 billion facility expiring in August 2016 and a $500 million facility expiring in July 2012. Our revolving credit facilities may be used as direct bank borrowings, as support for issuances of letters of credit totaling up to $26 million, or as support for our commercial paper programs. The revolving credit facilities are broadly syndicated among financial institutions and do not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The facility agreements contain a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or by any of its consolidated subsidiaries.

Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the London interbank market or at a margin above the overnight federal funds rate or prime rates offered by certain designated banks in the United States. The agreements call for commitment fees on available, but unused, amounts. The agreements also contain early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.

Our primary funding source for short-term working capital needs is the ConocoPhillips $6.35 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, which is used to fund commitments relating to the QG3 Project. At March 31, 2012, and December 31, 2011, we had no direct borrowings under the revolving credit facilities, but $26 million in letters of credit had been issued at March 31, 2012, and $40 million at December 31, 2011. In addition, under the two ConocoPhillips commercial paper programs, $1,097 million of commercial paper was outstanding at March 31, 2012, compared with $1,128 million at December 31, 2011. Since we had $1,097 million of commercial paper outstanding and had issued $26 million of letters of credit, we had access to $6.9 billion in borrowing capacity under our revolving credit facilities at March 31, 2012.

Shelf Registration

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.

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.

For information about guarantees, see Note 12—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Capital Requirements

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

Our debt balance at March 31, 2012, was $28.4 billion, an increase of $5.7 billion from the balance at December 31, 2011. The increase is primarily due to the issuance of debt by Phillips 66 of $5.8 billion of fixed-rate Senior Notes in March 2012. The net proceeds of the issuance were deposited into two segregated escrow accounts pending the separation and are included in the “Restricted cash” line on our consolidated balance sheet as of March 31, 2012. Post separation, Phillips 66 will retain this debt, and ConocoPhillips will use a cash distribution from Phillips 66, estimated to be $5.8 billion plus working capital adjustments, solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, in each case within twelve months following the distribution.

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began 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 $742 million was short-term and was included in the “Accounts payable—related parties” line on our March 31, 2012, consolidated balance sheet. The principal portion of these payments, which totaled $180 million in the first three months of 2012, is 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.

In February, 2012, we announced a dividend of 66 cents per share. The dividend was paid March 1, 2012, to stockholders of record at the close of business February 21, 2012.

On December 2, 2011, our Board of Directors authorized the purchase of up to an additional $10 billion of our common stock over the subsequent two years. Since our share repurchase programs began in 2010, share repurchases totaled 245 million shares at a cost of $16.9 billion through March 31, 2012.

Capital Spending

Capital Expenditures and Investments


	Millions of Dollars
	Three Months Ended March 31
	2012		2011

E&P
United States—Alaska	$	186		195
United States—Lower 48		1,267		773
International		2,528		1,724

		3,981		2,692

Midstream		4		3

R&M
United States		176		131
International		38		25

		214		156

LUKOIL Investment		-		-
Chemicals		-		-
Emerging Businesses		15		6
Corporate and Other		46		27

	$	4,260		2,884

United States	$	1,692		1,231
International		2,568		1,653

	$	4,260		2,884

E&P

Capital spending for E&P during the first three months of 2012 totaled $4.0 billion. The expenditures supported key exploration and development projects including:

•

Oil and natural gas exploration and development activities in the Lower 48, including the Eagle Ford, Bakken and North Barnett shale plays, as well as the Permian Basin.

•

Alaska development activities related to existing producing fields.

•

Oil sands projects in Canada.

•

Further development of coalbed methane projects associated with the Australia Pacific LNG Pty Ltd (APLNG) joint venture in Australia.

•

New fields offshore Malaysia.

•

In the North Sea, development activities in the Greater Ekofisk area, Jasmine and Clair Ridge.

•

The Kashagan Field in the Caspian Sea.

•

In Africa, primarily leasehold acquisitions in Angola and offshore activity in Nigeria.

R&M

Capital spending for R&M during the first three months of 2012 totaled $214 million and included projects related to sustaining and improving the existing business with a focus on safety, regulatory compliance and reliability.

Contingencies

contingencies. 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.

Legal Matters

Environmental

We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. 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 64, 65 and 66 of our 2011 Annual Report on Form 10-K.

We occasionally receive requests for information or notices of potential liability from the Environmental Protection Agency (EPA) 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, 2011, we reported we had been notified of potential liability under CERCLA and comparable state laws at 74 sites around the United States. During the quarter ended March 31, 2012, we were notified of 1 new site and resolved 12 sites, bringing the number to 63 unresolved sites with potential liability.

At March 31, 2012, our balance sheet included a total environmental accrual of $920 million, compared with $922 million at December 31, 2011. 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 concerns 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 it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. Examples of legislation and precursors for possible regulation that do or could affect our operations include the EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)), and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that trigger regulation of GHGs under the Clean Air Act, may trigger more climate-based claims for damages, and may result in longer agency review time for development projects.

For other 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 66 and 67 of our 2011 Annual Report on Form 10-K.

OUTLOOK

Planned Separation of Downstream Businesses

In conjunction with the separation, we received a private letter ruling from the Internal Revenue Service (IRS) to the effect that, based on certain facts, assumptions, representations and undertakings set forth in the ruling, for U.S. federal income tax purposes, the distribution of Phillips 66 stock is not taxable to ConocoPhillips or U.S. holders of ConocoPhillips common stock, except in respect of cash received in lieu of fractional share interests. Following the separation, ConocoPhillips will retain no ownership interest in Phillips 66, and each company will have separate public ownership, boards of directors and management. A registration statement on Form 10, as amended through the time of its effectiveness and describing the separation, was filed by Phillips 66 with the SEC and was declared effective on April 12, 2012. On May 1, 2012, Phillips 66 stock will begin trading the “regular-way” on the New York Stock Exchange under the “PSX” stock symbol.

As part of the separation, we expect to receive a cash distribution from Phillips 66 of approximately $5.8 billion plus working capital adjustments. Under the terms of the IRS ruling, these funds will be used solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, within twelve months following the distribution. We recognized one-time separation costs of $25 million and $95 million after-tax in 2011 and the first quarter of 2012, respectively, primarily related to legal, information technology, audit, advisor, and compensation and benefits. Prior to the separation, we expect to recognize additional one-time separation costs of approximately $75 million to $100 million after-tax, primarily related to remeasurement of deferred tax assets, as well as transfer taxes, interest expense, and information technology.

APLNG

In January 2012, APLNG and China Petrochemical Corporation (Sinopec) signed an amendment to their existing LNG sales agreement for the sale and purchase of an additional 3.3 million tonnes of LNG per year through 2035. This agreement, in combination with the binding Heads of Agreement with Kansai Electric Power Co., Inc., signed in November 2011, finalizes the marketing of the second train. In conjunction with the LNG sales agreement, the parties have also agreed for Sinopec to subscribe for additional shares in APLNG, which upon completion will raise its equity interest from 15 percent to 25 percent. As a result, both our ownership interest and Origin Energy’s ownership interest would dilute from 42.5 percent to 37.5 percent. The Subscription Agreement is subject to customary governmental approvals and, along with the amendment to the sales agreement, is conditional on a final investment decision on the second train, which is expected in the second quarter of 2012. We expect to record a loss of approximately $135 million after-tax from the dilution in the second quarter of 2012.

U.K. Tax Legislation

In the United Kingdom, legislation is expected to be enacted in July 2012 which would limit corporate tax relief on decommissioning costs to 50 percent. Upon enactment, we anticipate our third quarter 2012 earnings would be reduced by approximately $200 million due to the remeasurement of deferred tax balances.

China—Bohai Bay

Gross production from the Peng Lai fields in Bohai Bay is currently at approximately 40,000 barrels per day under an approved interim reservoir management plan. As previously announced, we and the China National Offshore Oil Corp. (CNOOC) reached an agreement with China’s Ministry of Agriculture (MOA) to resolve fishery-related issues in connection with the seepage incidents. Under this agreement, we paid approximately $160 million to settle public claims for alleged fishery damage and to fund settlement of private claims from potentially affected fishermen in relevant Bohai Bay communities. We also paid the MOA approximately $16 million to fund work to improve fishery resources and for related projects in the area. We hold a 49 percent ownership interest in the Peng Lai fields. A revised environmental impact assessment and overall development program have been submitted to the appropriate government agencies as part of the process for returning the field to normal operation. In late April, we and CNOOC reached agreement with China’s State Oceanic Administration (SOA) to resolve outstanding claims related to the 2011 seepage incidents. Under the terms of the agreement, we agreed to pay $173 million to the SOA over the next two years. We also agreed to contribute $18 million by December 2014 toward social projects benefiting Bohai Bay. As a result of this agreement, we expect to reflect an $89 million after-tax charge in our second quarter 2012 earnings.

E&P Production

In E&P, we expect our 2012 production will be approximately 1.55 million to 1.60 million BOE per day, dependent on the timing of asset dispositions. We expect production in the second quarter of 2012 to be negatively impacted by approximately 70,000 to 90,000 BOE per day due to turnaround activity in our international assets and the impact of dispositions. Normal seasonal factors will also impact the quarter.

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,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “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 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, bitumen, natural gas, LNG and natural gas liquids prices, refining and marketing margins and margins for our chemicals business.

•

Potential failures 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 reserves and 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 chemicals products.

•

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

•

Inability to timely obtain or maintain permits, including those necessary for drilling and/or development projects, 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, terrorism or cyber attacks.

•

International monetary conditions and exchange controls.

•

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

•

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

•

Liability resulting from litigation.

•

General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas, LNG, 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.

•

Delays in, or our inability to implement, our asset disposition plan.

•

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 effect of restructuring or reorganization of business components.

•

The effect of separation of our downstream businesses.

•

The factors generally described in Item 1A—Risk Factors in our 2011 Annual Report on Form 10-K.

Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the three months ended March 31, 2012, does not differ materially from that discussed under Item 7A in our 2011 Annual Report on Form 10-K.

Item 4.

CONTROLS AND PROCEDURES

As of March 31, 2012, with the participation of our management, our Chairman, President 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 ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman, President and Chief Executive Officer and our Senior Vice President, Finance and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of March 31, 2012.

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

PART II. OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the first quarter of 2012 and any material developments with respect to matters previously reported in ConocoPhillips’ 2011 Annual Report on Form 10-K. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings was 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 SEC regulations.

Our U.S. refineries are implementing two separate consent decrees regarding alleged violations of the Federal Clean Air Act with the 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 that 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

ConocoPhillips recently received notice the EPA will be seeking penalties of approximately $150,000 relating to allegations that the company did not immediately notify the EPA of certain releases in 2010 and 2011 at the Wood River Refinery. We are working with the EPA to resolve this matter.

Matters Previously Reported

In 2009, ConocoPhillips notified the EPA and the U.S. Department of Justice that it had self-identified certain compliance issues related to Benzene Waste Operations National Emission Standard for Hazardous Air Pollutants requirements at its facilities in Trainer, Pennsylvania, and Borger, Texas. In a Third Amendment to the consent decree in Civil Action No. H-05-258, ConocoPhillips agreed to pay penalties of $249,000 for the self-identified items at Borger, Texas, and $98,000 for the self-identified items at Trainer, Pennsylvania. This Amendment was entered by the court on April 13, 2012, and penalties have been paid. These compliance issues are now resolved.

Item 1A.

RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A of our 2011 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
Period	Total Number of Shares Purchased *		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs **		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs

January 1-31, 2012		6,802,323	$	71.97		6,801,700	$	9,510
February 1-29, 2012		5,560,816		71.88		5,560,100		9,111
March 1-31, 2012		13,081,609		77.23		13,075,200		8,101

Total		25,444,748	$	74.66		25,437,000

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

On December 2, 2011, we announced a share repurchase program for up to $10 billion of common stock over the next two years. Acquisitions for the share repurchase program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Repurchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares.

Item 6.

EXHIBITS



10*		Form of Stock Option Award Agreement under the ConocoPhillips Stock Option and Stock Appreciation Rights Program.

12*		Computation of Ratio of Earnings to Fixed Charges.

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

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

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

101.INS*		XBRL Instance Document.

101.SCH*		XBRL Schema Document.

101.CAL*		XBRL Calculation Linkbase Document.

101.LAB*		XBRL Labels Linkbase Document.

101.PRE*		XBRL Presentation Linkbase Document.

101.DEF*		XBRL Definition Linkbase Document.

* Filed herewith.

SIGNATURE

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

CONOCOPHILLIPS

/s/ Glenda M. Schwarz

Glenda M. Schwarz

Vice President and Controller

(Chief Accounting and Duly Authorized Officer)

April 30, 2012