Edgar Filing: CONOCOPHILLIPS

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, 2013

or

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

For the transition period from to

Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

Delaware

01-0562944

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

600 North Dairy Ashford, Houston, TX 77079

(Address of principal executive offices) (Zip Code)

281-293-1000

(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

The registrant had 1,222,661,180 shares of common stock, $.01 par value, outstanding at March 31, 2013.

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		25

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		29

Item 3. Quantitative and Qualitative Disclosures About Market Risk		48

Item 4. Controls and Procedures		48

Part II – Other Information

Item 1. Legal Proceedings		49

Item 1A. Risk Factors		49

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		49

Item 6. Exhibits		50

Signature		51

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS


Consolidated Income Statement		ConocoPhillips


	Millions of Dollars
	Three Months Ended March 31
	2013		2012

Revenues and Other Income
Sales and other operating revenues	$	14,166		14,593
Equity in earnings of affiliates		362		490
Gain on dispositions		58		940
Other income		65		60

Total Revenues and Other Income		14,651		16,083


Costs and Expenses
Purchased commodities		5,834		6,078
Production and operating expenses		1,687		1,559
Selling, general and administrative expenses		165		326
Exploration expenses		277		675
Depreciation, depletion and amortization		1,807		1,571
Impairments		2		214
Taxes other than income taxes		892		1,095
Accretion on discounted liabilities		106		105
Interest and debt expense		130		190
Foreign currency transaction (gains) losses		(36)		5

Total Costs and Expenses		10,864		11,818

Income from continuing operations before income taxes		3,787		4,265
Provision for income taxes		1,763		2,086

Income From Continuing Operations		2,024		2,179
Income from discontinued operations*		129		776

Net income		2,153		2,955
Less: net income attributable to noncontrolling interests		(14)		(18)

Net Income Attributable to ConocoPhillips	$	2,139		2,937


Amounts Attributable to ConocoPhillips Common Shareholders:
Income from continuing operations	$	2,010		2,163
Income from discontinued operations		129		774

Net Income	$	2,139		2,937


Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic
Continuing operations	$	1.64		1.69
Discontinued operations		0.10		0.60

Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	1.74		2.29

Diluted
Continuing operations	$	1.63		1.67
Discontinued operations		0.10		0.60

Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	1.73		2.27


Dividends Paid Per Share of Common Stock (dollars)	$	0.66		0.66


Average Common Shares Outstanding (in thousands)
Basic		1,229,232		1,283,493
Diluted		1,235,907		1,293,104

*Net of provision for income taxes on discontinued operations of:	$	*(9)*		434

See Notes to Consolidated Financial Statements.


Consolidated Statement of Comprehensive Income		ConocoPhillips


	Millions of Dollars
	Three Months Ended March 31
	2013		2012


Net Income	$	2,153		2,955
Other comprehensive income (loss)
Defined benefit plans
Prior service cost arising during the period		-		-
Reclassification adjustment for amortization of prior service credit included in net income		(1)		(1)

Net change		(1)		(1)

Net actuarial loss arising during the period		-		-
Reclassification adjustment for amortization of net actuarial losses included in net income		57		78

Net change		57		78
Nonsponsored plans*		1		3
Income taxes on defined benefit plans		(22)		(29)

Defined benefit plans, net of tax		35		51

Foreign currency translation adjustments		(644)		852
Reclassification adjustment for gain (loss) included in net income		(4)		1
Income taxes on foreign currency translation adjustments		4		(19)

Foreign currency translation adjustments, net of tax		(644)		834

Hedging activities		-		1
Income taxes on hedging activities		-		-

Hedging activities, net of tax		-		1

Other Comprehensive Income (Loss), Net of Tax		(609)		886

Comprehensive Income		1,544		3,841
Less: comprehensive income attributable to noncontrolling interests		(14)		(18)

Comprehensive Income Attributable to ConocoPhillips	$	1,530		3,823

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

See Notes to Consolidated Financial Statements.


Consolidated Balance Sheet		ConocoPhillips


	Millions of Dollars
	March 31 2013		December 31 2012
Assets
Cash and cash equivalents	$	5,422		3,618
Short-term investments*		23		-
Restricted cash		-		748
Accounts and notes receivable (net of allowance of $10 million in 2013 and $10 million in 2012)		8,703		8,929
Accounts and notes receivable—related parties		195		253
Inventories		1,133		965
Prepaid expenses and other current assets		8,759		9,476

Total Current Assets		24,235		23,989
Investments and long-term receivables		23,315		23,489
Loans and advances—related parties		1,455		1,517
Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $59,518 million in 2013 and $58,916 million in 2012)		67,890		67,263
Other assets		885		886

Total Assets	$	117,780		117,144


Liabilities
Accounts payable	$	9,554		9,154
Accounts payable—related parties		867		859
Short-term debt		1,351		955
Accrued income and other taxes		3,658		3,366
Employee benefit obligations		432		742
Other accruals		2,453		2,367

Total Current Liabilities		18,315		17,443
Long-term debt		20,319		20,770
Asset retirement obligations and accrued environmental costs		8,650		8,947
Joint venture acquisition obligation—related party		2,610		2,810
Deferred income taxes		13,607		13,185
Employee benefit obligations		3,271		3,346
Other liabilities and deferred credits		1,768		2,216

Total Liabilities		68,540		68,717


Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2013—1,764,891,853 shares; 2012—1,762,247,949 shares)
Par value		18		18
Capital in excess of par		45,425		45,324
Treasury stock (at cost: 2013—542,230,673 shares; 2012—542,230,673 shares)		(36,780)		(36,780)
Accumulated other comprehensive income		3,478		4,087
Retained earnings		36,662		35,338

Total Common Stockholders’ Equity		48,803		47,987
Noncontrolling interests		437		440

Total Equity		49,240		48,427

Total Liabilities and Equity	$	117,780		117,144

*Marketable securities.

See Notes to Consolidated Financial Statements.


Consolidated Statement of Cash Flows		ConocoPhillips


	Millions of Dollars
	Three Months Ended March 31
	2013		2012

Cash Flows From Operating Activities
Net income	$	2,153		2,955
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		1,807		1,571
Impairments		2		214
Dry hole costs and leasehold impairments		36		518
Accretion on discounted liabilities		106		105
Deferred taxes		241		131
Undistributed equity earnings		(29)		(77)
Gain on dispositions		(58)		(940)
Income from discontinued operations		(129)		(776)
Other		(503)		173
Working capital adjustments
Decrease in accounts and notes receivable		249		166
Decrease (increase) in inventories		(177)		83
Decrease (increase) in prepaid expenses and other current assets		(131)		79
Increase (decrease) in accounts payable		528		(55)
Increase (decrease) in taxes and other accruals		513		(77)

Net cash provided by continuing operating activities		4,608		4,070
Net cash provided by discontinued operations		122		112

Net Cash Provided by Operating Activities		4,730		4,182


Cash Flows From Investing Activities
Capital expenditures and investments		(3,391)		(3,818)
Proceeds from asset dispositions		1,134		1,102
Net sales (purchases) of short-term investments		(23)		92
Collection of advances/loans—related parties		57		38
Other		(21)		7

Net cash used in continuing investing activities		(2,244)		(2,579)
Net cash used in discontinued operations		(189)		(431)

Net Cash Used in Investing Activities		(2,433)		(3,010)


Cash Flows From Financing Activities
Repayment of debt		(48)		(47)
Change in restricted cash		748		-
Issuance of company common stock		(10)		36
Repurchase of company common stock		-		(1,899)
Dividends paid		(815)		(843)
Other		(205)		(199)

Net cash used in continuing financing activities		(330)		(2,952)
Net cash used in discontinued operations		-		(318)

Net Cash Used in Financing Activities		(330)		(3,270)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		(163)		25


Net Change in Cash and Cash Equivalents		1,804		(2,073)
Cash and cash equivalents at beginning of period		3,618		5,780

Cash and Cash Equivalents at End of Period	$	5,422		3,707

See Notes to Consolidated Financial Statements.


Notes to Consolidated Financial Statements		ConocoPhillips

Note 1—Basis of Presentation

The interim-period financial information presented in the financial statements included in this report is unaudited and, in the opinion of management, includes all known accruals and adjustments 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 unless otherwise disclosed. 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 2012 Annual Report on Form 10-K.

As a result of our separation of Phillips 66 on April 30, 2012, the results of operations for our former refining, marketing and transportation businesses; most of our former Midstream segment; our former Chemicals segment; and our power generation and certain technology operations included in our former Emerging Businesses segment (collectively, our “Downstream business”), have been classified as discontinued operations for the period ended March 31, 2012. In addition, the results of operations for our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and our Algerian and Nigerian businesses have been classified as discontinued operations for all periods presented. See Note 3—Discontinued Operations, for additional information. Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements relates to our continuing operations.

Note 2—Change in Accounting Principles

Effective January 1, 2013, we early adopted, on a prospective basis, Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2013-05, “Parent’s Accounting for the Cumulative Translation Adjustment (CTA) upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity.” This ASU resolves the diversity in practice about whether FASB Accounting Standards Codification (ASC) Subtopic 810-10, “Consolidation—Overall,” or Subtopic 830-30, “Foreign Currency Matters—Translation of Financial Statements,” applies to the release of the CTA into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a nonprofit activity or a business (other than a sale of in substance real estate or conveyance of oil and gas mineral rights) within a foreign entity. This ASU clarifies that ASC Subtopic 830-30 applies to sales within a foreign entity and thus the CTA should not be released into net income unless those sales represent the complete or substantially complete liquidation of the reporting parent’s investment in the broader foreign entity. This ASU also requires the release of all the related CTA into net income upon gaining control in a step acquisition of an equity method investment that is considered to be a standalone foreign entity, and a pro rata release of the related CTA into net income upon a partial sale of an interest in an equity method investment that is considered to be a standalone foreign entity.

Note 3—Discontinued Operations

Separation of Downstream Business

On April 30, 2012, the separation of our Downstream business was completed, creating two independent energy companies: ConocoPhillips and Phillips 66. In connection with the separation, Phillips 66 distributed approximately $7.8 billion to us in a special cash distribution. The principal funds from the special cash distribution were designated solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, within twelve months following the distribution. The cash was included in the “Restricted cash” line on our consolidated balance sheet. No balance remained from the cash distribution as of March 31, 2013. We also entered into several agreements with Phillips 66 in order to effect the separation and govern our relationship with Phillips 66.

Sales and other operating revenues and income from discontinued operations related to Phillips 66 for the three-month period ended March 31, 2012, were as follows:


	Millions of Dollars

Sales and other operating revenues from discontinued operations	$	45,498


Income from discontinued operations before-tax	$	1,008
Income tax expense		294

Income from discontinued operations	$	714

Income from discontinued operations after-tax includes transaction, information systems and other costs incurred to effect the separation of $44 million for the three-month period ended March 31, 2012. No separation costs were incurred during the first three months of 2013.

Prior to the separation, commodity sales to Phillips 66 were $4,054 million and commodity purchases from Phillips 66 were $160 million for the three-month period ended March 31, 2012. Prior to May 1, 2012, commodity sales and related costs were eliminated in consolidation between ConocoPhillips and Phillips 66. Beginning May 1, 2012, these revenues and costs represent third-party transactions with Phillips 66.

Other Discontinued Operations

As part of our ongoing strategic asset disposition program, we agreed to sell our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and our Algerian and Nigerian businesses (collectively, the “Disposition Group”). The Disposition Group was previously part of the Other International operating segment.

On November 26, 2012, we notified government authorities in Kazakhstan and co-ventures of our intent to sell the Company’s 8.4 percent interest in Kashagan to ONGC Videsh Limited. Expected proceeds are approximately $5.0 billion, which represents the purchase price plus expected working capital and customary adjustments at closing. The transaction is expected to close in 2013. We recorded pre-tax impairments of $606 million and $43 million in the fourth quarter of 2012 and first quarter of 2013, respectively. At March 31, 2013, the carrying value of the net assets related to our interest in Kashagan was $5.1 billion, net of impairments.

On December 18, 2012, we entered into an agreement with Pertamina to sell our wholly owned subsidiary, ConocoPhillips Algeria Ltd., for a total of $1.75 billion plus customary adjustments. The transaction is anticipated to close in 2013. We received a deposit of $175 million in December 2012. The deposit is refundable in the event our co-venturer exercises its preemptive rights, which have been waived, or government approval is not received. At March 31, 2013, the net carrying value of our Algerian assets was $698 million.

On December 20, 2012, we entered into agreements with affiliates of Oando PLC to sell our Nigerian business unit for a total of $1.79 billion plus customary adjustments. The transaction is anticipated to close in 2013, following appropriate consultations with stakeholders. We received a deposit of $435 million in December 2012. The deposit is only refundable in the event of default by us. At March 31, 2013, the net carrying value of our Nigerian assets was $317 million.

At March 31, 2013, the Disposition Group met the criteria to be classified as held for sale. Accordingly, we classified $22 million of loans and advances to related parties in the “Accounts and notes receivable—related parties” line and $7,058 million of noncurrent assets in the “Prepaid expenses and other current assets” line of our consolidated balance sheet. In addition, we classified $777 million of noncurrent liabilities in the “Accrued income and other taxes” line and $133 million of asset retirement obligations in the “Other accruals” line of our consolidated balance sheet. The carrying amounts of the major classes of assets and liabilities associated with the Disposition Group were as follows:


	Millions of Dollars
		March 31 2013	December 31 2012

Assets
Accounts and notes receivable	$	302	268
Accounts and notes receivable—related parties		2	1
Inventories		48	44
Prepaid expenses and other current assets		154	220

Total current assets of discontinued operations		506	533
Investments and long-term receivables		281	272
Loans and advances—related parties		22	29
Net properties, plants and equipment		6,775	6,629
Other assets		2	4

Total assets of discontinued operations	$	7,586	7,467


Liabilities
Accounts payable	$	437	471
Accrued income and other taxes		154	125

Total current liabilities of discontinued operations		591	596
Asset retirement obligations and accrued environmental costs		133	131
Deferred income taxes		777	759

Total liabilities of discontinued operations	$	1,501	1,486

Sales and other operating revenues and income from discontinued operations related to the Disposition Group were as follows:


	Millions of Dollars
	Three Months Ended March 31
		2013		2012


Sales and other operating revenues from discontinued operations	$	329		391


Income from discontinued operations before-tax	$	120		202
Income tax expense (benefit)		(9	)	140

Income from discontinued operations	$	129		62

Note 4—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 VIEs follows:

Freeport LNG Development, L.P. (Freeport LNG)

We have an agreement with 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, which expires in 2033. The terminal became operational in June 2008, and we began making payments under the terminal use agreement. At March 31, 2013, the prepaid balance of the terminal use agreement was $244 million, which is primarily reflected in the “Other assets” line on our consolidated balance sheet. Freeport LNG began making loan repayments in September 2008, and the loan balance outstanding was $551 million at March 31, 2013, and $565 million at December 31, 2012.

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. Since we do not have the unilateral power to direct the key activities which most significantly impact its economic performance, we are not the primary beneficiary of Freeport LNG. These key activities primarily involve or relate to operating and maintaining the terminal. We also 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.

Australia Pacific LNG (APLNG)

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. We are not the primary beneficiary of APLNG because we share with Origin Energy and China Petrochemical Corporation (Sinopec) the power to direct the key activities of APLNG that most significantly impact its economic performance, which involve activities related to the production and commercialization of coalbed methane, as well as LNG processing and export marketing. As a result, we do not consolidate APLNG, and it is accounted for as an equity method investment.

As of March 31, 2013, we have not provided, nor do we expect to provide in the future, any financial support to APLNG other than amounts previously contractually required. In addition, unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of APLNG. See Note 7—Investments, Loans and Long-Term Receivables, and Note 13—Guarantees, for additional information.

Note 5—Inventories

Inventories consisted of the following:


	Millions of Dollars
		March 31 2013	December 31 2012

Crude oil and petroleum products	$	396	244
Materials, supplies and other		737	721

	$	1,133	965

Inventories valued on the last-in, first-out (LIFO) basis totaled $293 million and $147 million at March 31, 2013, and December 31, 2012, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was approximately $200 million at both March 31, 2013, and December 31, 2012.

Note 6—Assets Held for Sale or Sold

Our interest in Kashagan and the Algerian and Nigerian business units were considered held for sale at March 31, 2013. These assets are classified as discontinued operations. See Note 3—Discontinued Operations, for additional information.

In March 2013, we sold the majority of our properties in the Cedar Creek Anticline for $989 million and recognized a before-tax loss on disposition of $62 million, which was included in the “Gain on dispositions” line on our consolidated income statement. At the time of the disposition, the carrying value of our interest, which was included in the Lower 48 and Latin America segment, was $1,051 million, which included $1,079 million of properties, plants and equipment (PP&E) and $28 million of asset retirement obligations.

Note 7—Investments, Loans and Long-Term Receivables

APLNG

In the fourth quarter of 2012, APLNG satisfied all conditions precedent to drawdown from the $8.5 billion project finance facility. The facility is comprised of financing agreements executed by APLNG with the Export-Import Bank of the United States for approximately $2.9 billion, the Export-Import Bank of China for approximately $2.7 billion, and a syndicate of Australian and international commercial banks for approximately $2.9 billion. In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata share of the project finance facility until the project achieves financial completion. See Note 13—Guarantees, for additional information.

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. See Note 4—Variable Interest Entities (VIEs), for additional information.

At March 31, 2013, the book value of our equity method investment in APLNG was $10,402 million, which included $2,595 million of cumulative translation effects due to strengthening of the Australian dollar relative to the U.S. dollar over time, and is included in the “Investments and long-term receivables” line on our consolidated balance sheet.

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, 2013, included the following:

—

$551 million in loan financing to Freeport LNG.

—

$1,050 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 our consolidated balance sheet, while the short-term portion is in “Accounts and notes receivable—related parties.”

Note 8—Suspended Wells

The capitalized cost of suspended wells at March 31, 2013, was $1,239 million, an increase of $201 million from $1,038 million at year-end 2012. No suspended wells were charged to dry hole expense during the first three months of 2013 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2012.

Note 9—Impairments

During the three-month periods of 2013 and 2012, we recognized the following before-tax impairment charges:


	Millions of Dollars
	Three Months Ended March 31
		2013	2012

Canada	$	-	213
Europe		-	1
Asia Pacific and Middle East		2	-

	$	2	214

The first quarter of 2012 included a $213 million property impairment in our Canada 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. We also recorded a $481 million impairment for the undeveloped leasehold costs associated with the project, which was included in the “Exploration expenses” line on our consolidated income statement.

Note 10—Debt

We have two commercial paper programs supported by our $7.5 billion revolving credit facility: the ConocoPhillips $6.35 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $1.15 billion commercial paper program, which is used to fund commitments relating to QG3. Commercial paper maturities are generally limited to 90 days.

At March 31, 2013 and December 31, 2012, we had no direct outstanding borrowings or letters of credit issued under our revolving credit facilities. In addition, under the ConocoPhillips Qatar Funding Ltd. commercial paper program, there was $1,008 million of commercial paper outstanding at March 31, 2013, compared with $1,055 million at December 31, 2012. Since we had $1,008 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.5 billion in borrowing capacity under our revolving credit facilities at March 31, 2013.

At March 31, 2013, we classified $920 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 April 2013, we repaid the following debt instruments at maturity:

—

The $100 million 7.625% Debentures due 2013.

—

The $750 million 5.50% Notes due 2013.

Note 11—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 $782 million was short-term and was included in the “Accounts payable—related parties” line on our March 31, 2013, consolidated balance sheet. The principal portion of these payments, which totaled $189 million in the first three months of 2013, 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 12—Noncontrolling Interests

Activity attributable to common stockholders’ equity and noncontrolling interests for the first three months of 2013 and 2012 was as follows:


	Millions of Dollars
	2013				2012
		Common Stockholders’ Equity	Non- Controlling Interest	Total Equity		Common Stockholders’ Equity	Non- Controlling Interest	Total Equity

Balance at January 1	$	47,987	440	48,427		65,239	510	65,749
Net income		2,139	14	2,153		2,937	18	2,955
Dividends		(815)	-	(815)		(843)	-	(843)
Repurchase of company common stock		-	-	-		(1,899)	-	(1,899)
Distributions to noncontrolling interests		-	(17)	(17)		-	(19)	(19)
Other changes, net*		(508)	-	(508)		1,115	-	1,115

Balance at March 31	$	48,803	437	49,240		66,549	509	67,058

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

Note 13—Guarantees

At March 31, 2013, 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.

APLNG Guarantees

At March 31, 2013, we have outstanding multiple guarantees in connection with our 37.5 percent ownership interest in APLNG. The following is a description of the guarantees with values calculated utilizing March 2013 exchange rates:

—

We have guaranteed APLNG’s performance with regard to a construction contract executed in connection with APLNG’s issuance of the Train 1 and Train 2 Notices to Proceed. We estimate the remaining term of this guarantee is 4 years. Our maximum potential amount of future payments related to this guarantee is approximately $110 million and would become payable if APLNG cancels the applicable construction contract and does not perform with respect to the amounts owed to the contractor.

—

We have issued a construction completion guarantee related to the third-party project financing secured by APLNG. Our maximum potential amount of future payments under the guarantee is estimated to be $3.2 billion, which could be payable if the full debt financing capacity is utilized and completion of the project is not achieved. Our guarantee of the project financing will be released upon meeting certain completion milestones, which we estimate would occur beginning in 2016. Our maximum exposure at March 31, 2013, is $1.7 billion based upon our pro-rata share of the facility used at that date. At March 31, 2013, the carrying value of this guarantee is approximately $114 million.

—

In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy in October 2008, we agreed to guarantee an existing obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of 4 to 19 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1.0 billion ($2.4 billion in the event of intentional or reckless breach), and would 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.

—

We have guaranteed the performance of APLNG with regard to certain other contracts executed in connection with the project’s continued development. The guarantees have remaining terms of up to 33 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $180 million and would become payable if APLNG does not perform.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $280 million, which consist primarily of guarantees of the residual value of leased corporate aircraft, guarantees to fund the short-term cash liquidity deficit of two joint ventures, a guarantee for our portion of a joint venture’s debt obligations and a guarantee of minimum charter revenue for an LNG vessel. These guarantees have remaining terms of up to 11 years or the life of the venture and would become payable, if upon sale, certain asset values are lower than guaranteed amounts, business conditions decline at guaranteed entities or as a result of non-performance of contractual terms by guaranteed parties.

Indemnifications

Over the years, we have entered into various lease agreements or agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. Agreements associated with these leases and 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, 2013, was approximately $70 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 approximately $50 million of environmental accruals for known contamination that are included in the “Asset retirement obligations and accrued environmental costs” line on our consolidated balance sheet. For additional information about environmental liabilities, see Note 14—Contingencies and Commitments.

In connection with the separation of the Downstream business, the Company entered into an Indemnification and Release Agreement with Phillips 66. See Note 3—Discontinued Operations, for additional information. This agreement provided for cross-indemnities between Phillips 66 and ConocoPhillips and established procedures for handling claims subject to indemnification and related matters. We evaluated the impact of the indemnifications given and the Phillips 66 indemnifications received as of the separation date and concluded those fair values were immaterial.

Note 14—Contingencies and Commitments

A number of lawsuits involving a variety of claims arising in the ordinary course of business have been made against ConocoPhillips. 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. With respect to 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, 2013, our

balance sheet included a total environmental accrual of $350 million, compared with $364 million at December 31, 2012. 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, 2013, we had performance obligations secured by letters of credit of $782 million (issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, commercial activities and services 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, Petróleos de Venezuela S.A. (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 anticipate an interim decision on key legal and factual issues in 2013.

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 the ICSID tribunal, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the 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. On April 24, 2012, Ecuador filed a supplemental counterclaim asserting environmental damages, which we believe are not material. The ICSID tribunal issued a decision on liability on December 14, 2012, in favor of Burlington, finding that Ecuador’s seizure of Blocks 7 and 21 was an unlawful expropriation in violation of the Ecuador-U.S. Bilateral Investment Treaty. An additional arbitration phase is now proceeding to determine the damages owed to ConocoPhillips for Ecuador’s actions.

ConocoPhillips served a Notice of Arbitration on the Timor-Leste Minister of Finance in October 2012 for outstanding disputes related to a series of tax assessments. Between 2010 and 2012, ConocoPhillips has paid, under protest, tax assessments totaling approximately $227 million, which are primarily recorded in the “Investments and long-term receivables” line on our consolidated balance sheet. The arbitration will be conducted in Singapore under the United Nations Commission on International Trade Laws (UNCITRAL) arbitration rules, pursuant to the terms of the Tax Stability Agreement with the Timor-Leste government. The arbitration process is currently underway. Future impacts on our business are not known at this time.

Note 15—Derivative and Financial Instruments

Derivative Instruments

We use futures, forwards, swaps and options in various markets to meet our customer needs and capture market opportunities. Our commodity business primarily consists of natural gas, crude oil, bitumen, LNG and natural gas liquids. Under our current business model, we are not required to register as a Swap Dealer or Major Swap Participant.

Our derivative instruments are held at fair value on our consolidated balance sheet. Where these balances have the right of setoff, they are presented net. Related cash flows are recorded as operating activities on the consolidated statement of cash flows. On the consolidated income statement, realized and unrealized gains and losses are recognized either on a gross basis if directly related to our physical business or a net basis if held for trading. Gains and losses related to contracts that meet and are designated with the normal purchase normal sale exception are recognized upon settlement. We generally apply this exception to eligible crude contracts. We do not use hedge accounting for our commodity derivatives.

The following table presents the gross fair values of our commodity derivatives, excluding collateral, and the line items where they appear on our consolidated balance sheet:


	Millions of Dollars
	March 31 2013		December 31 2012

Assets
Prepaid expenses and other current assets	$	1,402		1,538
Other assets		98		105
Liabilities
Other accruals		1,461		1,509
Other liabilities and deferred credits		94		99

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
	2013		2012

Sales and other operating revenues	$	(208)		(403)
Other income		2		(6)
Purchased commodities		185		398

The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts.


	Open Position Long/(Short)
	March 31 2013		December 31 2012

Natural gas and power (billions of cubic feet equivalent)
Fixed price		(22)		(48)
Basis		(1)		125

Foreign Currency Exchange Derivatives

We have foreign currency exchange rate risk resulting from international operations. Our foreign currency exchange derivative activity primarily consists of transactions designed to mitigate our cash-related and 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. We do not elect hedge accounting on our foreign currency exchange derivatives.

The following table presents the gross fair values of our foreign currency exchange derivatives, excluding collateral, and the line items where they appear on our consolidated balance sheet:


	Millions of Dollars
	March 31 2013		December 31 2012

Assets
Prepaid expenses and other current assets	$	12		32
Liabilities
Other accruals		5		2
Other liabilities and deferred credits		-		1

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


	Millions of Dollars
	Three Months Ended March 31
	2013		2012


Foreign currency transaction (gains) losses	$	22		(15)

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


	In Millions Notional Currency
	March 31 2013		December 31 2012


Sell U.S. dollar, buy other currencies*	USD	-		2,573
Buy U.S. dollar, sell other currencies**	USD	842		140
Buy British pound, sell euro	GBP	11		-
Buy euro, sell British pound	EUR	-		96

*Primarily euro, Canadian dollar, Norwegian krone and British pound.

**Primarily euro, Canadian dollar and Norwegian krone.

Financial Instruments

We have certain financial instruments on the consolidated balance sheet related to interest bearing time deposits and commercial paper. These held-to-maturity financial instruments are included in “Cash and cash equivalents” on our consolidated balance sheet if the maturities at the time we made the investments were 90 days or less; otherwise, these investments are included in “Short-term investments” on our consolidated balance sheet.

These balances consisted of the following:


	Millions of Dollars
	Carrying Amount
	Cash and Cash Equivalents				Short-Term Investments
	March 31 2013		December 31 2012		March 31 2013		December 31 2012


Cash	$	681		829		-		-
Time Deposits		4,741		2,789		-		-
Commercial Paper		-		-		23		-

	$	5,422		3,618		23		-

In conjunction with the separation of our Downstream business, we received a special cash distribution from Phillips 66. See Note 3—Discontinued Operations, for additional information. The balance of the special cash distribution was zero at March 31, 2013, and $748 million at December 31, 2012, and was included in “Restricted cash” on our consolidated balance sheet. At December 31, 2012, the funds in the restricted cash account were invested in money market funds with maturities within 90 days from December 31, 2012.

Credit Risk

Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, over-the-counter (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, such as certain transactions administered through the New York Mercantile Exchange or the IntercontinentalExchange.

The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on March 31, 2013, and December 31, 2012, was $143 million and $130 million, respectively. For these instruments, no collateral was posted as of March 31, 2013 or December 31, 2012. If our credit rating had been lowered one level from its “A” rating (per Standard and Poor’s) on March 31, 2013, we would be required to post no additional collateral to our counterparties. If we had been downgraded below investment grade, we would be required to post $143 million of additional collateral, either with cash or letters of credit.

Note 16—Fair Value Measurement

We carry a portion of our assets and liabilities at fair value that are measured at a reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclosed according to the quality of valuation inputs under the following hierarchy:

—

Level 1: Quoted prices (unadjusted) in an active market for identical assets or liabilities.

—

Level 2: Inputs other than quoted prices which are directly or indirectly observable.

—

Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities.

The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities that are initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. Transfers occur at the end of the reporting period. There were no material transfers in or out of Level 1.

Recurring Fair Value Measurement

Financial assets and liabilities reported at fair value on a recurring basis primarily include commodity derivatives and certain investments to support nonqualified deferred compensation plans. The deferred compensation investments are measured at fair value using unadjusted prices available from national securities exchanges; therefore, these assets are categorized as Level 1 in the fair value hierarchy. Level 1 derivative assets and liabilities primarily represent exchange-traded futures and options that are valued using unadjusted prices available from the underlying exchange. Level 2 derivative assets and liabilities primarily represent OTC swaps, options and forward purchase and sale contracts that are valued using adjusted exchange prices, prices provided by brokers or pricing service companies that are all corroborated by market data. Level 3 derivative assets and liabilities consist of OTC swaps, options and forward purchase and sale contracts that are long term in nature and where a significant portion of fair value is calculated from underlying market data that is not readily available. The derived value uses industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value. Level 3 activity was not material.

The following table summarizes the fair value hierarchy for gross financial assets and liabilities (i.e., unadjusted where the right of setoff exists for commodity derivatives accounted for at fair value on a recurring basis):


	Millions of Dollars
	March 31, 2013								December 31, 2012
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total

Assets
Deferred compensation investments	$	309		-		-		309		305		-		-		305
Commodity derivatives		972		512		13		1,497		1,052		567		18		1,637

Total assets	$	1,281		512		13		1,806		1,357		567		18		1,942

Liabilities
Commodity derivatives	$	990		561		1		1,552		1,031		567		4		1,602

Total liabilities	$	990		561		1		1,552		1,031		567		4		1,602

The following table summarizes those commodity derivative balances subject to the right of setoff as presented on our consolidated balance sheet:


	Millions of Dollars
	Gross Amounts Recognized		Gross Amounts Offset		Net Amounts Excluding Collateral		Cash Collateral		Net Amounts Subject to Setoff

March 31, 2013
Assets	$	1,475		1,304		171		29		142
Liabilities		1,523		1,304		219		56		163


December 31, 2012
Assets	$	1,621		1,403		218		29		189
Liabilities		1,588		1,403		185		16		169

At March 31, 2013 and December 31, 2012, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.

Non-Recurring Fair Value Measurement

We recorded a pre-tax loss of $43 million to reduce net PP&E (held for sale) to fair value. As of March 31, 2013, the fair value less costs to sell was $5,070 million. Since the fair value was determined by the negotiated selling price, it is classified as Level 1 in the fair value hierarchy. See Note 3—Discontinued Operations, for additional information.

Reported Fair Values of Financial Instruments

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

—

Cash and cash equivalents, restricted cash and short-term investments: The carrying amount reported on the balance sheet approximates fair value.

—

Accounts and notes receivable (including long-term and related parties): The carrying amount reported on the balance sheet approximates fair value. The valuation technique and methods used to estimate the fair value of the current portion of fixed-rate related party loans is consistent with Loans and advances—related parties.

—

Loans and advances—related parties: The carrying amount of floating-rate loans approximates fair value. The fair value of fixed-rate loan activity is measured using market observable data and is categorized as Level 2 in the fair value hierarchy. See Note 7—Investments, Loans and Long-Term Receivables, for additional information.

—

Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts payable and floating-rate debt reported on the balance sheet approximates fair value. The valuation technique and methods used to estimate the fair value of the current portion of the joint venture acquisition obligation is consistent with the methodology below.

—

Fixed-rate debt: The estimated fair value of fixed-rate debt is measured using prices available from a pricing service that is corroborated by market data; therefore, these liabilities are categorized as Level 2 in the fair value hierarchy.

—

Joint venture acquisition obligation—related party: Fair value is estimated based on the net present value of the future cash flows as a Level 2 fair value. At March 31, 2013 and December 31, 2012, effective yield rates were 0.66 percent and 0.7 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 11—Joint Venture Acquisition Obligation, for additional information.

The following table summarizes the net fair value of financial instruments (i.e., adjusted where the right of setoff exists for commodity derivatives):

Millions of Dollars

Carrying Amount

Fair Value

March 31

2013

December 31

2012

March 31

2013

December 31

2012

Financial assets

Deferred compensation investments

309

305

309

305

Commodity derivatives

181

221

181

221

Total loans and advances—related parties

1,629

1,697

1,820

1,916

Financial liabilities

Total debt, excluding capital leases

21,654

21,709

25,855

26,349

Total joint venture acquisition obligation

3,392

3,582

3,740

3,968

Commodity derivatives

209

199

209

199

Note 17—Accumulated Other Comprehensive Income

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

Millions of Dollars

Defined

Benefit Plans

Foreign

Currency

Translation

Accumulated

Other

Comprehensive

Income (Loss)

December 31, 2012

(1,425)

5,512

4,087

Other comprehensive income (loss)

(644)

(609)

March 31, 2013

(1,390)

4,868

3,478

At March 31, 2013, $35 million of accumulated other comprehensive income, net of $22 million of income tax expense, related to our defined benefit plans was amortized. The components of the employee benefit plan-related other comprehensive income items are included in the computation of net periodic pension cost. See Note 19—Employee Benefit Plans, for additional information.

There were no items within accumulated other comprehensive income related to noncontrolling interests.

Note 18—Cash Flow Information


	Millions of Dollars
	Three Months Ended March 31
		2013		2012

Cash Payments
Interest	$	157		228
Income taxes		1,199		1,308


Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased	$	(23	)	(497	)
Short-term investments sold		–		589

	$	(23	)	92

Note 19—Employee Benefit Plans

Pension and Postretirement Plans


	Millions of Dollars
	Pension Benefits												Other Benefits
Three Months Ended	March 31												March 31
	2013						2012						2013			2012
	U.S.			Int’l.			U.S.			Int’l.
Components of Net Periodic Benefit Cost
Service cost	$	35			26			58			28			1			2
Interest cost		36			37			63			43			6			10
Expected return on plan assets		(47	)		(41	)		(74	)		(43	)		-			-
Amortization of prior service cost (credit)		1			(2	)		2			(2	)		(1	)		(1	)
Recognized net actuarial loss (gain)		38			19			59			18			1			(1	)

Net periodic benefit cost	$	63			39			108			44			7			10

In connection with the separation of the Downstream business on April 30, 2012, ConocoPhillips entered into an Employee Matters Agreement with Phillips 66 which provides that employees of Phillips 66 will no longer participate in benefit plans sponsored or maintained by ConocoPhillips upon separation. As such, changes in net periodic benefit cost included in the table above primarily relate to the employees of Phillips 66 no longer participating in the ConocoPhillips benefit plans for the three-month period ended March 31, 2013.

During the first three months of 2013, we contributed $52 million to our domestic benefit plans and $50 million to our international benefit plans.

Note 20—Related Party Transactions

We consider our equity-method investments to be related parties. Significant transactions with related parties were:


	Millions of Dollars
	Three Months Ended March 31
		2013	2012


Operating revenues and other income	$	8	23
Purchases		41	43
Operating expenses and selling, general and administrative expenses		46	40
Net interest expense*		9	11

*	We paid interest to, or received interest from, various affiliates, including FCCL Partnership. See Note 7—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

Note 21—Segment Disclosures and Related Information

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. We manage our operations through six operating segments, which are defined by geographic region: Alaska, Lower 48 and Latin America, Canada, Europe, Asia Pacific and Middle East, and Other International.

On April 30, 2012, our Downstream business was separated into a stand-alone, publicly traded corporation, Phillips 66. Results of operations for Phillips 66 for the period ended March 31, 2012, have been reported as discontinued operations. Commodity sales to Phillips 66, which were previously eliminated in consolidation prior to the separation, are now reported as third-party sales. In 2012, we also agreed to sell our Nigerian and Algerian businesses and our interest in Kashagan. Results of operations for Nigeria, Algeria and Kashagan have been reported as discontinued operations for all periods presented. For additional information, see Note 3—Discontinued Operations.

Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead, costs associated with the separation and certain technology activities, net of licensing revenues. 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
		2013	2012

Sales and Other Operating Revenues
Alaska	$	2,104	2,737

Lower 48 and Latin America		4,822	5,131
Intersegment eliminations		(29)	(115)

Lower 48 and Latin America		4,793	5,016

Canada		1,255	1,218
Intersegment eliminations		(158)	(136)

Canada		1,097	1,082

Europe		3,453	3,602
Intersegment eliminations		-	(72)

Europe		3,453	3,530

Asia Pacific and Middle East		2,218	1,896
Other International		483	310
Corporate and Other		18	22

Consolidated sales and other operating revenues	$	14,166	14,593


Net Income Attributable to ConocoPhillips
Alaska	$	543	620
Lower 48 and Latin America		133	255
Canada		133	(549)
Europe		431	389
Asia Pacific and Middle East		918	1,738
Other International		14	21
Corporate and Other		(162)	(311)
Discontinued operations		129	774

Consolidated net income attributable to ConocoPhillips	$	2,139	2,937


	Millions of Dollars
		March 31 2013	December 31 2012

Total Assets
Alaska	$	11,241	10,950
Lower 48 and Latin America		28,250	28,895
Canada		22,306	22,308
Europe		15,071	15,562
Asia Pacific and Middle East		24,038	23,721
Other International		1,462	1,418
Corporate and Other		7,826	6,823
Discontinued operations		7,586	7,467

Consolidated total assets	$	117,780	117,144

Note 22—Income Taxes

Our effective tax rate from continuing operations for the first quarter of 2013 was 47 percent compared with 49 percent for the first quarter of 2012. The decrease was primarily due to a smaller proportion of income in higher tax jurisdictions in 2013. Additionally, the tax rate for the first quarter of 2013 reflected a favorable tax resolution associated with the sale of certain western Canada properties which occurred in a prior year, and the tax rate for the first quarter of 2012 reflected a benefit from asset dispositions in 2012.

The effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.

During the first quarter of 2013, unrecognized tax benefits decreased $235 million to $637 million at March 31, 2013, mainly due to the favorable tax resolution noted above. Included in this balance is $411 million which, if recognized, would impact our effective tax rate.

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.


	Millions of Dollars
	Three Months Ended March 31, 2013
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	$	-			4,464			-		-			-			9,702			-			14,166
Equity in earnings of affiliates		2,391			2,874			-		-			-			405			(5,308	)		362
Gain (loss) on dispositions		-			(2	)		-		-			-			60			-			58
Other income		1			45			-		-			-			19			-			65
Intercompany revenues		20			51			11		22			8			1,653			(1,765	)		-

Total Revenues and Other Income		2,412			7,432			11		22			8			11,839			(7,073	)		14,651


Costs and Expenses
Purchased commodities		-			3,929			-		-			-			3,064			(1,159	)		5,834
Production and operating expenses		-			310			-		-			-			1,379			(2	)		1,687
Selling, general and administrative expenses		4			122			-		-			-			56			(17	)		165
Exploration expenses		-			143			-		-			-			134			-			277
Depreciation, depletion and amortization		-			208			-		-			-			1,599			-			1,807
Impairments		-			-			-		-			-			2			-			2
Taxes other than income taxes		-			77			-		-			-			815			-			892
Accretion on discounted liabilities		-			14			-		-			-			92			-			106
Interest and debt expense		586			83			10		19			8			11			(587	)		130
Foreign currency transaction (gains) losses		17			8			-		(22	)		(14	)		(25	)		-			(36	)

Total Costs and Expenses		607			4,894			10		(3	)		(6	)		7,127			(1,765	)		10,864

Income from continuing operations before income taxes		1,805			2,538			1		25			14			4,712			(5,308	)		3,787
Provision for income taxes		(205	)		147			-		(1	)		1			1,821			-			1,763

Income From Continuing Operations		2,010			2,391			1		26			13			2,891			(5,308	)		2,024
Income from discontinued operations		129			129			-		-			-			129			(258	)		129

Net income		2,139			2,520			1		26			13			3,020			(5,566	)		2,153
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(14	)		-			(14	)

Net Income Attributable to ConocoPhillips	$	2,139			2,520			1		26			13			3,006			(5,566	)		2,139


Comprehensive Income Attributable to ConocoPhillips	$	1,530			1,911			1		(4	)		1			2,392			(4,301	)		1,530


Income Statement	Three Months Ended March 31, 2012

Revenues and Other Income
Sales and other operating revenues	$	-			4,292			-		-			-			10,301			-			14,593
Equity in earnings of affiliates		2,514			2,701			-		-			-			462			(5,187	)		490
Gain on dispositions		-			-			-		-			-			940			-			940
Other income		1			31			-		-			-			28			-			60
Intercompany revenues		1			440			11		22			8			825			(1,307	)		-

Total Revenues and Other Income		2,516			7,464			11		22			8			12,556			(6,494	)		16,083


Costs and Expenses
Purchased commodities		-			3,807			-		-			-			2,975			(704	)		6,078
Production and operating expenses		-			267			-		-			-			1,307			(15	)		1,559
Selling, general and administrative expenses		5			263			-		-			-			66			(8	)		326
Exploration expenses		-			90			-		-			-			585			-			675
Depreciation, depletion and amortization		-			204			-		-			-			1,367			-			1,571
Impairments		-			-			-		-			-			214			-			214
Taxes other than income taxes		-			82			-		-			-			1,013			-			1,095
Accretion on discounted liabilities		-			13			-		-			-			92			-			105
Interest and debt expense		540			81			10		19			8			112			(580	)		190
Foreign currency transaction (gains) losses		-			(28	)		-		11			16			6			-			5

Total Costs and Expenses		545			4,779			10		30			24			7,737			(1,307	)		11,818

Income (loss) from continuing operations before income taxes		1,971			2,685			1		(8	)		(16	)		4,819			(5,187	)		4,265
Provision for income taxes		(190	)		171			-		6			(1	)		2,100			-			2,086

Income (Loss) From Continuing Operations		2,161			2,514			1		(14	)		(15	)		2,719			(5,187	)		2,179
Income from discontinued operations		776			776			-		-			-			777			(1,553	)		776

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 (Loss) Attributable to ConocoPhillips	$	3,823			4,176			1		19			(2	)		4,283			(8,477	)		3,823


	Millions of Dollars
	March 31, 2013
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	$	-			279		6		48			2			5,087		-			5,422
Short-term investments		-			-		-		-			-			23		-			23
Accounts and notes receivable		62			6,273		-		-			-			7,544		(4,981	)		8,898
Inventories		-			87		-		-			-			1,046		-			1,133
Prepaid expenses and other current assets		18			592		-		1			-			8,148		-			8,759

Total Current Assets		80			7,231		6		49			2			21,848		(4,981	)		24,235
Investments, loans and long-term receivables*		82,784			118,108		771		1,443			573			43,986		(222,895	)		24,770
Net properties, plants and equipment		-			8,849		-		-			-			59,041		-			67,890
Other assets		48			219		-		2			3			613		-			885

Total Assets	$	82,912			134,407		777		1,494			578			125,488		(227,876	)		117,780


Liabilities and Stockholders’ Equity
Accounts payable	$	-			8,710		1		3			1			6,687		(4,981	)		10,421
Short-term debt		395			4		750		-			-			202		-			1,351
Accrued income and other taxes		-			158		-		4			-			3,496		-			3,658
Employee benefit obligations		-			294		-		-			-			138		-			432
Other accruals		119			655		19		32			13			1,615		-			2,453

Total Current Liabilities		514			9,821		770		39			14			12,138		(4,981	)		18,315
Long-term debt		9,051			5,213		-		1,250			499			4,306		-			20,319
Asset retirement obligations and accrued environmental costs		-			1,253		-		-			-			7,397		-			8,650
Joint venture acquisition obligation		-			-		-		-			-			2,610		-			2,610
Deferred income taxes		54			292		-		14			8			13,239		-			13,607
Employee benefit obligations		-			2,446		-		-			-			825		-			3,271
Other liabilities and deferred credits*		31,327			22,689		-		95			36			18,580		(70,959	)		1,768

Total Liabilities		40,946			41,714		770		1,398			557			59,095		(75,940	)		68,540
Retained earnings		30,100			26,618		5		(54	)		(62	)		33,419		(53,364	)		36,662
Other common stockholders’ equity		11,866			66,075		2		150			83			32,537		(98,572	)		12,141
Noncontrolling interests		-			-		-		-			-			437		-			437

Total Liabilities and Stockholders’ Equity	$	82,912			134,407		777		1,494			578			125,488		(227,876	)		117,780


Balance Sheet	December 31, 2012

Assets
Cash and cash equivalents	$	2			12		6		50			2			3,546		-			3,618
Restricted cash		748			-		-		-			-			-		-			748
Accounts and notes receivable		64			6,247		-		-			-			7,958		(5,087	)		9,182
Inventories		-			57		-		-			-			908		-			965
Prepaid expenses and other current assets		19			847		-		1			-			8,609		-			9,476

Total Current Assets		833			7,163		6		51			2			21,021		(5,087	)		23,989
Investments, loans and long-term receivables*		80,910			114,314		759		1,455			578			44,739		(217,749	)		25,006
Net properties, plants and equipment		-			8,771		-		-			-			58,492		-			67,263
Other assets		55			216		-		2			3			610		-			886

Total Assets	$	81,798			130,464		765		1,508			583			124,862		(222,836	)		117,144


Liabilities and Stockholders’ Equity
Accounts payable	$	-			9,067		-		4			1			6,028		(5,087	)		10,013
Short-term debt		(5	)		4		750		-			-			206		-			955
Accrued income and other taxes		-			104		-		3			-			3,259		-			3,366
Employee benefit obligations		-			485		-		-			-			257		-			742
Other accruals		209			636		9		15			4			1,494		-			2,367

Total Current Liabilities		204			10,296		759		22			5			11,244		(5,087	)		17,443
Long-term debt		9,453			5,215		-		1,250			499			4,353		-			20,770
Asset retirement obligations and accrued environmental costs		-			1,250		-		-			-			7,697		-			8,947
Joint venture acquisition obligation		-			-		-		-			-			2,810		-			2,810
Deferred income taxes		15			598		-		16			7			12,549		-			13,185
Employee benefit obligations		-			2,464		-		-			-			882		-			3,346
Other liabilities and deferred credits*		30,938			19,916		-		117			50			21,174		(69,979	)		2,216

Total Liabilities		40,610			39,739		759		1,405			561			60,709		(75,066	)		68,717
Retained earnings		28,815			24,041		4		(78	)		(73	)		30,778		(48,149	)		35,338
Other common stockholders’ equity		12,373			66,684		2		181			95			32,935		(99,621	)		12,649
Noncontrolling interests		-			-		-		-			-			440		-			440

Total Liabilities and Stockholders’ Equity	$	81,798			130,464		765		1,508			583			124,862		(222,836	)		117,144

* Includes intercompany loans.


	Millions of Dollars
Statement of Cash Flows	Three Months Ended March 31, 2013
	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) continuing operating activities	$	74			2,261			-		(2	)		-		2,618			(343	)		4,608
Net cash provided by discontinued operations		-			-			-		-			-		172			(50	)		122

Net Cash Provided by (Used in) Operating Activities		74			2,261			-		(2	)		-		2,790			(393	)		4,730

Cash Flows From Investing Activities
Capital expenditures and investments		-			(448	)		-		-			-		(2,943	)		-			(3,391	)
Proceeds from asset dispositions		-			4			-		-			-		1,130			-			1,134
Net sales of short-term investments		-			-			-		-			-		(23	)		-			(23	)
Long-term advances/loans—related parties		-			2			-		-			-		(7	)		5			-
Collection of advances/loans—related parties		-			14			-		-			-		1,609			(1,566	)		57
Other		-			-			-		-			-		(21	)		-			(21	)

Net cash used in continuing investing activities		-			(428	)		-		-			-		(255	)		(1,561	)		(2,244	)
Net cash used in discontinued operations		-			-			-		-			-		(189	)		-			(189	)

Net Cash Used in Investing Activities		-			(428	)		-		-			-		(444	)		(1,561	)		(2,433	)

Cash Flows From Financing Activities
Issuance of debt		-			-			-		-			-		5			(5	)		-
Repayment of debt		-			(1,566	)		-		-			-		(48	)		1,566			(48	)
Change in restricted cash		748			-			-		-			-		-			-			748
Issuance of company common stock		(10	)		-			-		-			-		-			-			(10	)
Dividends paid		(815	)		-			-		-			-		(343	)		343			(815	)
Other		1			-			-		-			-		(206	)		-			(205	)

Net cash used in continuing financing activities		(76	)		(1,566	)		-		-			-		(592	)		1,904			(330	)
Net cash used in discontinued operations		-			-			-		-			-		(50	)		50			-

Net Cash Used in Financing Activities		(76	)		(1,566	)		-		-			-		(642	)		1,954			(330	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents		-			-			-		-			-		(163	)		-			(163	)

Net Change in Cash and Cash Equivalents		(2	)		267			-		(2	)		-		1,541			-			1,804
Cash and cash equivalents at beginning of period		2			12			6		50			2		3,546			-			3,618

Cash and Cash Equivalents at End of Period	$	-			279			6		48			2		5,087			-			5,422


Statement of Cash Flows	Three Months Ended March 31, 2012

Cash Flows From Operating Activities
Net cash provided by (used in) continuing operating activities	$	3,011			3,737			-		(1	)		-		(257	)		(2,420	)		4,070
Net cash provided by (used in) discontinued operations		-			167			-		-			-		(56	)		1			112

Net Cash Provided by (Used in) Operating Activities		3,011			3,904			-		(1	)		-		(313	)		(2,419	)		4,182

Cash Flows From Investing Activities
Capital expenditures and investments		(303	)		(470	)		-		-			-		(3,348	)		303			(3,818	)
Proceeds from asset dispositions		-			-			-		-			-		1,102			-			1,102
Net purchases of short-term investments		-			-			-		-			-		92			-			92
Long-term advances/loans—related parties		-			(2	)		-		-			-		(3,004	)		3,006			-
Collection of advances/loans—related parties		-			92			-		-			-		28			(82	)		38
Other		-			-			-		-			-		7			-			7

Net cash used in continuing investing activities		(303	)		(380	)		-		-			-		(5,123	)		3,227			(2,579	)
Net cash provided by (used in) discontinued operations		-			(163	)		-		-			-		7,932			(8,200	)		(431	)

Net Cash Provided by (Used in) Investing Activities		(303	)		(543	)		-		-			-		2,809			(4,973	)		(3,010	)

Cash Flows From Financing Activities
Issuance of debt		-			3,000			-		-			-		6			(3,006	)		-
Repayment of debt		-			(8,215	)		-		-			-		(114	)		8,282			(47	)
Issuance of company common stock		36			-			-		-			-		-			-			36
Repurchase of company common stock		(1,899	)		-			-		-			-		-			-			(1,899	)
Dividends paid		(843	)		-			-		-			-		(2,308	)		2,308			(843	)
Other		(2	)		-			-		-			-		(198	)		1			(199	)

Net cash used in continuing financing activities		(2,708	)		(5,215	)		-		-			-		(2,614	)		7,585			(2,952	)
Net cash used in discontinued operations		-			(5	)		-		-			-		(120	)		(193	)		(318	)

Net Cash Used in Financing Activities		(2,708	)		(5,220	)		-		-			-		(2,734	)		7,392			(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

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 47.

Due to the separation of our downstream businesses in 2012 and our intention to sell our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and our Nigerian and Algerian businesses, which are reported as discontinued operations, income (loss) from continuing operations is more representative of ConocoPhillips as an independent exploration and production company. The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to income (loss) from continuing operations.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on production and proved reserves. Headquartered in Houston, Texas, we have operations and activities in 30 countries. At March 31, 2013, we had approximately 17,100 employees worldwide and total assets of $118 billion.

Discontinued Operations

On April 30, 2012, we completed the separation of our downstream businesses into an independent, publicly traded company, Phillips 66. 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 (collectively, our “Downstream business”), were transferred to Phillips 66. Results of operations related to Phillips 66 for the period ended March 31, 2012, have been classified as discontinued operations. As part of our strategic asset disposition program, in the fourth quarter of 2012, we agreed to sell our interest in Kashagan and our Nigerian and Algerian businesses. Results of operations related to Kashagan, Nigeria and Algeria have been classified as discontinued operations in all periods presented in this Form 10-Q. For additional information, see Note 3—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Overview

As an independent E&P company, we are solely focused on exploring for, developing and producing crude oil and natural gas globally. Our portfolio primarily includes legacy assets in North America, Europe, Asia and Australia; growing North American shale and oil sands businesses; several major international developments; and a global exploration program. Our value proposition to our shareholders is to deliver production and cash margin growth, competitive returns on capital, and a compelling dividend, while keeping our fundamental commitment to safety, operating excellence and environmental stewardship. We expect to achieve our value proposition through portfolio optimization, investments in high-margin developments, applying technical capability and maintaining financial flexibility.

In the first quarter of 2013, we achieved production of 1,596 thousand barrels of oil equivalent per day (MBOED), including production from discontinued operations of 41 MBOED. Additionally, we generated $4.6 billion in cash from continuing operations, paid dividends on our common stock of $0.8 billion, funded a $3.6 billion capital program and continued to progress the asset disposition program. For the first quarter of 2013, we have generated proceeds from dispositions of approximately $1.1 billion, which mainly included the sale of certain properties in the Cedar Creek Anticline, located in North Dakota and Montana; our 24.5 percent interest in the N Block, located offshore Kazakhstan; and our 10 percent interest in the Interconnector Pipeline, located in Europe. The previously announced sales of Kashagan, Nigeria and Algeria are anticipated to close in 2013 and generate approximately $8.5 billion in expected proceeds.

Because we participate in a capital-intensive industry, we make significant investments to acquire acreage, explore for new oil and gas fields, develop newly discovered fields, maintain existing fields, and construct pipelines and liquefied natural gas (LNG) facilities. We use a disciplined approach to select the appropriate projects which will provide the most attractive investment opportunities, with a continued focus on higher-margin liquids plays and limited investment in North American conventional natural gas. As investments bring more liquids production online, we expect a corresponding shift in our production mix. However, there are often long lead times from the time we make an investment to the time the investment is operational and begins generating financial returns. In the near-term, we will fund a portion of our capital program with the proceeds from strategic asset dispositions. Over the next five years, our investment in high-margin developments should position us to deliver 3 to 5 percent annual production volume and margin growth, enabling us to fund our capital program organically.

Business Environment

In recent years, the business environment for the energy industry has experienced many challenges which have influenced our operations and profitability, largely due to factors beyond our control, such as the recent financial crisis, geopolitical events or fears thereof, environmental laws, tax regulations, governmental policies, and weather-related disruptions. These factors generally influence the supply and demand of crude oil and natural gas. The most significant factor impacting our profitability and related reinvestment of our operating cash flows into our business is commodity prices. The prices for commodity products are supply- and demand-based and can be very volatile; therefore, to navigate through the volatility, our strategy is to maintain a core portfolio of low-risk, high-return development programs associated with legacy assets, coupled with a portfolio of development opportunities which offer high-margin growth, such as unconventional plays, deepwater exploration and LNG.

The following table depicts the average benchmark prices for West Texas Intermediate (WTI) crude oil, Dated Brent crude oil and U.S. Henry Hub natural gas:


	Dollars Per Unit
	Three Months Ended
	March 31
	2013		2012

Market Indicators
WTI (per barrel)	$	94.29		102.99
Dated Brent (per barrel)		112.55		118.49
U.S. Henry Hub first of month (per million British thermal units)		3.34		2.72

Industry crude prices for WTI decreased 8 percent in the first quarter of 2013, compared with the same period in 2012, while Brent prices decreased 5 percent in the first quarter of 2013. Global oil prices weakened during the first quarter of 2013, mainly as a result of weak global economic growth and increasing North American oil supply.

Henry Hub natural gas prices increased 23 percent in the first quarter of 2013, compared with the same period in 2012. The increase was due to a colder winter in 2013 compared to 2012, which increased U.S. natural gas consumption by over 5 billion cubic feet per day in the first quarter of 2013 versus the first quarter of 2012.

The expansion in shale production has also helped boost supplies of natural gas liquids, resulting in downward pressure on natural gas liquids prices in the United States. As a result, our domestic realized natural gas liquids price declined 34 percent in the first quarter of 2013, compared with the same period of 2012. Our realized bitumen price was $39.23 in the first quarter of 2013, compared with $60.66 in the first quarter of 2012 and $48.32 in the fourth quarter of 2012, decreases of 35 percent and 19 percent, respectively. We expect bitumen prices to strengthen in the second quarter of 2013, compared to the first quarter of 2013.

Key Operating and Financial Highlights

Significant highlights during the first quarter of 2013 included the following:

—

Achieved first quarter total production of 1,596 MBOED, including continuing operations of 1,555 MBOED and discontinued operations of 41 MBOED.

—

Eagle Ford, Bakken and Permian combined production increased by 42 percent compared to the first quarter of 2012.

—

Oil sands production averaged 109 MBOED, up 30 percent compared to the first quarter of 2012.

—

Major projects on schedule for fourth-quarter startup.

—

Realized the first sale of oil from the deepwater Gumusut Field.

—

Announced Coronado and Shenandoah discoveries in the deepwater Gulf of Mexico.

—

Continued building the Gulf of Mexico exploration portfolio.

—

Entered Colombia to explore La Luna Shale.

—

Completed the sale of Cedar Creek Anticline properties for $989 million.

Outlook

Consistent with prior guidance, second quarter 2013 production from continuing operations is expected to be 1,440 to 1,470 MBOED, reflecting previously announced planned downtime and turnaround activity. Production from discontinued operations is expected to be approximately 40 MBOED in the second quarter of 2013. Full-year 2013 production from continuing operations is expected to be 1,485 to 1,520 MBOED.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three-month period ended March 31, 2013, is based on a comparison with the corresponding period of 2012.

A summary of income (loss) from continuing operations by business segment follows:


	Millions of Dollars
	Three Months Ended
	March 31
	2013			2012

Alaska	$	543			620
Lower 48 and Latin America		133			255
Canada		133			(549)
Europe		431			389
Asia Pacific and Middle East		932			1,754
Other International		14			21
Corporate and Other		(162	)		(311)

Income from continuing operations	$	2,024			2,179

Earnings for ConocoPhillips decreased 7 percent in the first quarter of 2013. The decrease primarily resulted from:

—

Lower gains from asset sales. Earnings for the first quarter of 2013 included a $270 million after-tax benefit associated with asset dispositions, compared with gains of $938 million after-tax in the first quarter of 2012.

—

Lower crude oil, bitumen and natural gas liquids prices.

—

Higher depreciation, depletion and amortization (DD&A) expenses, mainly due to higher volumes in the Lower 48 and China.

These items were partially offset by:

—

Lower impairments. Non-cash impairments in the first quarter of 2013 totaled $1 million after-tax, compared with impairments in the first quarter of 2012 of $520 million after-tax.

—

Higher natural gas prices.

—

Lower production taxes, primarily as a result of lower production volumes and prices in Alaska.

—

Higher sales, largely due to higher bitumen and LNG sales.

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

Income Statement Analysis

Sales and other operating revenues decreased 3 percent in the first quarter of 2013, mainly due to lower crude oil, natural gas liquids and bitumen prices, partly offset by higher natural gas prices.

Equity in earnings of affiliates decreased 26 percent in the first quarter of 2013. The decrease primarily resulted from:

—

Lower earnings from FCCL Partnership, mainly as a result of lower bitumen prices, partly offset by higher bitumen volumes.

—

Lower earnings from Lane Energy Poland Sp.z o.o., primarily due to expenses related to a dry hole.

—

Lower earnings from Phoenix Park Gas Processors Limited, mostly due to lower natural gas liquids prices.

These decreases in equity earnings were partially offset by higher earnings from Qatar Liquefied Gas Company Limited (3) (QG3), largely due to higher LNG prices and volumes.

Gain on dispositions decreased $882 million in the first quarter of 2013. Gains in the first quarter of 2013 primarily resulted from the disposition of our interest in the Interconnector Pipeline in Europe, partly offset by a loss on the disposition of certain properties located in the Cedar Creek Anticline in the Lower 48. Gains in the first quarter of 2012 mainly reflected the $937 million gain on sale of our Vietnam business.

Purchased commodities decreased 4 percent in the first quarter of 2013, largely as a result of lower purchased natural gas volumes, partly offset by higher natural gas prices.

Production and operating expenses increased 8 percent in the first quarter of 2013, mostly due to higher operating expenses in the Lower 48 and Canada.

Selling, general and administrative expenses decreased 49 percent in the first quarter of 2013, mainly as a result of lower costs related to compensation and benefit plans and the absence of costs associated with the separation of Phillips 66.

Exploration expenses decreased 59 percent in the first quarter of 2013, mostly due to the absence of the first quarter 2012 impairment of undeveloped leasehold costs associated with the Mackenzie Gas Project as a result of the indefinite suspension of the project. This decrease was partly offset by higher geological and geophysical expenses in the Lower 48 and expenses associated with the deferral of the Chukchi Sea exploration program in Alaska.

DD&A increased 15 percent in the first quarter of 2013. The increase was mostly associated with higher production volumes in the Lower 48 and China, as well as higher unit-of-production rates associated with year-end 2012 price-related reserve revisions.

Impairments decreased $212 million in the first quarter of 2013. The first quarter of 2012 included a $213 million impairment of capitalized project development costs associated with the Mackenzie Gas Project. For additional information, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.

Taxes other than income taxes decreased 19 percent in the first quarter of 2013, mainly as a result of lower production taxes due to lower crude oil production volumes and prices in Alaska.

Interest and debt expense decreased 32 percent in the first quarter of 2013, primarily due to lower interest expense from lower average debt levels and higher capitalized interest on projects.

See Note 22—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.

Summary Operating Statistics


	Three Months Ended
	March 31
	2013		2012

Average Net Production
Crude oil (MBD)*		626		624
Natural gas liquids (MBD)		159		163
Bitumen (MBD)		109		84
Natural gas (MMCFD)**		3,962		4,261


Total Production (MBOED)		1,555		1,581


	Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)	$	105.97		111.88
Natural gas liquids (per barrel)		42.95		55.03
Bitumen (per barrel)		39.23		60.66
Natural gas (per thousand cubic feet)		5.84		5.61


	Millions of Dollars
Exploration Expenses
General administrative; geological and geophysical; and lease rentals	$	241		157
Leasehold impairment		32		512
Dry holes		4		6

	$	277		675

Excludes discontinued operations.

*Thousands of barrels per day.

**Millions of cubic feet per day. Represents quantities available for sale and excludes gas equivalent of natural gas liquids included above.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At March 31, 2013, our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Malaysia, Qatar, Libya and Russia.

In the first quarter of 2013, average production from continuing operations decreased 2 percent compared with the first quarter of 2012, while average liquids production increased 3 percent over the same period. The decrease in total average production primarily resulted from normal field decline, the impact from asset dispositions and higher unplanned downtime. These decreases were largely offset by additional production from major developments, mainly from shale plays in the Lower 48 and the ramp-up of production from new phases at FCCL; higher production in China; increased drilling programs, mostly in western Canada, the Lower 48 and Norway; and the resumption of production in Libya.

Segment Results

Alaska


	Three Months Ended
	March 31
	2013		2012


Income From Continuing Operations (millions of dollars)	$	543		620


Average Net Production
Crude oil (MBD)		190		208
Natural gas liquids (MBD)		18		18
Natural gas (MMCFD)		56		59


Total Production (MBOED)		218		236


Average Sales Prices
Crude oil (dollars per barrel)	$	110.79		112.20
Natural gas (dollars per thousand cubic feet)		5.20		4.68

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids and natural gas. As of March 31, 2013, Alaska contributed 23 percent of our worldwide liquids production and 2 percent of our natural gas production.

Alaska operations reported earnings of $543 million in the first quarter of 2013, a 12 percent decrease compared with the same period in 2012. The decrease in earnings was largely due to lower volumes, partly offset by lower production taxes, which resulted from lower crude oil production volumes and prices. Higher exploration expenses, mainly related to cancellation fees for contracts associated with the deferral of the Chukchi Sea exploration program, and lower crude oil prices also contributed to the decrease in earnings.

Production averaged 218 MBOED in the first quarter of 2013, a decrease of 8 percent compared with the first quarter of 2012. The reduction was mainly due to normal field decline.

Chukchi Sea

In April 2013, we announced our 2014 Chukchi Sea exploration drilling plans are on hold given the uncertainties of evolving federal regulatory requirements and operational permitting standards. Once these requirements are clarified and better defined, we will re-evaluate our Chukchi Sea drilling plans.

Lower 48 and Latin America


	Three Months Ended
	March 31
	2013		2012


Income From Continuing Operations (millions of dollars)	$	133		255


Average Net Production
Crude oil (MBD)		148		117
Natural gas liquids (MBD)		87		84
Natural gas (MMCFD)		1,441		1,502


Total Production (MBOED)		475		451


Average Sales Prices
Crude oil (dollars per barrel)	$	93.69		99.00
Natural gas liquids (dollars per barrel)		29.58		44.90
Natural gas (dollars per thousand cubic feet)		3.19		2.65

As of March 31, 2013, Lower 48 and Latin America contributed 26 percent of our worldwide liquids production and 36 percent of our natural gas production. The Lower 48 and Latin America segment primarily consists of operations located in the U.S. Lower 48 states.

Lower 48 and Latin America operations reported earnings of $133 million in the first quarter of 2013, a 48 percent decrease compared with the same period in 2012. First quarter 2013 earnings were impacted by a $60 million after-tax loss on the disposition of certain Cedar Creek Anticline properties. In addition, the decrease in earnings was primarily the result of lower crude oil and natural gas liquids prices; higher DD&A, mostly due to higher crude oil and natural gas liquids production; and higher operating and exploration expenses. These decreases were partially offset by higher crude oil volumes and higher natural gas prices.

Average production in the Lower 48 increased 5 percent in the first quarter of 2013, while average liquids production increased 17 percent over the same period. New production, primarily from the Eagle Ford, Bakken and Permian areas, and improved drilling and well performance more than offset normal field decline. However, unfavorable weather conditions and unplanned downtime partially offset the increase in production.

Gulf of Mexico Exploration

In the first quarter of 2013, we confirmed a significant oil discovery from the Shenandoah appraisal well in the deepwater Gulf of Mexico. We hold a 30 percent working interest in Shenandoah. Additionally, we announced a deepwater discovery from the Coronado wildcat exploration well, which will require further appraisal. We hold a 35 percent working interest in Coronado.

Asset Dispositions

In April 2013, we sold certain properties located in southwest Louisiana, which generated proceeds of $95 million in the second quarter of 2013.

Colombia

In the first quarter of 2013, we entered into a farm-in agreement with Canacol Energy Ltd. to acquire a 70 percent working interest in the Santa Isabel Block located in Colombia. We expect to drill our first exploration well in Colombia’s La Luna Shale in the second quarter of 2013.

Canada


	Three Months Ended
	March 31
	2013		2012


Income (Loss) From Continuing Operations (millions of dollars)	$	133		(549)


Average Net Production
Crude oil (MBD)		14		13
Natural gas liquids (MBD)		26		25
Bitumen (MBD)
Consolidated operations		13		11
Equity affiliates		96		73

Total bitumen		109		84
Natural gas (MMCFD)		806		863


Total Production (MBOED)		283		266


Average Sales Prices
Crude oil (dollars per barrel)	$	72.85		83.85
Natural gas liquids (dollars per barrel)		50.15		54.13
Bitumen (dollars per barrel)
Consolidated operations		36.78		64.95
Equity affiliates		39.52		60.04
Total bitumen		39.23		60.66
Natural gas (dollars per thousand cubic feet)		2.89		1.98

Our Canadian operations comprise mainly natural gas fields in western Canada and oil sands projects in the Athabasca Region of northeastern Alberta. As of March 31, 2013, Canada contributed 17 percent of our worldwide liquids production and 20 percent of our natural gas production.

Canada operations reported earnings of $133 million in the first quarter of 2013, compared with a loss of $549 million in the corresponding period of 2012. First quarter 2012 earnings were impacted by a $520 million after-tax impairment of the Mackenzie Gas Project and associated undeveloped leaseholds. First quarter 2013 earnings benefitted from the recognition of additional income of $224 million related to the favorable tax resolution associated with the sale of certain western Canada properties in a prior year. Lower bitumen prices were nearly offset by higher bitumen volumes and higher natural gas prices.

Average production increased 6 percent in the first quarter of 2013, while average liquids production increased 22 percent over the same period. The ramp-up of production from Christina Lake Phases C and D in FCCL and improved drilling and well performance from western Canada more than offset normal field decline. In addition, lower natural gas curtailments and lower royalty impacts, as a result of lower prices, contributed to the increase in production.

Europe


	Three Months Ended
	March 31
	2013		2012


Income From Continuing Operations (millions of dollars)	$	431		389


Average Net Production
Crude oil (MBD)		124		156
Natural gas liquids (MBD)		6		10
Natural gas (MMCFD)		461		632


Total Production (MBOED)		207		271


Average Sales Prices
Crude oil (dollars per barrel)	$	114.11		121.25
Natural gas liquids (dollars per barrel)		60.10		59.29
Natural gas (dollars per thousand cubic feet)		10.81		9.98

The Europe segment consists of operations principally located in Norway and the United Kingdom, as well as exploration activities in Poland and Greenland. As of March 31, 2013, our Europe operations contributed 15 percent of our worldwide liquids production and 12 percent of our natural gas production.

Europe operations reported earnings of $431 million in the first quarter of 2013, an increase of 11 percent compared with the corresponding period of 2012. Earnings in the first quarter of 2013 mainly benefitted from the $83 million after-tax gain on disposition of our interest in the Interconnector Pipeline and foreign currency transaction gains, compared to foreign currency transaction losses in the first quarter of 2012, partly offset by lower crude oil and natural gas volumes.

Average production decreased 24 percent in the first quarter of 2013, mostly due to normal field decline, asset dispositions and higher unplanned downtime, mostly in the East Irish Sea, partly offset by improved drilling and well performance in Norway.

Asia Pacific and Middle East


	Three Months Ended
	March 31
	2013		2012

Income From Continuing Operations (millions of dollars)	$	932		1,754


Average Net Production
Crude oil (MBD)
Consolidated operations		86		61
Equity affiliates		15		16

Total crude oil		101		77


Natural gas liquids (MBD)
Consolidated operations		14		18
Equity affiliates		8		8

Total natural gas liquids		22		26


Natural gas (MMCFD)
Consolidated operations		684		697
Equity affiliates		483		505

Total natural gas		1,167		1,202


Total Production (MBOED)		318		303


Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	109.35		117.66
Equity affiliates		107.80		116.37
Total crude oil		109.12		117.38
Natural gas liquids (dollars per barrel)
Consolidated operations		77.59		89.56
Equity affiliates		77.32		88.24
Total natural gas liquids		77.50		89.18
Natural gas (dollars per thousand cubic feet)
Consolidated operations		10.71		10.40
Equity affiliates		9.36		8.62
Total natural gas		10.03		9.65

The Asia Pacific and Middle East segment has producing operations in China, Indonesia, Malaysia, Australia, the Timor Sea and Qatar, as well as exploration activities in Bangladesh and Brunei. As of March 31, 2013, Asia Pacific and Middle East contributed 14 percent of our worldwide liquids production and 29 percent of our natural gas production.

Asia Pacific and Middle East operations reported earnings of $932 million in the first quarter of 2013, a 47 percent decrease compared with the same period in 2012. The decrease was mainly due to the absence of a $937 million after-tax gain on sale of our Vietnam business in the corresponding period of 2012, partly offset by higher crude oil volumes, mainly from China. Lower crude oil prices and higher DD&A also contributed to the decrease in first quarter 2013 earnings.

Production averaged 318 MBOED in the first quarter of 2013, an increase of 5 percent compared with the first quarter of 2012. The increase was largely due to the resumption of normal production operations in Bohai Bay, China, new production from Panyu in the South China Sea and the ramp-up of production in Malaysia. These increases were partly offset by the disposition of our Vietnam business in the first quarter of 2012, normal field decline and the impact of higher production on production sharing contracts in China.

PetroChina Agreements

In the first quarter of 2013, we entered into a set of agreements with PetroChina Company Ltd., whereby PetroChina will acquire a 20 percent working interest in the Poseidon offshore discovery in the Browse Basin and a 29 percent working interest in the Goldwyer Shale in the onshore Canning Basin. We also agreed to establish a Joint Study Agreement with PetroChina to identify unconventional resource opportunities in the Sichuan Basin in China. The agreements are subject to customary government and partner approvals.

Other International


	Three Months Ended
	March 31
	2013		2012

Income From Continuing Operations (millions of dollars)*	$	14		21


Average Net Production*
Crude oil (MBD)
Consolidated operations		44		35
Equity affiliates		5		18

Total crude oil		49		53


Natural gas (MMCFD)		31		3


Total Production (MBOED)		54		54


Average Sales Prices*
Crude oil (dollars per barrel)
Consolidated operations	$	112.18		121.68
Equity affiliates		75.22		107.34
Total crude oil		108.15		115.21
Natural gas (dollars per thousand cubic feet)		4.86		0.09

*Prior periods have been restated to exclude discontinued operations.

The Other International segment includes producing operations in Libya and Russia, as well as exploration activities in Angola and onshore Azerbaijan. As of March 31, 2013, Other International contributed 5 percent of our worldwide liquids production and 1 percent of our natural gas production.

Other International operations reported earnings of $14 million in the first quarter of 2013, a 33 percent decrease compared with the same period in 2012. The decrease was primarily the result of lower gains from foreign currency transactions and lower equity earnings, mainly as a result of the disposition of our interest in Naryanmarneftegaz (NMNG) in Russia in 2012. These decreases were partially offset by higher crude oil volumes from Libya and lower exploration expenses.

Average production remained flat in the first quarter of 2013, compared with the first quarter of 2012. Increased production from Libya in the first quarter of 2013, compared with the ramp-up of production in the first quarter of 2012 following their period of civil unrest, and higher natural gas production was offset by lower production due to the disposition of our interest in NMNG in 2012.

Asset Dispositions

We plan to sell our 8.4 percent interest in Kashagan and our Algerian and Nigerian businesses. The transactions are expected to close in 2013, subject to customary governmental approvals. Results of operations related to Kashagan, Nigeria and Algeria have been classified as discontinued operations in all periods presented in this Form 10-Q.

Corporate and Other


	Millions of Dollars
	Three Months Ended March 31
	2013		2012
Income (Loss) From Continuing Operations
Net interest	$	(108)		(161)
Corporate general and administrative expenses		(27)		(74)
Technology		(8)		(18)
Separation costs		-		(33)
Other		(19)		(25)

	$	(162)		(311)

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 33 percent in the first quarter of 2013, mainly as a result of lower interest expense due to lower average debt levels and higher capitalized interest on projects.

Corporate general and administrative expenses decreased 64 percent in the first quarter of 2013, mostly due to lower costs related to compensation and benefit plans and lower corporate contributions.

Technology includes our investment in new technologies or businesses, as well as licensing revenues received. Activities are focused on heavy oil and oil sands, unconventional reservoirs, subsurface technology, liquefied natural gas, arctic and deepwater, as well as sustainability technology.

Separation costs consist of expenses related to the separation of our Downstream business into a stand-alone, publicly traded company, Phillips 66.

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.

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators


	Millions of Dollars
	March 31 2013			December 31 2012

Short-term debt	$	1,351			955
Total debt		21,670			21,725
Total equity		49,240			48,427
Percent of total debt to capital*		31	%		31
Percent of floating-rate debt to total debt**		8	%		9

*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 continuing operating activities is the primary source of funding. In addition, during the first three months of 2013, we received $1,134 million in proceeds from asset sales. We used the remaining $748 million of our restricted cash balance, received in connection with the separation of Phillips 66, solely to pay dividends. During the first three months of 2013, the primary uses of our available cash were $3,391 million to support our ongoing capital expenditures and investments program and $815 million to pay dividends. During the first three months of 2013, cash and cash equivalents increased by $1,804 million to $5,422 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 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

Cash provided by continuing operating activities was $4,608 million for the first three months of 2013, compared with $4,070 million for the corresponding period of 2012, a 13 percent increase. The increase was primarily due to a working capital benefit associated with the timing of certain tax payments and the tax impacts of dispositions.

While the stability of our cash flows from operating activities benefits from geographic diversity, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and natural gas liquids. 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.

Asset Sales

Proceeds from asset sales during the first three months of 2013 were $1,134 million, primarily from the sale of the majority of our properties in the Cedar Creek Anticline. This compares with proceeds of $1,102 million in the first three months of 2012, primarily from the sale of our Vietnam business. We have announced additional asset sales of $8.5 billion which are expected to close in 2013. We continue to evaluate opportunities to further optimize the portfolio.

Commercial Paper and Credit Facilities

At March 31, 2013, we had a revolving credit facility totaling $7.5 billion expiring in August 2016. Our revolving credit facility may be used as direct bank borrowings, as support for issuances of letters of credit totaling up to $750 million, or as support for our commercial paper programs. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or by any of its consolidated subsidiaries.

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 agreement calls for commitment fees on available but unused amounts. The agreement also contains 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. $1.15 billion commercial paper program, which is used to fund commitments relating to QG3. At both March 31, 2013 and December 31, 2012, we had no direct borrowings or letters of credit issued under the revolving credit facilities. In addition, under the ConocoPhillips Qatar Funding Ltd. commercial paper programs, $1,008 million of commercial paper was outstanding at March 31, 2013, compared with $1,055 million at December 31, 2012. Since we had $1,008 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.5 billion in borrowing capacity under our revolving credit facilities at March 31, 2013.

Certain of our project-related contracts and derivative instruments contain provisions requiring us to post collateral. Although cash is the primary form of collateral, many of these contracts and instruments permit us to post letters of credit. At March 31, 2013 and December 31, 2012, we had direct bank letters of credit of $782 million and $852 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business.

Shelf Registration

We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission 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 13—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, 2013 and December 31, 2012, was $21.7 billion. In April 2013, we repaid bonds at maturity totaling $850 million.

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 $782 million was short-term and was included in the “Accounts payable—related parties” line on our March 31, 2013 consolidated balance sheet. The principal portion of these payments, which totaled $189 million in the first three months of 2013, 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.

In February 2013, we announced a dividend of 66 cents per share. The dividend was paid March 1, 2013, to stockholders of record at the close of business on February 19, 2013.

Capital Spending

Capital Program


	Millions of Dollars
	Three Months Ended March 31
	2013 2012
Alaska	$	262	186
Lower 48 and Latin America		1,280	1,267
Canada		675	629
Europe		791	622
Asia Pacific and Middle East		337	699
Other International		19	354
Corporate and Other		27	61

Capital expenditures and investments from continuing operations	$	3,391	3,818

Discontinued operations in Kashagan, Nigeria and Algeria	$	189	220
Joint venture acquisition obligation (principal)—Canada		189	180

Capital Program	$	3,769	4,218

During the first three months of 2013, capital expenditures and investments from continuing operations supported key exploration and development programs, primarily:

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

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Exploration leases and wells in deepwater Gulf of Mexico.

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Oil sands development and ongoing liquids-focused plays in Canada.

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Continued development of new fields offshore Malaysia and ongoing exploration and development activity onshore and offshore Indonesia and Australia.

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In Europe, development activities in the Greater Ekofisk, Jasmine and Clair Ridge areas and appraisal activities in the Greater Clair Area.

Contingencies

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 58–60 of our 2012 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, 2012, we reported we had been notified of potential liability under CERCLA and comparable state laws at 11 sites around the United States. During the quarter ended March 31, 2013, we were notified of 1 new site, increasing the number of unresolved sites with potential liability to 12 sites.

At March 31, 2013, our balance sheet included a total environmental accrual of $350 million, compared with $364 million at December 31, 2012. 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, to the extent 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 and factors on which the ultimate impact on our financial performance will depend, see the “Climate Change” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 60–62 of our 2012 Annual Report on Form 10-K.

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:

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Fluctuations in crude oil, bitumen, natural gas, LNG and natural gas liquids prices.

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Potential failures or delays in achieving expected reserve or production levels from existing and future oil and gas developments due to operating hazards, drilling risks and the inherent uncertainties in predicting reserves and reservoir performance.

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Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.

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Unexpected changes in costs or technical requirements for constructing, modifying or operating exploration and production facilities.

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

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Inability to timely obtain or maintain permits, including those necessary for drilling and/or development, construction of LNG terminals or regasification facilities; comply with government regulations; or make capital expenditures required to maintain compliance.

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Failure to complete definitive agreements and feasibility studies for, and to timely complete construction of, announced and future exploration and production and LNG development.

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Potential disruption or interruption of our operations due to accidents, extraordinary weather events, civil unrest, political events, terrorism or cyber attacks.

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International monetary conditions and exchange controls.

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

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

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Liability resulting from litigation.

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General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas, LNG or natural gas liquids pricing, regulation or taxation; other political, economic or diplomatic developments; and international monetary fluctuations.

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Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules applicable to our business.

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

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

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Inability to obtain economical financing for development, construction or modification of facilities and general corporate purposes.

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The operation and financing of our joint ventures.

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The factors generally described in Item 1A—Risk Factors in our 2012 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, 2013, does not differ materially from that discussed under Item 7A in our 2012 Annual Report on Form 10-K.

Item 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. As of March 31, 2013, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Executive Vice President, Finance and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Executive Vice President, Finance and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of March 31, 2013.

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 2013 and any material developments with respect to matters previously reported in ConocoPhillips’ 2012 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 U.S. Securities and Exchange Commission (SEC) regulations.

On April 30, 2012, the separation of our Downstream business was completed, creating two independent energy companies: ConocoPhillips and Phillips 66. In connection with the separation, we entered into an Indemnification and Release Agreement, which provides for cross-indemnities between Phillips 66 and us and established procedures for handling claims subject to indemnification and related matters, such as legal proceedings. We have included matters where we remain a party to a proceeding relating to Phillips 66, in accordance with SEC regulations. We do not expect any of those matters to result in a net claim against us.

Matters Previously Reported—ConocoPhillips

The New Mexico Environment Department has issued four Notices of Violation (NOVs) to ConocoPhillips alleging a total of 20 individual violations for failure to comply with air emission recordkeeping, reporting and testing requirements at various natural gas compression operations in northwestern New Mexico. These violations are alleged to have occurred between 2006 and 2012. The agency is seeking a penalty of over $100,000. We have resolved two of the NOVs and are working with the agency to resolve the remaining two matters.

Matters Previously Reported—Phillips 66

On November 28, 2011, the Phillips 66 Borger Refinery received a Notice of Enforcement from the Texas Commission on Environmental Quality for alleged emissions events that occurred during inclement weather in January and February 2011. This matter was concluded with no impact to ConocoPhillips.

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A of our 2012 Annual Report on Form 10-K.

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

Issuer Purchases of Equity Securities

None.

Item 6. EXHIBITS


10.1*		Offer letter from ConocoPhillips to Matthew J. Fox, dated November 18, 2011.

10.2*		Form of Make-up Grant Award Agreement under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.

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, 2013