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, 2014

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 1,227,705,457 shares of common stock, $.01 par value, outstanding at March 31, 2014.

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		24

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		28

Item 3. Quantitative and Qualitative Disclosures About Market Risk		48

Item 4. Controls and Procedures		48

Part II – Other Information

Item 1. Legal Proceedings		49

Item 1A. Risk Factors		49

Item 6. Exhibits		50

Signature		52

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS


Consolidated Income Statement		ConocoPhillips


	Millions of Dollars
	Three Months Ended March 31
	2014			2013

Revenues and Other Income
Sales and other operating revenues	$	15,415			14,166
Equity in earnings of affiliates		572			362
Gain on dispositions		9			58
Other income		52			65

Total Revenues and Other Income		16,048			14,651


Costs and Expenses
Purchased commodities		7,127			5,834
Production and operating expenses		1,895			1,687
Selling, general and administrative expenses		182			165
Exploration expenses		296			277
Depreciation, depletion and amortization		1,892			1,807
Impairments		1			2
Taxes other than income taxes		651			892
Accretion on discounted liabilities		117			106
Interest and debt expense		171			130
Foreign currency transaction (gains) losses		18			(36)

Total Costs and Expenses		12,350			10,864

Income from continuing operations before income taxes		3,698			3,787
Provision for income taxes		1,581			1,763

Income From Continuing Operations		2,117			2,024
Income from discontinued operations*		20			129

Net income		2,137			2,153
Less: net income attributable to noncontrolling interests		(14	)		(14)

Net Income Attributable to ConocoPhillips	$	2,123			2,139


Amounts Attributable to ConocoPhillips Common Shareholders:
Income from continuing operations	$	2,103			2,010
Income from discontinued operations		20			129

Net Income	$	2,123			2,139


Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic
Continuing operations	$	1.70			1.64
Discontinued operations		0.02			0.10

Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	1.72			1.74

Diluted
Continuing operations	$	1.69			1.63
Discontinued operations		0.02			0.10

Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	1.71			1.73


Dividends Paid Per Share of Common Stock (dollars)	$	0.69			0.66


Average Common Shares Outstanding (in thousands)
Basic		1,234,968			1,229,232
Diluted		1,242,667			1,235,907

*Net of provision for income taxes on discontinued operations of:	$	32			(9)
See Notes to Consolidated Financial Statements.


Consolidated Statement of Comprehensive Income		ConocoPhillips


	Millions of Dollars
	Three Months Ended March 31
	2014		2013


Net Income	$	2,137		2,153
Other comprehensive income (loss)
Defined benefit plans
Reclassification adjustment for amortization of prior service credit included in net income		(2)		(1)
Reclassification adjustment for amortization of net actuarial losses included in net income		33		57
Nonsponsored plans*		6		1
Income taxes on defined benefit plans		(11)		(22)

Defined benefit plans, net of tax		26		35

Foreign currency translation adjustments		(222)		(644)
Reclassification adjustment for loss included in net income		(4)		(4)
Income taxes on foreign currency translation adjustments		-		4

Foreign currency translation adjustments, net of tax		(226)		(644)

Other Comprehensive Loss, Net of Tax		(200)		(609)

Comprehensive Income		1,937		1,544
Less: comprehensive income attributable to noncontrolling interests		(14)		(14)

Comprehensive Income Attributable to ConocoPhillips	$	1,923		1,530

*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 2014		December 31 2013

Assets
Cash and cash equivalents	$	7,520		6,246
Short-term investments*		210		272
Accounts and notes receivable (net of allowance of $8 million in 2014 and $8 million in 2013)		8,438		8,273
Accounts and notes receivable—related parties		213		214
Inventories		1,221		1,194
Prepaid expenses and other current assets		2,798		2,824

Total Current Assets		20,400		19,023
Investments and long-term receivables		23,261		23,907
Loans and advances—related parties		1,289		1,357
Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $66,890 million in 2014 and $65,321 million in 2013)		74,025		72,827
Other assets		1,050		943

Total Assets	$	120,025		118,057


Liabilities
Accounts payable	$	9,534		9,250
Accounts payable—related parties		70		64
Short-term debt		1,712		589
Accrued income and other taxes		3,485		2,713
Employee benefit obligations		495		842
Other accruals		1,821		1,671

Total Current Liabilities		17,117		15,129
Long-term debt		19,494		21,073
Asset retirement obligations and accrued environmental costs		9,908		9,883
Deferred income taxes		15,539		15,220
Employee benefit obligations		2,394		2,459
Other liabilities and deferred credits		1,952		1,801

Total Liabilities		66,404		65,565


Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2014—1,769,936,130 shares; 2013—1,768,169,906 shares)
Par value		18		18
Capital in excess of par		45,754		45,690
Treasury stock (at cost: 2014—542,230,673 shares; 2013—542,230,673 shares)		(36,780)		(36,780)
Accumulated other comprehensive income		1,802		2,002
Retained earnings		42,428		41,160

Total Common Stockholders’ Equity		53,222		52,090
Noncontrolling interests		399		402

Total Equity		53,621		52,492

Total Liabilities and Equity	$	120,025		118,057

*Includes marketable securities of:	$	43		135

See Notes to Consolidated Financial Statements.


Consolidated Statement of Cash Flows		ConocoPhillips


	Millions of Dollars
	Three Months Ended March 31
	2014		2013

Cash Flows From Operating Activities
Net income	$	2,137		2,153
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		1,892		1,807
Impairments		1		2
Dry hole costs and leasehold impairments		69		36
Accretion on discounted liabilities		117		106
Deferred taxes		230		241
Undistributed equity earnings		1,131		(29)
Gain on dispositions		(9)		(58)
Income from discontinued operations		(20)		(129)
Other		116		(503)
Working capital adjustments
Decrease (increase) in accounts and notes receivable		(290)		249
Increase in inventories		(27)		(177)
Increase in prepaid expenses and other current assets		(17)		(131)
Increase in accounts payable		353		528
Increase in taxes and other accruals		595		513

Net cash provided by continuing operating activities		6,278		4,608
Net cash provided by discontinued operations		58		122

Net Cash Provided by Operating Activities		6,336		4,730


Cash Flows From Investing Activities
Capital expenditures and investments		(3,895)		(3,391)
Proceeds from asset dispositions		48		1,134
Net sales (purchases) of short-term investments		63		(23)
Collection of advances/loans—related parties		62		57
Other		46		(21)

Net cash used in continuing investing activities		(3,676)		(2,244)
Net cash used in discontinued operations		(22)		(189)

Net Cash Used in Investing Activities		(3,698)		(2,433)


Cash Flows From Financing Activities
Repayment of debt		(450)		(48)
Change in restricted cash		-		748
Issuance of company common stock		(32)		(10)
Dividends paid		(855)		(815)
Other		(17)		(205)

Net cash used in continuing financing activities		(1,354)		(330)
Net cash used in discontinued operations		-		-

Net Cash Used in Financing Activities		(1,354)		(330)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		(10)		(163)


Net Change in Cash and Cash Equivalents		1,274		1,804
Cash and cash equivalents at beginning of period		6,246		3,618

Cash and Cash Equivalents at End of Period	$	7,520		5,422

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 2013 Annual Report on Form 10-K.

The results of operations for our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and our Algeria and Nigeria businesses have been classified as discontinued operations for all periods presented. See Note 2—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—Discontinued Operations

As part of our asset disposition program, we agreed to sell our interest in Kashagan and our Algeria and Nigeria businesses (collectively, the “Disposition Group”). The Disposition Group was previously part of the Other International operating segment. We completed the sales of Kashagan and our Algeria business in the fourth quarter of 2013.

On December 20, 2012, we entered into agreements with affiliates of Oando PLC to sell our Nigeria business. This originally included our upstream affiliates and Phillips (Brass) Limited, which owns a 17 percent interest in the Brass LNG Project. Brass LNG plans to construct a liquefied natural gas (LNG) facility in the Niger Delta. For the upstream affiliates, we agreed to further extend the outside date, the date the sales agreement may terminate if closing has not occurred, to June 30, 2014, in order to provide additional time for the parties to obtain government consents. The upstream sale is expected to generate proceeds of approximately $1.4 billion, after customary adjustments, inclusive of deposits received. We received deposits of $435 million and $15 million in December 2012 and 2013, respectively. In 2014, we received additional deposits of $50 million in February and $25 million in April, bringing our total deposits received to $525 million. An additional deposit of $25 million is to be paid on May 30, 2014, if government consent has not been obtained by May 23, 2014. We may retain the deposits if closing does not occur due to default by the buyer or failure to obtain all consents required under Nigerian petroleum laws. In the first quarter of 2014, we and Oando agreed to terminate the sales agreement for Phillips (Brass) Limited, and we are currently evaluating options for exiting the Brass LNG Project. As of March 31, 2014, the net carrying value of our Nigerian upstream assets and Phillips (Brass) Limited was $329 million and $63 million, respectively.

At March 31, 2014, our interest in the Nigeria business was considered held for sale, and accordingly, we classified $4 million of loans and advances to related parties in the “Accounts and notes receivable—related parties” line and $1,238 million of noncurrent assets in the “Prepaid expenses and other current assets” line of our consolidated balance sheet. In addition, we classified $786 million of deferred income taxes in the “Accrued income and other taxes” line and $14 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		December 31
	2014		2013

Assets
Accounts and notes receivable	$	276		376
Inventories		9		9
Prepaid expenses and other current assets		88		72

Total current assets of discontinued operations		373		457
Investments and long-term receivables		62		60
Loans and advances—related parties		4		7
Net properties, plants and equipment		1,176		1,154
Other assets		-		1

Total assets of discontinued operations	$	1,615		1,679


Liabilities
Accounts payable	$	340		419
Accrued income and other taxes		83		72

Total current liabilities of discontinued operations		423		491
Asset retirement obligations and accrued environmental costs		14		14
Deferred income taxes		786		765

Total liabilities of discontinued operations	$	1,223		1,270

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
	2014		2013


Sales and other operating revenues from discontinued operations	$	158		329


Income from discontinued operations before-tax	$	52		120
Income tax expense (benefit)		32		(9)

Income from discontinued operations	$	20		129

Note 3—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 an 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, 2014, the prepaid balance of the terminal use agreement was $293 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 $491 million at March 31, 2014, and $506 million at December 31, 2013.

In July 2013, we reached an agreement with Freeport LNG to terminate our long-term agreement at the Freeport LNG Terminal, subject to Freeport LNG obtaining regulatory approval and project financing for an LNG liquefaction and export facility in Texas, in which we are not a participant. Upon satisfaction of these conditions, currently expected to occur in the second half of 2014, we will pay Freeport LNG a termination fee of approximately $600 million. Freeport LNG will repay the outstanding ConocoPhillips loan used by Freeport LNG to partially fund the original construction of the terminal. When the agreement becomes effective, we expect to recognize an after-tax charge to earnings of approximately $540 million. At that time, our terminal regasification capacity will be reduced from 0.9 billion cubic feet per day to 0.4 billion cubic feet per day, until July 1, 2016, at which time it will be reduced to zero.

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 method investment.

Australia Pacific LNG Pty Ltd (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, 2014, we have not provided any financial support to APLNG other than amounts previously contractually required. Unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of APLNG. See Note 5—Investments, Loans and Long-Term Receivables, and Note 9—Guarantees, for additional information.

Note 4—Inventories

Inventories consisted of the following:


	Millions of Dollars
		March 31 2014	December 31 2013


Crude oil and natural gas	$	468	452
Materials, supplies and other		753	742

	$	1,221	1,194

Inventories valued on the last-in, first-out (LIFO) basis totaled $319 million and $343 million at March 31, 2014 and December 31, 2013, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was approximately $160 million at both March 31, 2014 and December 31, 2013.

Note 5—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 consists 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. At March 31, 2014, $7.6 billion had been drawn from the facility. 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 9—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 3—Variable Interest Entities (VIEs), for additional information.

At March 31, 2014, the book value of our equity method investment in APLNG was $11,569 million, which included $1,504 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.

FCCL

In the first quarter of 2014, we received a $1.3 billion distribution from FCCL Partnership, our 50 percent owned business venture with Cenovus Energy Inc., which is included in the “Undistributed equity earnings” line on our consolidated statement of cash flows.

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, 2014, included the following:

—

$491 million in loan financing to Freeport LNG. See Note 3—Variable Interest Entities (VIEs), for additional information.

—

$959 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 6—Suspended Wells

The capitalized cost of suspended wells at March 31, 2014, was $997 million, an increase of $3 million from $994 million at year-end 2013. No suspended wells were charged to dry hole expense during the first three months of 2014 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2013.

Note 7—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 program, which is used to fund commitments relating to QG3. Commercial paper maturities are generally limited to 90 days.

At March 31, 2014 and December 31, 2013, we had no direct outstanding borrowings under the revolving credit facility, with no letters of credit as of March 31, 2014 or December 31, 2013. In addition, under the ConocoPhillips Qatar Funding Ltd. commercial paper program, there was $912 million of commercial paper outstanding at March 31, 2014, compared with $961 million at December 31, 2013. Since we had $912 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.6 billion in borrowing capacity under our revolving credit facility at March 31, 2014.

At March 31, 2014, we classified $810 million of short-term debt as long-term debt, based on our ability and intent to refinance the obligation on a long-term basis under our revolving credit facility.

In February 2014, the $400 million 4.75% Notes due 2014 were repaid at maturity.

During 2013, a lease of a semi-submersible floating production system (FPS) commenced for the Gumusut development, located in Malaysia, in which we are a co-venturer. As of March 31, 2014, the value of the capital lease asset and associated obligation for our proportionate interest in the FPS was $906 million with commissioning activities continuing. Following the startup of the FPS, the capital lease asset will be depreciated over a period consistent with the estimated proved reserves of Gumusut using the unit-of-production method with the associated depreciation included in the “Depreciation, depletion and amortization” line on our consolidated income statement.

Note 8—Noncontrolling Interests

Activity attributable to common stockholders’ equity and noncontrolling interests for the first three months of 2014 and 2013 was as follows:


	Millions of Dollars
	2014				2013
		Common Stockholders’ Equity	Non- Controlling Interest	Total Equity		Common Stockholders’ Equity	Non- Controlling Interest	Total Equity


Balance at January 1	$	52,090	402	52,492		47,987	440	48,427
Net income		2,123	14	2,137		2,139	14	2,153
Dividends		(855)	-	(855)		(815)	-	(815)
Distributions to noncontrolling interests		-	(17)	(17)		-	(17)	(17)
Other changes, net*		(136)	-	(136)		(508)	-	(508)

Balance at March 31	$	53,222	399	53,621		48,803	437	49,240

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

Note 9—Guarantees

At March 31, 2014, 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 guarantees and expect future performance to be either immaterial or have only a remote chance of occurrence.

APLNG Guarantees

At March 31, 2014, 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 2014 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 three years. Our maximum potential amount of future payments related to this guarantee is approximately $140 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 tests with milestones, which we estimate would occur beginning in 2016. Our maximum exposure at March 31, 2014, is approximately $2.8 billion based upon our pro-rata share of the facility used at that date. At March 31, 2014, the carrying value of this guarantee is $114 million.

—

In conjunction with our original acquisition of an ownership interest in APLNG in October 2008, we agreed to guarantee an existing obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of 3 to 18 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $0.8 billion (approximately $2.0 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 32 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $200 million and would become payable if APLNG does not perform.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $250 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 10 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 agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. These agreements include indemnifications for taxes, environmental liabilities, employee claims, 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, 2014, was approximately $60 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 at March 31, 2014, 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 10—Contingencies and Commitments.

On April 30, 2012, the separation of our downstream businesses 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. 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 10—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 other 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 agency concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit and some of the indemnifications are subject to dollar limits and time limits.

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state and international sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. At

March 31, 2014, our balance sheet included a total environmental accrual of $347 million, compared with $348 million at December 31, 2013, for remediation activities in the U.S. and Canada. 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

We are subject to various lawsuits and claims including but not limited to matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, personal injury, and property damage. Our primary exposures for such matters relate to alleged royalty underpayments on certain Federal, State and privately owned properties and claims of alleged environmental contamination from historic operations. We will continue to defend ourselves vigorously in these matters.

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, is 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, 2014, we had performance obligations secured by letters of credit of $756 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. On September 3, 2013, an ICSID arbitration tribunal held that Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in June 2007. A separate arbitration phase will proceed to determine the amount of damages owed to ConocoPhillips for Venezuela’s actions.

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 supplemental counterclaims 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 and to address Ecuador’s counterclaims.

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. As of March 2014, ConocoPhillips paid, under protest, tax assessments totaling approximately $232 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 11—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.

Our derivative instruments are held at fair value on our consolidated balance sheet. Where these balances have the right of setoff, they are presented on a net basis. Related cash flows are recorded as operating activities on the consolidated statement of cash flows. On our 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 2014		December 31 2013

Assets
Prepaid expenses and other current assets	$	1,168		871
Other assets		76		64
Liabilities
Other accruals		1,138		890
Other liabilities and deferred credits		68		58

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


	Millions of Dollars
	Three Months Ended March 31
	2014			2013


Sales and other operating revenues	$	237			(208)
Other income		1			2
Purchased commodities		(221	)		185

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



	Open Position Long/(Short)
	March 31 2014		December 31 2013

Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price		(15)		(18)
Basis		1		(10)

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 programs 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 2014		December 31 2013

Assets
Prepaid expenses and other current assets	$	1		1
Liabilities
Other accruals		1		-

The 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
	2014		2013


Foreign currency transaction losses	$	-		22

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


	In Millions Notional Currency
	March 31 2014		December 31 2013


Sell U.S. dollar, buy British pound	USD	250		-
Buy U.S. dollar, sell other currencies*	USD	163		6
Buy British pound, sell euro	GBP	63		17

*Primarily Canadian dollar and Norwegian krone.

Financial Instruments

We have certain financial instruments on our 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.


	Millions of Dollars
	Carrying Amount
	Cash and Cash Equivalents				Short-Term Investments
	March 31		December 31		March 31		December 31
	2014		2013		2014		2013


Cash	$	1,014		636		-		-
Time deposits
Remaining maturities from 1 to 90 days		4,590		5,336		167		137
Commercial paper
Remaining maturities from 1 to 90 days		1,916		274		43		135

	$	7,520		6,246		210		272

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 transactions administered through the New York Mercantile Exchange or 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, 2014, and December 31, 2013, was $107 million and $57 million, respectively. For these instruments, no collateral was posted as of March 31, 2014 or December 31, 2013. If our credit rating had been lowered one level from its “A” rating (per Standard and Poor’s) on March 31, 2014, 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 $107 million of additional collateral, either with cash or letters of credit.

Note 12—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 that 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 during 2014 or 2013.

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 for all periods presented.

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, 2014								December 31, 2013
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total

Assets
Deferred compensation investments	$	302		-		-		302		306		-		-		306
Commodity derivatives		898		335		11		1,244		744		177		10		931

Total assets	$	1,200		335		11		1,546		1,050		177		10		1,237


Liabilities
Commodity derivatives	$	863		334		9		1,206		765		172		7		944

Total liabilities	$	863		334		9		1,206		765		172		7		944

The following table summarizes those commodity derivative balances subject to the right of setoff as presented on our consolidated balance sheet. We have elected to offset the recognized fair value amounts for multiple derivative instruments executed with the same counterparty in our financial statements when a legal right of offset exists.


	Millions of Dollars
	Gross Amounts Recognized		Gross Amounts Offset		Net Amounts Presented		Cash Collateral		Gross Amounts without Right of Setoff		Net Amounts

March 31, 2014
Assets	$	1,244		1,034		210		24		26		160
Liabilities		1,206		1,034		172		1		29		142


December 31, 2013
Assets	$	931		827		104		6		12		86
Liabilities		944		827		117		26		9		82

At March 31, 2014 and December 31, 2013, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.

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 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 5—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.

—

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.

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

2014

December 31

2013

March 31

2014

December 31

2013

Financial assets

Deferred compensation investments

302

306

302

306

Commodity derivatives

186

Total loans and advances—related parties

1,461

1,528

1,596

1,680

Financial liabilities

Total debt, excluding capital leases

20,285

20,740

23,686

23,553

Commodity derivatives

171

Note 13—Accumulated Other Comprehensive Income

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

Millions of Dollars

Defined
Benefit Plans

Foreign
Currency
Translation

Accumulated

Other

Comprehensive

Income (Loss)

December 31, 2013

(824)

2,826

2,002

Other comprehensive income (loss)

(226)

(200)

March 31, 2014

(798)

2,600

1,802

The following table summarizes reclassifications out of accumulated other comprehensive income:


	Millions of Dollars
	Three Months Ended March 31
		2014	2013

Defined Benefit Plans	$	20	35

Above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of $11 million and $22 million for the three-month periods ended March 31, 2014 and 2013, respectively. See Note 15—Employee Benefit Plans, for additional information.

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

Note 14—Cash Flow Information


	Millions of Dollars
	Three Months Ended March 31
		2014		2013

Cash Payments
Interest	$	199		157
Income taxes		667		1,199


Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased	$	(210	)	(23)
Short-term investments sold		273		-

	$	63		(23)

Note 15—Employee Benefit Plans

Pension and Postretirement Plans


	Millions of Dollars
	Pension Benefits								Other Benefits
Three Months Ended	March 31								March 31
	2014				2013				2014		2013
	U.S.		Int’l.		U.S.		Int’l.
Components of Net Periodic Benefit Cost
Service cost	$	31		28		35		26		1		1
Interest cost		41		42		36		37		7		6
Expected return on plan assets		(53)		(46)		(47)		(41)		-		-
Amortization of prior service cost (credit)		1		(2)		1		(2)		(1)		(1)
Recognized net actuarial loss (gain)		19		15		38		19		(1)		1

Net periodic benefit cost	$	39		37		63		39		6		7

During the first three months of 2014, we contributed $86 million to our domestic benefit plans and $35 million to our international benefit plans.

Note 16—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
		2014		2013


Operating revenues and other income	$	21		8
Purchases		48		41
Operating expenses and selling, general and administrative expenses		52		46
Net interest (income) expense*		(12	)	9

*	We paid interest to, or received interest from various affiliates. See Note 5—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

Note 17—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.

In 2012, we agreed to sell our Nigeria and Algeria businesses and our interest in Kashagan. We sold Kashagan and our Algeria business in the fourth quarter of 2013. Results for the Disposition Group have been reported as discontinued operations in all periods presented. For additional information, see Note 2—Discontinued Operations.

Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead and certain technology activities, including licensing revenues. Corporate assets include all cash and cash equivalents and short-term investments.

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

Effective April 1, 2014, the Other International segment will be restructured to focus on enhancing our capability to operate in emerging and new country business units. The Latin America and Poland businesses will be included in the Other International segment. Accordingly, results of operations for the Lower 48 and Latin America, Europe and Other International segments will be revised for current and prior periods beginning in the second quarter of 2014. There is no expected impact on our consolidated financial statements, and the impact on our segment presentation is expected to be immaterial.

Analysis of Results by Operating Segment


	Millions of Dollars
	Three Months Ended March 31
		2014		2013

Sales and Other Operating Revenues
Alaska	$	2,186		2,104

Lower 48 and Latin America		6,584		4,822
Intersegment eliminations		(38	)	(29)

Lower 48 and Latin America		6,546		4,793

Canada		1,859		1,255
Intersegment eliminations		(345	)	(158)

Canada		1,514		1,097

Europe		3,209		3,453
Asia Pacific and Middle East		1,949		2,218
Other International		2		483
Corporate and Other		9		18

Consolidated sales and other operating revenues	$	15,415		14,166


Net Income Attributable to ConocoPhillips
Alaska	$	598		543
Lower 48 and Latin America		320		133
Canada		356		133
Europe		343		431
Asia Pacific and Middle East		742		918
Other International		(21	)	14
Corporate and Other		(235	)	(162	)
Discontinued operations		20		129

Consolidated net income attributable to ConocoPhillips	$	2,123		2,139


	Millions of Dollars
		March 31 2014	December 31 2013

Total Assets
Alaska	$	12,073	11,662
Lower 48 and Latin America		30,295	29,571
Canada		21,250	22,394
Europe		17,570	17,299
Asia Pacific and Middle East		26,094	25,473
Other International		1,678	1,610
Corporate and Other		9,446	8,367
Discontinued operations		1,619	1,681

Consolidated total assets	$	120,025	118,057

Note 18—Income Taxes

Our effective tax rate from continuing operations for the first quarter of 2014 was 43 percent compared with 47 percent for the first quarter of 2013. The decrease in the effective tax rate was primarily due to a smaller proportion of income in higher tax jurisdictions in 2014. The first quarter of 2013 effective tax rate was favorably impacted by the tax resolution associated with the sale of certain western Canada properties which occurred in a prior year.

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

Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company and ConocoPhillips Canada Funding Company I, with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. ConocoPhillips Canada Funding Company I is an indirect, 100 percent owned subsidiary of ConocoPhillips Company. ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Canada Funding Company I, with respect to its 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 and ConocoPhillips Canada Funding Company I (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.

During 2013, ConocoPhillips Australia Funding Company’s guaranteed, publicly held debt was repaid. Beginning in the first quarter of 2014, financial information for ConocoPhillips Australia Funding Company is presented in the “All Other Subsidiaries” column of our condensed consolidating financial information.

In April 2014, ConocoPhillips received a $32 billion dividend from ConocoPhillips Company to settle certain accumulated intercompany balances. The transaction will be reflected in the second quarter 2014 Condensed Consolidating Financial Information for ConocoPhillips and ConocoPhillips Company and is expected to have no impact on our consolidated financial statements.

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, 2014
Income Statement				ConocoPhillips			ConocoPhillips Company			ConocoPhillips Canada Funding Company I			All Other Subsidiaries			Consolidating Adjustments			Total Consolidated

Revenues and Other Income
Sales and other operating revenues				$	-			6,143			-			9,272			-			15,415
Equity in earnings of affiliates					2,212			2,451			-			721			(4,812	)		572
Gain (loss) on dispositions					-			(1	)		-			10			-			9
Other income					-			18			-			34			-			52
Intercompany revenues					20			154			71			1,643			(1,888	)		-

Total Revenues and Other Income					2,232			8,765			71			11,680			(6,700	)		16,048


Costs and Expenses
Purchased commodities					-			5,517			-			3,290			(1,680	)		7,127
Production and operating expenses					-			360			-			1,538			(3	)		1,895
Selling, general and administrative expenses					3			124			-			69			(14	)		182
Exploration expenses					-			144			-			152			-			296
Depreciation, depletion and amortization					-			242			-			1,650			-			1,892
Impairments					-			1			-			-			-			1
Taxes other than income taxes					-			93			-			558			-			651
Accretion on discounted liabilities					-			14			-			103			-			117
Interest and debt expense					159			70			58			75			(191	)		171
Foreign currency transaction (gains) losses					25			-			(139	)		132			-			18

Total Costs and Expenses					187			6,565			(81	)		7,567			(1,888	)		12,350

Income from continuing operations before income taxes					2,045			2,200			152			4,113			(4,812	)		3,698
Provision for income taxes					(58	)		(12	)		2			1,649			-			1,581

Income From Continuing Operations					2,103			2,212			150			2,464			(4,812	)		2,117
Income from discontinued operations					20			20			-			20			(40	)		20

Net income					2,123			2,232			150			2,484			(4,852	)		2,137
Less: net income attributable to noncontrolling interests					-			-			-			(14	)		-			(14)

Net Income Attributable to ConocoPhillips				$	2,123			2,232			150			2,470			(4,852	)		2,123


Comprehensive Income Attributable to ConocoPhillips				$	1,923			2,032			9			2,255			(4,296	)		1,923


	Millions of Dollars
	Three Months Ended March 31, 2013
Income Statement	ConocoPhillips			ConocoPhillips Company			ConocoPhillips Australia Funding Company			ConocoPhillips Canada Funding Company I			All Other Subsidiaries			Consolidating Adjustments			Total Consolidated

Revenues and Other Income
Sales and other operating revenues	$	-			4,463			-			-			9,703			-			14,166
Equity in earnings of affiliates*		2,110			2,372			-			-			474			(4,594	)		362
Gain (loss) on dispositions		-			(2	)		-			-			60			-			58
Other income		1			45			-			-			19			-			65
Intercompany revenues*		20			125			11			78			1,159			(1,393	)		-

Total Revenues and Other Income		2,131			7,003			11			78			11,415			(5,987	)		14,651


Costs and Expenses
Purchased commodities		-			3,928			-			-			3,065			(1,159	)		5,834
Production and operating expenses		-			316			-			-			1,373			(2	)		1,687
Selling, general and administrative expenses		4			122			-			-			57			(18	)		165
Exploration expenses		-			143			-			-			134			-			277
Depreciation, depletion and amortization		-			209			-			-			1,598			-			1,807
Impairments		-			-			-			-			2			-			2
Taxes other than income taxes		-			77			-			-			815			-			892
Accretion on discounted liabilities		-			14			-			-			92			-			106
Interest and debt expense*		154			81			10			59			40			(214	)		130
Foreign currency transaction (gains) losses		17			8			-			(98	)		37			-			(36)

Total Costs and Expenses		175			4,898			10			(39	)		7,213			(1,393	)		10,864

Income from continuing operations before income taxes		1,956			2,105			1			117			4,202			(4,594	)		3,787
Provision for income taxes		(54	)		(5	)		-			5			1,817			-			1,763

Income From Continuing Operations		2,010			2,110			1			112			2,385			(4,594	)		2,024
Income from discontinued operations		129			129			-			-			129			(258	)		129

Net income		2,139			2,239			1			112			2,514			(4,852	)		2,153
Less: net income attributable to noncontrolling interests		-			-			-			-			(14	)		-			(14)

Net Income Attributable to ConocoPhillips	$	2,139			2,239			1			112			2,500			(4,852	)		2,139


Comprehensive Income Attributable to ConocoPhillips	$	1,530			1,630			1			17			1,885			(3,533	)		1,530

“Interest and debt expense” for ConocoPhillips was revised to reflect contractually agreed interest rates, with offsetting adjustments in the “Equity in earnings of affiliates” and “Intercompany revenues” lines for ConocoPhillips, ConocoPhillips Company and All Other Subsidiaries. There was no impact to Total Consolidated balances.


			Millions of Dollars
			March 31, 2014
Balance Sheet			ConocoPhillips		ConocoPhillips Company		ConocoPhillips Canada Funding Company I			All Other Subsidiaries		Consolidating Adjustments			Total Consolidated

Assets
Cash and cash equivalents			$	-		3,718		230			3,572		-			7,520
Short-term investments				-		-		-			210		-			210
Accounts and notes receivable				16		3,275		22			9,172		(3,834	)		8,651
Inventories				-		105		-			1,116		-			1,221
Prepaid expenses and other current assets				19		477		10			2,339		(47	)		2,798

Total Current Assets				35		7,575		262			16,409		(3,881	)		20,400
Investments, loans and long-term receivables*				88,823		102,251		4,156			35,431		(206,111	)		24,550
Net properties, plants and equipment				-		9,528		-			64,497		-			74,025
Other assets				38		270		123			1,396		(777	)		1,050

Total Assets			$	88,896		119,624		4,541			117,733		(210,769	)		120,025


Liabilities and Stockholders’ Equity
Accounts payable			$	-		4,567		6			8,865		(3,834	)		9,604
Short-term debt				1,504		6		5			197		-			1,712
Accrued income and other taxes				-		374		-			3,111		-			3,485
Employee benefit obligations				-		336		-			159		-			495
Other accruals				115		714		101			937		(46	)		1,821

Total Current Liabilities				1,619		5,997		112			13,269		(3,880	)		17,117
Long-term debt				7,537		5,207		2,978			3,772		-			19,494
Asset retirement obligations and accrued environmental costs				-		1,289		-			8,619		-			9,908
Deferred income taxes				-		561		-			14,984		(6	)		15,539
Employee benefit obligations				-		1,749		-			645		-			2,394
Other liabilities and deferred credits*				33,078		11,023		1,489			20,665		(64,303	)		1,952

Total Liabilities				42,234		25,826		4,579			61,954		(68,189	)		66,404
Retained earnings				35,907		34,030		(1,350	)		15,086		(41,245	)		42,428
Other common stockholders’ equity				10,755		59,768		1,312			40,294		(101,335	)		10,794
Noncontrolling interests				-		-		-			399		-			399

Total Liabilities and Stockholders’ Equity			$	88,896		119,624		4,541			117,733		(210,769	)		120,025

*Includes intercompany loans.

	Millions of Dollars
	December 31, 2013
Balance Sheet	ConocoPhillips		ConocoPhillips Company		ConocoPhillips Australia Funding Company		ConocoPhillips Canada Funding Company I			All Other Subsidiaries		Consolidating Adjustments			Total Consolidated


Assets
Cash and cash equivalents	$	-		2,434		-		229			3,583		-			6,246
Short-term investments		-		-		-		-			272		-			272
Accounts and notes receivable		73		2,122		2		-			9,267		(2,977	)		8,487
Inventories		-		174		-		-			1,020		-			1,194
Prepaid expenses and other current assets		20		535		-		35			2,311		(77	)		2,824

Total Current Assets		93		5,265		2		264			16,453		(3,054	)		19,023
Investments, loans and long-term receivables*		86,836		100,052		-		4,259			34,795		(200,678	)		25,264
Net properties, plants and equipment		-		9,313		-		-			63,514		-			72,827
Other assets		38		260		-		103			1,394		(852	)		943

Total Assets	$	86,967		114,890		2		4,626			116,156		(204,584	)		118,057


Liabilities and Stockholders’ Equity
Accounts payable	$	-		3,388		-		4			8,899		(2,977	)		9,314
Short-term debt		395		4		-		5			185		-			589
Accrued income and other taxes		-		223		-		-			2,517		(27	)		2,713
Employee benefit obligations		-		566		-		-			276		-			842
Other accruals		210		639		-		81			790		(49	)		1,671

Total Current Liabilities		605		4,820		-		90			12,667		(3,053	)		15,129
Long-term debt		9,047		5,208		-		2,980			3,838		-			21,073
Asset retirement obligations and accrued environmental costs		-		1,289		-		-			8,594		-			9,883
Deferred income taxes		94		557		-		-			14,569		-			15,220
Employee benefit obligations		-		1,791		-		-			668		-			2,459
Other liabilities and deferred credits*		31,693		9,422		-		1,603			22,204		(63,121	)		1,801

Total Liabilities		41,439		23,087		-		4,673			62,540		(66,174	)		65,565
Retained earnings		34,636		31,835		-		(1,500	)		12,848		(36,659	)		41,160
Other common stockholders’ equity		10,892		59,968		2		1,453			40,366		(101,751	)		10,930
Noncontrolling interests		-		-		-		-			402		-			402

Total Liabilities and Stockholders’ Equity	$	86,967		114,890		2		4,626			116,156		(204,584	)		118,057

*Includes intercompany loans.


				Millions of Dollars
Statement of Cash Flows				Three Months Ended March 31, 2014
				ConocoPhillips			ConocoPhillips Company			ConocoPhillips Canada Funding Company I			All Other Subsidiaries			Consolidating Adjustments			Total Consolidated
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operating activities				$	(134	)		373			1			5,976			62			6,278
Net cash provided by discontinued operations					-			100			-			121			(163	)		58

Net Cash Provided by (Used in) Operating Activities					(134	)		473			1			6,097			(101	)		6,336


Cash Flows From Investing Activities
Capital expenditures and investments					-			(662	)		-			(3,378	)		145			(3,895)
Proceeds from asset dispositions					-			(1	)		-			49			-			48
Net sales of short-term investments					-			-			-			63			-			63
Long-term advances/loans—related parties					-			(44	)		-			(2	)		46			-
Collection of advances/loans—related parties					-			15			-			47			-			62
Intercompany cash management					1,325			1,486			-			(2,811	)		-			-
Other					-			18			-			(6	)		34			46

Net cash provided by (used in) continuing investing activities					1,325			812			-			(6,038	)		225			(3,676)
Net cash used in discontinued operations					-			(1	)		-			(22	)		1			(22)

Net Cash Provided by (Used in) Investing Activities					1,325			811			-			(6,060	)		226			(3,698)


Cash Flows From Financing Activities
Issuance of debt					-			-			-			46			(46	)		-
Repayment of debt					(400	)		-			-			(50	)		-			(450)
Issuance of company common stock					63			-			-			-			(95	)		(32)
Dividends paid					(855	)		-			-			(96	)		96			(855)
Other					1			-			-			161			(179	)		(17)

Net cash provided by (used in) continuing financing activities					(1,191	)		-			-			61			(224	)		(1,354)
Net cash used in discontinued operations					-			-			-			(99	)		99			-

Net Cash Used in Financing Activities					(1,191	)		-			-			(38	)		(125	)		(1,354)


Effect of Exchange Rate Changes on Cash and Cash Equivalents					-			-			-			(10	)		-			(10)


Net Change in Cash and Cash Equivalents					-			1,284			1			(11	)		-			1,274
Cash and cash equivalents at beginning of period					-			2,434			229			3,583			-			6,246

Cash and Cash Equivalents at End of Period				$	-			3,718			230			3,572			-			7,520


	Millions of Dollars
	Three Months Ended March 31, 2013*
Statement of Cash Flows	ConocoPhillips			ConocoPhillips Company			ConocoPhillips Australia Funding Company			ConocoPhillips Canada Funding Company I			All Other Subsidiaries			Consolidating Adjustments			Total Consolidated

Cash Flows From Operating Activities
Net cash provided by (used in) continuing operating activities	$	(185	)		1,308			-			(10	)		3,610			(115	)		4,608
Net cash provided by discontinued operations		-			50			-			-			239			(167	)		122

Net Cash Provided by (Used in) Operating Activities		(185	)		1,358			-			(10	)		3,849			(282	)		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 purchases of short-term investments		-			-			-			-			(23	)		-			(23)
Long-term advances/loans—related parties		-			2			-			-			(7	)		5			-
Collection of advances/loans—related parties		-			14			-			2			1,609			(1,568	)		57
Intercompany cash management		148			903			-			-			(1,051	)		-			-
Other		-			-			-			-			(21	)		-			(21)

Net cash provided by (used in) continuing investing activities		148			475			-			2			(1,306	)		(1,563	)		(2,244)
Net cash used in discontinued operations		-			-			-			-			(189	)		-			(189)

Net Cash Provided by (Used in) Investing Activities		148			475			-			2			(1,495	)		(1,563	)		(2,433)


Cash Flows From Financing Activities
Issuance of debt		-			-			-			-			5			(5	)		-
Repayment of debt		-			(1,566	)		-			-			(50	)		1,568			(48)
Change in restricted cash		748			-			-			-			-			-			748
Issuance of company common stock		101			-			-			-			-			(111	)		(10)
Dividends paid		(815	)		-			-			-			(343	)		343			(815)
Other		1			-			-			-			(206	)		-			(205)

Net cash provided by (used in) continuing financing activities		35			(1,566	)		-			-			(594	)		1,795			(330)
Net cash used in discontinued operations		-			-			-			-			(50	)		50			-

Net Cash Provided by (Used in) Financing Activities		35			(1,566	)		-			-			(644	)		1,845			(330)


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


Net Change in Cash and Cash Equivalents		(2	)		267			-			(8	)		1,547			-			1,804
Cash and cash equivalents at beginning of period		2			12			6			59			3,539			-			3,618

Cash and Cash Equivalents at End of Period	$	-			279			6			51			5,086			-			5,422

Revised to reflect intercompany cash management activities previously presented as cash flows from continuing operating activities as both continuing activities and discontinued operations in “Cash Flows from Investing Activities” and “Cash Flows From Financing Activities.” There was no impact on Total Consolidated balances.

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 discontinued operations reporting, income (loss) from continuing operations is more representative of ConocoPhillips’ earnings. The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to income (loss) from continuing operations. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements.

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 27 countries. At March 31, 2014, we had approximately 18,800 employees worldwide and total assets of $120 billion.

Overview

We are an independent E&P company focused on exploring for, developing and producing crude oil and natural gas globally. Our asset base reflects our legacy as a major company with a strategic focus on higher-margin developments. Our diverse portfolio primarily includes resource-rich North American shale and oil sands assets; lower-risk legacy assets in North America, Europe, Asia and Australia; several major international developments; and a growing inventory of global conventional and unconventional exploration prospects. Our value proposition to our shareholders is to deliver 3 to 5 percent production and cash margin growth, achieve ongoing competitive returns on capital, and offer a compelling dividend, while keeping our fundamental commitment to safety, operating excellence and environmental stewardship. To achieve these goals, we plan to continue to invest in high-margin developments, optimize our portfolio, apply technical capability and maintain financial flexibility.

In 2013, we successfully achieved the targets we set to sell non-core assets, advance major projects, progress development drilling and exploration programs and maintain a compelling dividend. Our success has enabled us to focus on growth in 2014, which we intend to deliver through investments in our legacy assets, continued success in our development drilling and exploration programs, continued ramp up in our unconventional plays and additional project startups, such as the recent startup at Siakap North-Petai and the anticipated startups in Canada, Malaysia and the United Kingdom in 2014. As a result, we expect to deliver 3 to 5 percent volume growth in 2014. In the first quarter of 2014, we achieved production of 1,568 thousand barrels of oil equivalent per day (MBOED), including production from discontinued operations of 36 MBOED. Excluding Libya, our production from continuing operations was 1,530 MBOED.

In the first quarter of 2014, we generated $6.3 billion in cash from continuing operations, which included a $1.3 billion distribution from our 50 percent owned FCCL Partnership. We also paid dividends on our common stock of $0.9 billion and ended the quarter with $7.5 billion in cash and cash equivalents.

We participate in a capital-intensive industry. As a result, we invest significant capital 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. Our capital budget for 2014 is $16.7 billion, and we funded $3.9 billion of this in the first quarter of 2014. We use a disciplined approach to select the appropriate projects which will provide the most attractive investment opportunities, with a continued focus on organic growth in volumes and margins through higher-margin oil, condensate and LNG projects 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. Over the next five years, our investment in higher-value products and geographies will contribute to margin growth.

Business Environment

The business environment for the energy industry has historically experienced many challenges which have influenced our operations and profitability, largely due to factors beyond our control, such as the global financial crisis and recession which began in 2008, supply disruptions or fears thereof caused by civil unrest or military conflicts, environmental laws, tax regulations, governmental policies and weather-related disruptions. Recently, North America’s energy landscape has been transformed from resource scarcity to an abundance of supply, as a result of advances in technology responsible for the rapid growth of shale production, successful exploration and development in the deepwater Gulf of Mexico and rising production from the Canadian oil sands. These dynamics generally influence world energy markets and commodity prices. The most significant factor impacting our profitability and related reinvestment of operating cash flows into our business is commodity prices, which can be very volatile; therefore, our strategy is to maintain a strong balance sheet with a diverse portfolio of assets, which will provide the financial flexibility to withstand challenging business cycles.

Our earnings generally correlate with industry price levels for crude oil and natural gas. These are commodity products, the prices of which are subject to factors external to the Company and over which we have no control. The following graph depicts the trend in average benchmark prices for West Texas Intermediate (WTI) crude oil, Dated Brent crude oil and U.S. Henry Hub (HH) natural gas:

LOGO

Brent crude oil prices averaged $108.22 per barrel in the first quarter of 2014, a decrease of 4 percent compared with $112.55 per barrel in the first quarter of 2013. Prices have remained relatively stable since the third quarter of 2013, as they have been supported by continued Middle East and Africa supply disruptions and global oil demand growth. Industry crude prices for WTI averaged $98.75 per barrel in the first quarter of 2014, an increase of 5 percent compared with $94.29 per barrel in the first quarter of 2013, as strong refinery runs and new infrastructure helped to reduce the inventories at the Cushing, Oklahoma hub. As a result, the discount of WTI to Brent decreased 48 percent in the first quarter of 2014, compared with the first quarter of 2013.

Henry Hub natural gas prices averaged $4.94 per thousand cubic feet (MCF) in the first quarter of 2014, an increase of 48 percent compared with $3.34 per MCF in the first quarter of 2013. A severe winter across most of the United States contributed to the increase in the first quarter of 2014, as large withdrawals of natural gas in storage were needed to meet demand during the periods of extreme cold winter weather.

Our realized bitumen price was $56.47 per barrel in the first quarter of 2014, an increase of 44 percent compared with $39.23 per barrel in the first quarter of 2013. This increase was primarily the result of higher refinery demand and expanded rail capacity.

Our total average realized price was $71.21 per barrel of oil equivalent (BOE) in the first quarter of 2014, an increase of 4 percent compared with $68.57 per BOE in the first quarter of 2013, which reflected higher natural gas, bitumen and natural gas liquids prices, partially offset by lower crude oil prices.

Key Operating and Financial Highlights

Significant highlights during the first quarter of 2014 included the following:

—

First-quarter production of 1,530 MBOED from continuing operations, excluding Libya; total production of 1,568 MBOED.

—

Eagle Ford and Bakken combined production increased by 41 percent compared with first-quarter 2013.

—

Christina Lake Phase E approached full production, contributing to ongoing growth from Canadian oil sands.

—

Jasmine averaged 25 MBOED, with Ekofisk South and East Irish Sea continuing to ramp up.

—

Major project startup at Siakap North-Petai in Malaysia with preparations underway for four additional startups in Canada, Malaysia and the United Kingdom in 2014.

—

Exploration and appraisal activity ongoing with drilling in the Gulf of Mexico, Alaska and Australia, as well as unconventional plays in Canada, the Lower 48 and Poland.

—

Strong North American natural gas prices and income from marketing third-party natural gas.

—

Cash flow from operations of $6.3 billion, including a $0.6 billion working capital benefit and a $1.3 billion FCCL distribution.

Outlook

Production Guidance

Second-quarter 2014 production from continuing operations, excluding Libya, is expected to be 1,490 MBOED to 1,540 MBOED, reflecting planned downtime and turnaround activity. Full-year 2014 production from continuing operations is unchanged from previous guidance and is expected to be 1,510 MBOED to 1,550 MBOED, excluding Libya.

Sale of Nigeria Business Update

As previously announced, we entered into agreements with affiliates of Oando PLC to sell our Nigeria business, which originally included our upstream affiliates and Phillips (Brass) Limited, which owns a 17 percent interest in the Brass LNG Project. The upstream sale is anticipated to close, subject to government consents, in the second quarter of 2014 and generate proceeds of approximately $1.4 billion, after customary adjustments, inclusive of deposits received. In the first quarter of 2014, we and Oando agreed to terminate the sales agreement for Phillips (Brass) Limited, and we are currently evaluating options for exiting the Brass LNG Project. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Other International Segment

Effective April 1, 2014, the Other International segment will be restructured to focus on enhancing our capability to operate in emerging and new country business units. The Latin America and Poland businesses will be included in the Other International segment, in addition to Angola, Azerbaijan, Libya, Russia, Senegal and Nigeria. Beginning in the second quarter of 2014, results of operations for the Lower 48 and Latin America, Europe and Other International segments will be revised for current and prior periods. There is no expected impact on our consolidated financial statements, and the impact on our segment presentation is expected to be immaterial.

Freeport LNG

We have a long-term agreement with Freeport LNG Development, L.P. to use 0.9 billion cubic feet per day of regasification capacity at Freeport’s 1.5-billion-cubic-feet-per-day LNG receiving terminal in Quintana, Texas. In July 2013, we and Freeport LNG agreed to terminate this agreement, subject to Freeport LNG obtaining regulatory approval and project financing for an LNG liquefaction and export facility in Texas, in which we are not a participant. Upon satisfaction of these conditions, currently expected to occur in the second half of 2014, we will pay Freeport LNG a termination fee of approximately $600 million. Freeport LNG will repay the outstanding ConocoPhillips loan used by Freeport LNG to partially fund the original construction of the terminal. These transactions, plus miscellaneous items, will result in a one-time net cash outflow of approximately $80 million for us. When the agreement becomes effective, we also expect to recognize an after-tax charge to earnings of approximately $540 million. At that time, our terminal regasification capacity will be reduced from 0.9 billion cubic feet per day to 0.4 billion cubic feet per day, until July 1, 2016, at which time it will be reduced to zero. As a result of this transaction, we anticipate saving approximately $50 to $60 million per year in operating costs over the next 19 years. For additional information, see Note 3—Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three-month period ended March 31, 2014, is based on a comparison with the corresponding period of 2013.

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


	Millions of Dollars
	Three Months Ended March 31
	2014			2013


Alaska	$	598			543
Lower 48 and Latin America		320			133
Canada		356			133
Europe		343			431
Asia Pacific and Middle East		756			932
Other International		(21	)		14
Corporate and Other		(235	)		(162)

Income from continuing operations	$	2,117			2,024

Earnings for ConocoPhillips increased 5 percent in the first quarter of 2014. The increase primarily resulted from:

—

Higher natural gas, bitumen, LNG and natural gas liquids prices.

—

Lower production taxes in Alaska, as a result of higher capital spending, lower production volumes and lower prices.

—

Improved marketing of third-party North American natural gas volumes.

—

A higher proportion of production in higher-margin areas and a continued portfolio shift toward liquids.

These items were partially offset by:

—

Lower gains from asset sales. Earnings for the first quarter of 2014 included gains of $6 million after-tax, compared with a $270 million after-tax benefit associated with asset dispositions in the first quarter of 2013.

—

Higher operating expenses.

—

Lower crude oil prices.

—

An $83 million after-tax loss related to releases of capacity on transportation and storage capacity agreements.

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

Income Statement Analysis

Sales and other operating revenues increased 9 percent in the first quarter of 2014, mainly due to higher natural gas, bitumen, LNG and natural gas liquids prices, partly offset by lower crude oil prices and overall volumes.

Equity in earnings of affiliates increased 58 percent in the first quarter of 2014. The increase primarily resulted from higher earnings from FCCL Partnership, mainly as a result of higher bitumen prices and volumes, in addition to a foreign exchange benefit related to cash balances held in FCCL. The increase was partially offset by lower earnings from Qatar Liquefied Gas Company Limited (3) (QG3), largely due to lower volumes and higher depreciation, depletion and amortization (DD&A). These decreases to QG3’s earnings were partly offset by higher LNG prices.

Gain on dispositions decreased 84 percent in the first quarter of 2014. 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 a majority of our producing zones located in the Cedar Creek Anticline in the Lower 48.

Purchased commodities increased 22 percent in the first quarter of 2014, largely as a result of higher natural gas prices, in addition to a $130 million loss related to transportation and storage capacity agreements located in the Lower 48. These increases were partly offset by lower purchased natural gas volumes.

Production and operating expenses increased 12 percent in the first quarter of 2014, mostly due to increased drilling activity in the Lower 48, as well as higher well workovers and maintenance activities in Europe and China.

DD&A increased 5 percent in the first quarter of 2014. The increase was mostly associated with higher production volumes in the United Kingdom and the Lower 48, partly offset by lower unit-of-production rates in Canada associated with year-end 2013 price-related reserve revisions and lower production volumes.

Taxes other than income taxes decreased 27 percent in the first quarter of 2014, mainly due to lower production taxes in Alaska, as a result of higher capital spending, lower crude oil production volumes and lower crude oil prices.

Interest and debt expense increased 32 percent in the first quarter of 2014, primarily due to lower capitalized interest on projects.

Foreign currency transaction gains in the first quarter of 2013 were primarily attributable to fluctuations in the U.S. dollar versus Norwegian krone exchange rates.

See Note 18—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
	2014		2013

Average Net Production
Crude oil (MBD)*		599		626
Natural gas liquids (MBD)		159		159
Bitumen (MBD)		124		109
Natural gas (MMCFD)**		3,901		3,962


Total Production (MBOED)		1,532		1,555


	Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)	$	101.59		105.97
Natural gas liquids (per barrel)		46.52		42.95
Bitumen (per barrel)		56.47		39.23
Natural gas (per thousand cubic feet)***		7.55		6.19


	Millions of Dollars
Exploration Expenses
General administrative; geological and geophysical; and lease rentals	$	227		241
Leasehold impairment		46		32
Dry holes		23		4

	$	296		277

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.

***Prior period revised to conform to current-year presentation.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At March 31, 2014, our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar, Libya and Russia.

In the first quarter of 2014, average production from continuing operations decreased 1 percent compared with the first quarter of 2013. The decrease in total average production primarily resulted from normal field decline, shut-in Libya production due to the closure of the Es Sider crude oil export terminal, the impact from asset dispositions and higher planned downtime. These decreases were partly offset by additional production from major developments, mainly from shale plays in the Lower 48 and the ramp up of production from Jasmine in the United Kingdom and Christina Lake in Canada, and increased drilling programs, mostly in the Lower 48, China, western Canada and Norway. Adjusted for Libya, dispositions and downtime, production from continuing operations increased by 41 MBOED, or 3 percent compared with the first quarter of 2013.

Segment Results

Alaska


	Three Months Ended March 31
	2014		2013


Income From Continuing Operations (millions of dollars)	$	598		543


Average Net Production
Crude oil (MBD)		175		190
Natural gas liquids (MBD)		16		18
Natural gas (MMCFD)		55		56


Total Production (MBOED)		200		218


Average Sales Prices
Crude oil (dollars per barrel)	$	106.39		110.79
Natural gas (dollars per thousand cubic feet)		5.22		5.20

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. As of March 31, 2014, Alaska contributed 22 percent of our worldwide liquids production and 1 percent of our natural gas production.

Alaska operations reported earnings of $598 million in the first quarter of 2014, a 10 percent increase compared with the same period in 2013. Earnings in the first quarter of 2014 benefitted from lower production taxes, mainly as a result of higher 2014 capital spending, lower crude oil production volumes and lower crude oil prices. The increase in earnings was partially offset by lower crude oil volumes and prices.

Production averaged 200 MBOED in the first quarter of 2014, a decrease of 8 percent compared with the first quarter of 2013. The reduction was mainly due to normal field decline.

Lower 48 and Latin America


	Three Months Ended March 31
	2014		2013


Income From Continuing Operations (millions of dollars)	$	320		133


Average Net Production
Crude oil (MBD)		171		148
Natural gas liquids (MBD)		91		87
Natural gas (MMCFD)		1,468		1,441


Total Production (MBOED)		507		475


Average Sales Prices
Crude oil (dollars per barrel)	$	91.52		93.69
Natural gas liquids (dollars per barrel)		36.06		29.58
Natural gas (dollars per thousand cubic feet)		5.08		3.19

As of March 31, 2014, Lower 48 and Latin America contributed 30 percent of our worldwide liquids production and 38 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, as well as exploration activities in the Gulf of Mexico and Colombia.

Lower 48 and Latin America operations reported earnings of $320 million in the first quarter of 2014, a 141 percent increase compared with the same period in 2013. The increase in the first quarter of 2014 was primarily the result of higher natural gas and natural gas liquids prices and higher crude oil volumes. In addition, earnings benefitted approximately $100 million after-tax from marketing third-party natural gas volumes. Earnings also benefitted from the absence of a $60 million after-tax loss recognized in the first quarter of 2013 from the disposition of the majority of our producing zones in the Cedar Creek Anticline. These increases to earnings were partially offset by an $83 million after-tax loss recognized upon the release of underutilized transportation and storage capacity at rates below our contractual rates. Higher DD&A, mostly due to higher crude oil production, higher operating expenses and a $39 million after-tax legal accrual also partly offset the increase in earnings.

Average production in the Lower 48 increased 7 percent in the first quarter of 2014, while average crude oil production increased 16 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, the impact from asset dispositions and higher unplanned downtime.

Canada


	Three Months Ended March 31
	2014		2013


Income From Continuing Operations (millions of dollars)	$	356		133


Average Net Production
Crude oil (MBD)		13		14
Natural gas liquids (MBD)		25		26
Bitumen (MBD)
Consolidated operations		13		13
Equity affiliates		111		96

Total bitumen		124		109
Natural gas (MMCFD)		707		806


Total Production (MBOED)		280		283


Average Sales Prices
Crude oil (dollars per barrel)	$	80.32		72.85
Natural gas liquids (dollars per barrel)		56.13		50.15
Bitumen (dollars per barrel)
Consolidated operations		61.69		36.78
Equity affiliates		55.85		39.52
Total bitumen		56.47		39.23
Natural gas (dollars per thousand cubic feet)		5.81		2.89

Our Canadian operations mainly consist of natural gas fields in western Canada and oil sands developments in the Athabasca Region of northeastern Alberta. As of March 31, 2014, Canada contributed 18 percent of our worldwide liquids production and 18 percent of our natural gas production.

Canada operations reported earnings of $356 million in the first quarter of 2014, an increase of 168 percent compared with the corresponding period of 2013. The increase in earnings was primarily due to significantly higher bitumen and natural gas prices. Earnings in the first quarter of 2014 also benefitted from lower DD&A from western Canada, which mainly resulted from lower unit-of-production rates related to year-end 2013 price-related reserve revisions and lower production volumes. Higher equity earnings, as a result of a foreign currency transaction gain of approximately $60 million after-tax related to cash balances held in FCCL, and higher bitumen volumes also contributed to the increase in earnings. These increases were partially offset by the absence of a $224 million tax benefit recognized in the first quarter of 2013, which related to the favorable tax resolution associated with the sale of certain western Canada properties in a previous year.

Average production decreased 1 percent in the first quarter of 2014, while average liquids production increased 9 percent in the same period, primarily from the oil sands. Normal field decline and higher royalty impacts, as a result of higher prices, were nearly offset by the ramp-up of production from Christina Lake Phase E in FCCL and improved drilling and well performance from western Canada.

Europe


	Three Months Ended
	March 31
	2014		2013


Income From Continuing Operations (millions of dollars)	$	343		431


Average Net Production
Crude oil (MBD)		135		124
Natural gas liquids (MBD)		7		6
Natural gas (MMCFD)		472		461


Total Production (MBOED)		220		207


Average Sales Prices
Crude oil (dollars per barrel)	$	109.05		114.11
Natural gas liquids (dollars per barrel)		60.48		60.10
Natural gas (dollars per thousand cubic feet)		10.94		10.81

The Europe segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, as well as exploration activities in Poland and Greenland. As of March 31, 2014, our Europe operations contributed 16 percent of our worldwide liquids production and 12 percent of our natural gas production.

Europe operations reported earnings of $343 million in the first quarter of 2014, a decrease of 20 percent compared with the corresponding period of 2013. The reduction in earnings was largely due to the absence of an $83 million after-tax gain recognized in the first quarter of 2013 on the disposition of our interest in the Interconnector Pipeline. Higher DD&A, mostly as a result of increased production volumes from Jasmine, and foreign currency transaction losses in the first quarter of 2014, compared with foreign currency transaction gains in the first quarter of 2013, also contributed to the decrease in earnings. These decreases were partly offset by higher crude oil volumes.

Average production increased 6 percent in the first quarter of 2014, mostly due to the continued ramp-up of production from Jasmine, new wells from Ekofisk South, improved drilling and well performance in Norway and lower unplanned downtime. These increases were partly offset by normal field decline.

Asia Pacific and Middle East


	Three Months Ended
	March 31
	2014		2013


Income From Continuing Operations (millions of dollars)	$	756		932


Average Net Production
Crude oil (MBD)
Consolidated operations		86		86
Equity affiliates		14		15

Total crude oil		100		101


Natural gas liquids (MBD)
Consolidated operations		13		14
Equity affiliates		7		8

Total natural gas liquids		20		22


Natural gas (MMCFD)
Consolidated operations		726		684
Equity affiliates		469		483

Total natural gas		1,195		1,167


Total Production (MBOED)		319		318


Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	104.92		109.35
Equity affiliates		107.49		107.80
Total crude oil		105.32		109.12
Natural gas liquids (dollars per barrel)
Consolidated operations		80.07		77.59
Equity affiliates		79.91		77.32
Total natural gas liquids		80.01		77.50
Natural gas (dollars per thousand cubic feet)
Consolidated operations*		10.32		11.20
Equity affiliates		10.43		9.36
Total natural gas*		10.37		10.44

*Prior period revised to conform to current-year presentation.

The Asia Pacific and Middle East segment has producing operations in China, Indonesia, Malaysia, Australia, Timor-Leste and Qatar, as well as exploration activities in Bangladesh and Brunei. As of March 31, 2014, Asia Pacific and Middle East contributed 14 percent of our worldwide liquids production and 31 percent of our natural gas production.

Asia Pacific and Middle East operations reported earnings of $756 million in the first quarter of 2014, a 19 percent decrease compared with the same period in 2013. The decrease in earnings was mainly due to lower crude oil and natural gas liquids sales volumes, as a result of lift timing; lower earnings from equity affiliates, as a result of a DD&A adjustment and foreign exchange-related tax impacts; and higher operating expenses, partly offset by lower taxes.

Average production remained flat in the first quarter of 2014 compared with the first quarter of 2013. Increased production, mainly from China and Indonesia, favorable impacts on production sharing contracts, and lower unplanned downtime were offset by normal field decline and higher planned downtime, primarily from maintenance at QG3.

Other International


	Three Months Ended
	March 31
	2014			2013


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


Average Net Production
Crude oil (MBD)
Consolidated operations		1			44
Equity affiliates		4			5

Total crude oil		5			49


Natural gas (MMCFD)		4			31


Total Production (MBOED)		6			54


Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	-			112.18
Equity affiliates		67.82			75.22
Total crude oil		67.82			108.15
Natural gas (dollars per thousand cubic feet)		6.65			4.86

The Other International segment includes producing operations in Libya and Russia, as well as exploration activities in Angola, Senegal and Azerbaijan.

Other International operations reported a loss of $21 million in the first quarter of 2014, compared with earnings of $14 million in the first quarter of 2013. The decrease was primarily the result of lower volumes from Libya and higher exploration expenses.

Average production decreased 89 percent in the first quarter of 2014, compared with the first quarter of 2013, as a result of the shutdown of the Es Sider crude oil export terminal in Libya which began at the end of July 2013. Libya production remains shut in, as the Es Sider Terminal closure has continued into the second quarter of 2014.

Asset Dispositions

We have an agreement to sell our Nigeria upstream affiliates. In 2013, we sold our Algeria business and our interest in Kashagan. Results of operations related to Nigeria, Algeria and Kashagan have been classified as discontinued operations in all periods presented in this Form 10-Q. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Corporate and Other


	Millions of Dollars
	Three Months Ended March 31
	2014		2013

Income (Loss) From Continuing Operations
Net interest	$	(163)		(108)
Corporate general and administrative expenses		(31)		(27)
Technology		(28)		(8)
Other		(13)		(19)

	$	(235)		(162)

Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased 51 percent in the first quarter of 2014, mainly as a result of lower capitalized interest on projects sold or completed.

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, LNG, and subsurface, arctic and deepwater technologies, with an underlying commitment to environmental responsibility. Losses from Technology increased $20 million in the first quarter of 2014, primarily as a result of lower licensing revenues and higher research and development expenses.

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 2014			December 31 2013


Short-term debt	$	1,712			589
Total debt		21,206			21,662
Total equity		53,621			52,492
Percent of total debt to capital*		28	%		29
Percent of floating-rate debt to total debt**		8	%		8

*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. During the first three months of 2014, the primary uses of our available cash were $3,895 million to support our ongoing capital expenditures and investments program, $855 million to pay dividends and $450 million to repay debt. During the first three months of 2014, cash and cash equivalents increased by $1,274 million to $7,520 million.

In addition to cash flows from operating activities, 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, and required debt payments.

Significant Sources of Capital

Operating Activities

Cash provided by continuing operating activities was $6,278 million for the first three months of 2014, compared with $4,608 million for the corresponding period of 2013, a 36 percent increase. The increase was primarily due to the $1.3 billion distribution from FCCL.

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 have historically been 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 absolute production volumes, as well as product and location mix, impacts our cash flows. Production levels are impacted by such factors as acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiencies, 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

Commercial Paper and Credit Facilities

At March 31, 2014, 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, 2014 and December 31, 2013, we had no direct borrowings or letters of credit issued under the revolving credit facility. In addition, under the ConocoPhillips Qatar Funding Ltd. commercial paper programs, $912 million of commercial paper was outstanding at March 31, 2014, compared with $961 million at December 31, 2013. Since we had $912 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.6 billion in borrowing capacity under our revolving credit facility at March 31, 2014.

Certain of our project-related contracts and derivative instruments contain provisions requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters of credit as collateral. At March 31, 2014 and December 31, 2013, we had direct bank letters of credit of $756 million and $827 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 9—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, 2014, was $21.2 billion, a decrease of $456 million from the balance at December 31, 2013. Our short-term debt balance at March 31, 2014, increased $1.1 billion compared with December 31, 2013, primarily as a result of the timing of scheduled maturities. In February 2014, we repaid notes at maturity totaling $400 million. For more information, see Note 7—Debt, in the Notes to Consolidated Financial Statements.

In February 2014, we announced a dividend of 69 cents per share. The dividend was paid March 3, 2014, to stockholders of record at the close of business on February 18, 2014.

Capital Spending


	Millions of Dollars
	Three Months Ended March 31
	2014		2013


Alaska	$	415		262
Lower 48 and Latin America		1,318		1,280
Canada		622		675
Europe		613		791
Asia Pacific and Middle East		848		337
Other International		44		19
Corporate and Other		35		27

Capital expenditures and investments from continuing operations	$	3,895		3,391

Discontinued operations in Kashagan, Nigeria and Algeria	$	22		189
Joint venture acquisition obligation (principal)—Canada		-		189

Capital Program	$	3,917		3,769

During the first three months of 2014, capital expenditures and investments from continuing operations supported key exploration and development programs, primarily:

—

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

—

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

—

Development of coalbed methane projects associated with the APLNG joint venture in Australia.

—

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

—

Alaska activities related to development in the Greater Kuparuk Area and the Greater Prudhoe Area, as well as exploration and development activities in the Western North Slope.

—

Exploration and appraisal drilling in deepwater Gulf of Mexico.

—

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

—

Exploration activities in Angola.

Contingencies

contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. 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.

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 63–65 of our 2013 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, 2013, we reported we had been notified of potential liability under CERCLA and comparable state laws at 15 sites around the United States. As of March 31, 2014, there was no change in the number of sites.

At March 31, 2014, our balance sheet included a total environmental accrual of $347 million, compared with $348 million at December 31, 2013, for remediation activities in the U.S. and Canada. 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 upon our results of operations or financial position as a result of compliance with current environmental laws and regulations.

Climate Change

There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. Examples of legislation and precursors for possible regulation that do or could affect our operations include the EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)) and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that trigger regulation of GHGs under the Clean Air Act, may trigger more climate-based claims for damages, and may result in longer agency review time for development projects.

For other examples of legislation or precursors for possible regulation 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 65–66 of our 2013 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, bitumen, natural gas, LNG and natural gas liquids.

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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, cyber attacks or infrastructure constraints or disruptions.

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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 and 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, execute asset dispositions.

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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 2013 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, 2014, does not differ materially from that discussed under Item 7A in our 2013 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 the 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, 2014, 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, 2014.

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 2014 and any material developments with respect to matters previously reported in ConocoPhillips’ 2013 Annual Report on Form 10-K. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were to be 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 businesses 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 – Phillips 66

On March 7, 2012, the Bay Area Air Quality Management District (District) in California issued a $302,500 demand to settle five Notices of Violation (NOVs) issued between 2008 and 2010. The NOVs allege non-compliance with the District rules and/or facility permit conditions at the Phillip 66 Rodeo Refinery. Phillips 66 has resolved this matter.

On September 19, 2012, the District issued a $213,500 demand to settle 14 NOVs issued in 2009 and 2010 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery. Phillips 66 has resolved this matter.

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A of our 2013 Annual Report on Form 10-K.

Item 6. EXHIBITS



10.1*		Form of Key Employee Award Agreement, as part of the ConocoPhillips Stock Option Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 18, 2014.

10.2*		Form of Key Employee Award Agreement, as part of the ConocoPhillips Restricted Stock Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 18, 2014.

10.3*		Form of Performance Period IX Award Agreement, as part of the ConocoPhillips Performance Share Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 18, 2014.

10.4*		Form of Performance Period IX Award Agreement—Canada, as part of the ConocoPhillips Performance Share Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 18, 2014.

10.5*		Form of Performance Period X Award Agreement, as part of the ConocoPhillips Performance Share Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 18, 2014.

10.6*		Form of Performance Period X Award Agreement—Canada, as part of the ConocoPhillips Performance Share Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 18, 2014.

10.7*		Form of Performance Period XI Award Agreement, as part of the ConocoPhillips Performance Share Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 18, 2014.

10.8*		Form of Performance Period XI Award Agreement—Canada, as part of the ConocoPhillips Performance Share Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 18, 2014.

10.9*		Form of Performance Period XII Award Agreement, as part of the ConocoPhillips Performance Share Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 18, 2014.

10.10*		Form of Performance Period XII Award Agreement—Canada, as part of the ConocoPhillips Performance Share Program granted under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 18, 2014.

10.11*		Form of Inducement Grant Award Agreement under the 2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated March 31, 2014.

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)

May 6, 2014