Edgar Filing: CONOCOPHILLIPS

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

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, 2015

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

For the transition period from to

Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

Delaware

01-0562944

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

600 North Dairy Ashford, Houston, TX 77079

(Address of principal executive offices) (Zip Code)

281-293-1000

(Registrant’s telephone number, including area code)

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

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

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

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

The registrant had 1,232,946,616 shares of common stock, $.01 par value, outstanding at March 31, 2015.

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		22

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		26

Item 3. Quantitative and Qualitative Disclosures About Market Risk		46

Item 4. Controls and Procedures		46

Part II—Other Information

Item 1. Legal Proceedings		47

Item 1A. Risk Factors		47

Item 6. Exhibits		48

Signature		49

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS


Consolidated Income Statement			ConocoPhillips


	Millions of Dollars
	Three Months Ended March 31
	2015			2014

Revenues and Other Income
Sales and other operating revenues	$	7,716			15,415
Equity in earnings of affiliates		205			572
Gain on dispositions		52			9
Other income		29			52

Total Revenues and Other Income		8,002			16,048


Costs and Expenses
Purchased commodities		3,237			7,127
Production and operating expenses		1,802			1,895
Selling, general and administrative expenses		159			182
Exploration expenses		482			296
Depreciation, depletion and amortization		2,131			1,892
Impairments		16			1
Taxes other than income taxes		224			651
Accretion on discounted liabilities		121			117
Interest and debt expense		202			171
Foreign currency transaction (gains) losses		(16	)		18

Total Costs and Expenses		8,358			12,350

Income (loss) from continuing operations before income taxes		(356	)		3,698
Provision (benefit) for income taxes		(642	)		1,581

Income From Continuing Operations		286			2,117
Income from discontinued operations*		—			20

Net income		286			2,137
Less: net income attributable to noncontrolling interests		(14	)		(14	)

Net Income Attributable to ConocoPhillips	$	272			2,123


Amounts Attributable to ConocoPhillips Common Shareholders:
Income from continuing operations	$	272			2,103
Income from discontinued operations		—			20

Net Income	$	272			2,123


Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic
Continuing operations	$	0.22			1.70
Discontinued operations		—			0.02

Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	0.22			1.72

Diluted
Continuing operations	$	0.22			1.69
Discontinued operations		—			0.02

Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	0.22			1.71


Dividends Paid Per Share of Common Stock (dollars)	$	0.73			0.69


Average Common Shares Outstanding (in thousands)
Basic		1,240,791			1,234,968
Diluted		1,245,531			1,242,667

*Net of provision for income taxes on discontinued operations of:	$	—			32

See Notes to Consolidated Financial Statements.


Consolidated Statement of Comprehensive Income			ConocoPhillips


	Millions of Dollars
	Three Months Ended March 31
	2015			2014

Net Income	$	286			2,137
Other comprehensive income (loss)
Defined benefit plans
Reclassification adjustment for amortization of prior service credit included in net income		(1	)		(2	)
Reclassification adjustment for amortization of net actuarial losses included in net income		50			33
Nonsponsored plans*		—			6
Income taxes on defined benefit plans		(17	)		(11	)

Defined benefit plans, net of tax		32			26

Foreign currency translation adjustments		(2,745	)		(222	)
Income taxes on foreign currency translation adjustments		26			(4	)

Foreign currency translation adjustments, net of tax		(2,719	)		(226	)

Other Comprehensive Loss, Net of Tax		(2,687	)		(200	)

Comprehensive Income (Loss)		(2,401	)		1,937
Less: comprehensive income attributable to noncontrolling interests		(14	)		(14	)

Comprehensive Income (Loss) Attributable to ConocoPhillips	$	(2,415	)		1,923

*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			December 31
	2015			2014

Assets
Cash and cash equivalents	$	2,664			5,062
Accounts and notes receivable (net of allowance of $4 million in 2015 and $5 million in 2014)		5,246			6,675
Accounts and notes receivable—related parties		133			132
Inventories		1,233			1,331
Prepaid expenses and other current assets		1,564			1,868

Total Current Assets		10,840			15,068
Investments and long-term receivables		23,224			24,335
Loans and advances—related parties		750			804
Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $70,256 million in 2015 and $70,786 million in 2014)		74,220			75,444
Other assets		1,008			888

Total Assets	$	110,042			116,539


Liabilities
Accounts payable	$	6,706			7,982
Accounts payable—related parties		44			44
Short-term debt		193			182
Accrued income and other taxes		864			1,051
Employee benefit obligations		552			878
Other accruals		1,204			1,400

Total Current Liabilities		9,563			11,537
Long-term debt		22,318			22,383
Asset retirement obligations and accrued environmental costs		10,304			10,647
Deferred income taxes		14,042			15,070
Employee benefit obligations		2,979			2,964
Other liabilities and deferred credits		1,828			1,665

Total Liabilities		61,034			64,266


Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2015—1,775,177,289 shares; 2014—1,773,583,368 shares)
Par value		18			18
Capital in excess of par		46,136			46,071
Treasury stock (at cost: 2015—542,230,673 shares; 2014—542,230,673 shares)		(36,780	)		(36,780	)
Accumulated other comprehensive loss		(4,589	)		(1,902	)
Retained earnings		43,867			44,504

Total Common Stockholders’ Equity		48,652			51,911
Noncontrolling interests		356			362

Total Equity		49,008			52,273

Total Liabilities and Equity	$	110,042			116,539

See Notes to Consolidated Financial Statements.


Consolidated Statement of Cash Flows			ConocoPhillips


	Millions of Dollars
	Three Months Ended March 31
	2015			2014

Cash Flows From Operating Activities
Net income	$	286			2,137
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		2,131			1,892
Impairments		16			1
Dry hole costs and leasehold impairments		311			69
Accretion on discounted liabilities		121			117
Deferred taxes		(637	)		230
Undistributed equity earnings		80			1,131
Gain on dispositions		(52	)		(9	)
Income from discontinued operations		—			(20	)
Other		(133	)		116
Working capital adjustments
Decrease (increase) in accounts and notes receivable		1,368			(290	)
Decrease (increase) in inventories		77			(27	)
Decrease (increase) in prepaid expenses and other current assets		234			(17	)
Increase (decrease) in accounts payable		(1,302	)		353
Increase (decrease) in taxes and other accruals		(630	)		595

Net cash provided by continuing operating activities		1,870			6,278
Net cash provided by discontinued operations		—			58

Net Cash Provided by Operating Activities		1,870			6,336


Cash Flows From Investing Activities
Capital expenditures and investments		(3,332	)		(3,895	)
Proceeds from asset dispositions		173			48
Net sales of short-term investments		—			63
Collection of advances/loans—related parties		52			62
Other		(9	)		46

Net cash used in continuing investing activities		(3,116	)		(3,676	)
Net cash used in discontinued operations		—			(22	)

Net Cash Used in Investing Activities		(3,116	)		(3,698	)


Cash Flows From Financing Activities
Repayment of debt		(57	)		(450	)
Issuance of company common stock		(34	)		(32	)
Dividends paid		(910	)		(855	)
Other		(18	)		(17	)

Net Cash Used in Financing Activities		(1,019	)		(1,354	)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		(133	)		(10	)


Net Change in Cash and Cash Equivalents		(2,398	)		1,274
Cash and cash equivalents at beginning of period		5,062			6,246

Cash and Cash Equivalents at End of Period	$	2,664			7,520

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 2014 Annual Report on Form 10-K.

Effective April 1, 2014, the Other International segment was restructured to focus on enhancing our capability to operate in emerging and new country business units. As a result, we moved the Latin America and Poland businesses from the historically presented Lower 48 and Latin America segment and the Europe segment to the Other International segment. Results of operations for the Lower 48, Europe and Other International segments have been revised for all periods presented. For additional information, see Note 16—Segment Disclosures and Related Information.

The results of operations for our former Nigeria business have been classified as discontinued operations for all periods presented. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations.

Note 2—Variable Interest Entities (VIEs)

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

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 liquefied natural gas (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, 2015, 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 4—Investments, Loans and Long-Term Receivables, and Note 8—Guarantees, for additional information.

Note 3—Inventories

Inventories consisted of the following:


	Millions of Dollars
	March 31 2015		December 31 2014

Crude oil and natural gas	$	456		538
Materials, supplies and other		777		793

	$	1,233		1,331

Inventories valued on the last-in, first-out (LIFO) basis totaled $330 million and $440 million at March 31, 2015 and December 31, 2014, respectively.

Note 4—Investments, Loans and Long-Term Receivables

APLNG

APLNG’s $8.5 billion project finance 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, 2015, $8.3 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 8—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 2—Variable Interest Entities (VIEs), for additional information.

At March 31, 2015, the book value of our equity method investment in APLNG was $11,718 million, net of a $671 million reduction due to cumulative translation effects. The balance is included in the “Investments and long-term receivables” line on our consolidated balance sheet.

FCCL

At March 31, 2015, the book value of our equity method investment in FCCL was $8,637 million, net of a $1,216 million reduction due to cumulative translation effects. The balance is included in the “Investments and long-term receivables” line on our consolidated balance sheet. In the first quarter of 2014, we received a $1.3 billion distribution from FCCL, 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. At March 31, 2015, significant loans to affiliated companies included $857 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 5—Suspended Wells

The capitalized cost of suspended wells at March 31, 2015, was $1,310 million, an increase of $11 million from $1,299 million at year-end 2014. No suspended wells were charged to dry hole expense during the first three months of 2015 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2014.

Note 6—Debt

We have two commercial paper programs supported by our $7.0 billion revolving credit facility: the ConocoPhillips $6.1 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $900 million program, which is used to fund commitments relating to QG3. Commercial paper maturities are generally limited to 90 days.

At March 31, 2015 and December 31, 2014, we had no direct outstanding borrowings under the revolving credit facility, with no letters of credit as of March 31, 2015 or December 31, 2014. In addition, under the ConocoPhillips Qatar Funding Ltd. commercial paper program, there was $806 million of commercial paper outstanding at March 31, 2015, compared with $860 million at December 31, 2014. Since we had $806 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.2 billion in borrowing capacity under our revolving credit facility at March 31, 2015.

At March 31, 2015, we classified $698 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.

Note 7—Noncontrolling Interests

Activity attributable to common stockholders’ equity and noncontrolling interests for the first three months of 2015 and 2014 was as follows:


	Millions of Dollars
	2015									2014
	Common Stockholders’ Equity			Non- Controlling Interest			Total Equity			Common Stockholders’ Equity			Non- Controlling Interest			Total Equity

Balance at January 1	$	51,911			362			52,273			52,090			402			52,492
Net income		272			14			286			2,123			14			2,137
Dividends		(910	)		—			(910	)		(855	)		—			(855	)
Distributions to noncontrolling interests		—			(21	)		(21	)		—			(17	)		(17	)
Other changes, net*		(2,621	)		1			(2,620	)		(136	)		—			(136	)

Balance at March 31	$	48,652			356			49,008			53,222			399			53,621

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

Note 8—Guarantees

At March 31, 2015, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.

APLNG Guarantees

At March 31, 2015, 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 2015 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 two years. Our maximum potential amount of future payments related to this guarantee is approximately $90 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 should occur beginning in 2016. Our maximum exposure at March 31, 2015, is $3.1 billion based upon our pro-rata share of the facility used at that date. At March 31, 2015, the carrying value of this guarantee is approximately $114 million.

•

In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy in October 2008, we agreed to guarantee an existing obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of 1 to 27 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1.2 billion ($2.1 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 31 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $150 million and would become payable if APLNG does not perform.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $300 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 9 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, 2015, was approximately $90 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, 2015, were approximately $40 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 9—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.

On March 1, 2015, a supplier to one of the refineries that was included in Phillips 66 as part of the separation of our Downstream businesses formally registered Phillips 66 as a party to the supply agreement, thereby triggering a guarantee we provided at the time of separation. Our maximum potential liability for future payments under this guarantee, which would become payable if Phillips 66 does not perform its contractual obligations under the supply agreement, is approximately $1.7 billion. At March 31, 2015, the carrying value of this guarantee is approximately $100 million and the remaining term is 9 years. Because Phillips 66 has indemnified us for losses incurred under this guarantee, we have recorded an indemnification asset from Phillips 66 of approximately $100 million. The recorded indemnification asset amount represents the estimated fair value of the guarantee; however, if we are required to perform under the guarantee, we would expect to recover from Phillips 66 any amounts in excess of that value, provided Phillips 66 is a going concern.

Note 9—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, 2015, our balance sheet included a total environmental accrual of $322 million, compared with $344 million at December 31, 2014, for remediation activities in the United States 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.

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, 2015, we had performance obligations secured by letters of credit of $472 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 is currently proceeding to determine the damages owed to ConocoPhillips for Venezuela’s actions. On October 10, 2014, we filed a separate arbitration under the rules of the International Chamber of Commerce against PDVSA for contractual compensation related to the Petrozuata and Hamaca heavy crude oil projects.

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 31, 2015, ConocoPhillips has paid, under protest, tax assessments totaling approximately $237 million, which are primarily recorded in the “Investments and long-term receivables” line on our consolidated balance sheet. The arbitration hearing was conducted in Singapore in June 2014 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. Post-hearing briefs from both parties were filed in August 2014. We are now awaiting the Tribunal’s decision. Future impacts on our business are not known at this time.

Note 10—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 2015		December 31 2014

Assets
Prepaid expenses and other current assets	$	3,593		4,500
Other assets		162		157
Liabilities
Other accruals		3,590		4,426
Other liabilities and deferred credits		157		144

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
	2015			2014

Sales and other operating revenues	$	(16	)		237
Other income		(1	)		1
Purchased commodities		44			(221	)

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


	Open Position Long/(Short)
	March 31 2015			December 31 2014

Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price		(5	)		(11	)
Basis		(3	)		18

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 2015		December 31 2014

Assets
Prepaid expenses and other current assets	$	2		1
Liabilities
Other accruals		21		1

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


	Millions of Dollars
	Three Months Ended March 31
	2015		2014

Foreign currency transaction losses	$	24		—

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


	In Millions Notional Currency
	March 31 2015		December 31 2014


Sell U.S. dollar, buy other currencies*	USD	624		7
Buy U.S. dollar, sell other currencies**	USD	9		44
Sell British pound, buy euro	GBP	7		—
Buy British pound, sell euro	GBP	—		20

*Primarily Canadian dollar, Norwegian krone and British pound.

**Primarily Canadian dollar, Norwegian krone and euro.

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.


	Millions of Dollars
	Carrying Amount
	Cash and Cash Equivalents
	March 31 2015		December 31 2014


Cash	$	535		946
Money Market Funds		—		50
Time deposits
Remaining maturities from 1 to 90 days		2,129		3,726
Commercial paper
Remaining maturities from 1 to 90 days		—		340

	$	2,664		5,062

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 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, 2015 and December 31, 2014, was $121 million and $150 million, respectively. For these instruments, no collateral was posted as of March 31, 2015 or December 31, 2014. If our credit rating had been lowered one level from its “A” rating (per Standard and Poor’s) on March 31, 2015, 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 $121 million of additional collateral, either with cash or letters of credit.

Note 11—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 2015 or 2014.

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, 2015								December 31, 2014
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total

Assets
Deferred compensation investments	$	296		—		—		296		297		—		—		297
Commodity derivatives		3,452		232		71		3,755		4,221		361		75		4,657

Total assets	$	3,748		232		71		4,051		4,518		361		75		4,954


Liabilities
Commodity derivatives	$	3,481		254		12		3,747		4,200		354		16		4,570

Total liabilities	$	3,481		254		12		3,747		4,200		354		16		4,570

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, 2015
Assets	$	3,755		3,550		205		7		13		185
Liabilities		3,747		3,550		197		37		10		150


December 31, 2014
Assets	$	4,657		4,352		305		8		28		269
Liabilities		4,570		4,352		218		4		22		192

At March 31, 2015 and December 31, 2014, 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: 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 4—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
2015

December 31
2014

March 31
2015

December 31
2014

Financial assets

Deferred compensation investments

296

297

296

297

Commodity derivatives

198

297

198

297

Total loans and advances—related parties

859

913

859

913

Financial liabilities

Total debt, excluding capital leases

21,650

21,707

25,460

25,191

Commodity derivatives

160

214

160

214

Note 12—Accumulated Other Comprehensive Income

Accumulated other comprehensive income (loss) 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, 2014	$	(1,261	)		(641	)		(1,902	)
Other comprehensive income (loss)		32			(2,719	)		(2,687	)

March 31, 2015	$	(1,229	)		(3,360	)		(4,589	)

Foreign Currency Translation decreased due to the strengthening of the U.S. dollar relative to the Canadian dollar, Australian dollar and Norwegian krone.

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


	Millions of Dollars
	Three Months Ended March 31
	2015		2014

Defined Benefit Plans	$	32		20

The above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of $17 million and $11 million for the three-month periods ended March 31, 2015 and 2014, respectively. See Note 14—Employee Benefit Plans, for additional information.

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

Note 13—Cash Flow Information


	Millions of Dollars
	Three Months Ended March 31
	2015			2014

Cash Payments (Receipts)
Interest	$	197			199
Income taxes*		(253	)		667


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

	$	—			63

*Includes $556 million in 2015 related to a refund received from the Internal Revenue Service for 2014 overpaid taxes.

Note 14—Employee Benefit Plans

Pension and Postretirement Plans


	Millions of Dollars
	Pension Benefits												Other Benefits
Three Months Ended	March 31												March 31
	2015						2014						2015			2014

	U.S.			Int’l.			U.S.			Int’l.

Components of Net Periodic Benefit Cost
Service cost	$	36			32			31			28			1			1
Interest cost		40			34			41			42			7			7
Expected return on plan assets		(54	)		(44	)		(53	)		(46	)		—			—
Amortization of prior service cost (credit)		2			(2	)		1			(2	)		(1	)		(1	)
Recognized net actuarial loss (gain)		28			21			19			15			1			(1	)

Net periodic benefit cost	$	52			41			39			37			8			6

During the first three months of 2015, we contributed $14 million to our domestic benefit plans and $44 million to our international benefit plans. In 2015, we expect to contribute approximately $110 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $120 million to our international qualified and nonqualified pension and postretirement benefit plans.

Due to an ongoing restructuring program in the Europe segment, we recognized additional expense of $50 million associated with employee special termination benefits during the three-month period ended March 31, 2015, of which approximately 62 percent is expected to be recovered from partners.

Severance Accrual

As a result of the current business environment’s impact on our operating and capital plans, a reduction in our overall employee workforce is expected in 2015. The following segments recorded accruals totaling $85 million in the first quarter of 2015 for severance and related employee benefits: $33 million in Corporate and Other, $25 million in Lower 48, $24 million in Canada, $2 million in Alaska, and $1 million in Asia Pacific and Middle East. The following table summarizes our severance accrual activity:


	Millions of Dollars

Balance at January 1, 2015	$	61
Accruals		85
Benefit payments		(13	)
Foreign currency translation adjustments		(4	)

Balance at March 31, 2015	$	129

Of the remaining balance at March 31, 2015, $88 million is classified as short-term.

Note 15—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
	2015			2014

Operating revenues and other income	$	25			21
Purchases		22			48
Operating expenses and selling, general and administrative expenses*		18			18
Net interest (income) expense**		(2	)		(12	)

*2014 has been restated to eliminate certain non-related party transactions.

**We paid interest to, or received interest from various affiliates. See Note 4—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

Note 16—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 primarily defined by geographic region: Alaska, Lower 48, Canada, Europe, Asia Pacific and Middle East, and Other International.

Effective April 1, 2014, the Other International segment was restructured to focus on enhancing our capability to operate in emerging and new country business units. As a result, we moved the Latin America and Poland businesses from the historically presented Lower 48 and Latin America segment and the Europe segment to the Other International segment. Results of operations for the Lower 48, Europe and Other International segments have been revised for all periods presented. There was no impact on our consolidated financial statements, and the impact on our segment presentation was immaterial.

In 2012, we agreed to sell our Nigeria business. We sold our Nigeria business in the third quarter of 2014. Results for these operations have been reported as discontinued operations in all periods presented.

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.

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

Analysis of Results by Operating Segment


	Millions of Dollars
	Three Months Ended March 31
	2015			2014

Sales and Other Operating Revenues
Alaska	$	1,050			2,186

Lower 48		3,139			6,584
Intersegment eliminations		(22	)		(38	)

Lower 48		3,117			6,546

Canada		703			1,859
Intersegment eliminations		(110	)		(345	)

Canada		593			1,514

Europe		1,554			3,209
Asia Pacific and Middle East		1,388			1,949
Other International		(5	)		2
Corporate and Other		19			9

Consolidated sales and other operating revenues	$	7,716			15,415


Net Income (Loss) Attributable to ConocoPhillips
Alaska	$	145			598
Lower 48		(405	)		324
Canada		(158	)		356
Europe		637			347
Asia Pacific and Middle East		395			742
Other International		(93	)		(29	)
Corporate and Other		(249	)		(235	)
Discontinued operations		—			20

Consolidated net income (loss) attributable to ConocoPhillips	$	272			2,123


	Millions of Dollars
	March 31 2015			December 31 2014


Total Assets
Alaska	$	12,913			12,655
Lower 48		29,905			30,185
Canada		20,035			21,764
Europe		15,020			16,125
Asia Pacific and Middle East		25,015			25,976
Other International		2,025			1,961
Corporate and Other		5,129			7,815
Discontinued operations		—			58

Consolidated total assets	$	110,042			116,539

Note 17—Income Taxes

Our effective tax rate from continuing operations for the first quarter of 2015 was 180 percent compared with 43 percent for the first quarter of 2014. The increase in the effective tax rate was primarily due to the effect of the 2015 U.K. tax law change discussed below, partially offset by positive earnings in higher tax rate jurisdictions in 2015.

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

In the United Kingdom, legislation was enacted on March 26, 2015, to decrease the overall U.K. upstream corporation tax rate from 62 percent to 50 percent effective January 1, 2015. As a result, a $555 million net tax benefit for revaluing the U.K. deferred tax liability is reflected in the “Provision (benefit) for income taxes” line on our consolidated income statement.

Note 18—New Accounting Standards

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers,” which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. This ASU supersedes the revenue recognition requirements in FASB Accounting Standards Codification (ASC) Topic 605, “Revenue Recognition,” and most industry-specific guidance. This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. The ASU is currently effective for interim and annual periods beginning after December 15, 2016. Early adoption is not permitted. Entities may choose to adopt the standard using either a full retrospective approach or a modified retrospective approach. We are currently evaluating the impact of the adoption of this ASU.

In February 2015, the FASB issued ASU No. 2015-02, “Amendments to the Consolidation Analysis,” which amends existing requirements applicable to reporting entities that are required to evaluate whether certain legal entities should be consolidated. The ASU is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted. Entities may choose to adopt the standard using either a full retrospective approach or a modified retrospective approach. We are currently evaluating the impact of the adoption of this ASU.

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.

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

In April 2015, ConocoPhillips received a $2 billion return of capital from ConocoPhillips Company to settle certain accumulated intercompany balances. The transaction will be reflected in the second quarter 2015 Condensed Consolidating Financial Information for ConocoPhillips and ConocoPhillips Company and is expected to have no impact on our consolidated financial statements.


	Millions of Dollars
	Three Months Ended March 31, 2015
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	$	—			2,933			—			4,783			—			7,716
Equity in earnings of affiliates		381			813			—			578			(1,567	)		205
Gain on dispositions		—			31			—			21			—			52
Other income		—			7			—			22			—			29
Intercompany revenues		19			98			64			843			(1,024	)		—

Total Revenues and Other Income		400			3,882			64			6,247			(2,591	)		8,002

Costs and Expenses
Purchased commodities		—			2,560			—			1,494			(817	)		3,237
Production and operating expenses		—			400			—			1,434			(32	)		1,802
Selling, general and administrative expenses		3			120			—			45			(9	)		159
Exploration expenses		—			200			—			282			—			482
Depreciation, depletion and amortization		—			259			—			1,872			—			2,131
Impairments		—			—			—			16			—			16
Taxes other than income taxes		—			69			—			155			—			224
Accretion on discounted liabilities		—			14			—			107			—			121
Interest and debt expense		121			101			57			89			(166	)		202
Foreign currency transaction (gains) losses		63			(1	)		(378	)		300			—			(16	)

Total Costs and Expenses		187			3,722			(321	)		5,794			(1,024	)		8,358

Income (loss) from continuing operations before income taxes		213			160			385			453			(1,567	)		(356	)
Provision (benefit) for income taxes		(59	)		(221	)		11			(373	)		—			(642	)

Income From Continuing Operations		272			381			374			826			(1,567	)		286
Income from discontinued operations		—			—			—			—			—			—

Net income		272			381			374			826			(1,567	)		286
Less: net income attributable to noncontrolling interests		—			—			—			(14	)		—			(14	)

Net Income Attributable to ConocoPhillips	$	272			381			374			812			(1,567	)		272

Comprehensive Income (Loss) Attributable to ConocoPhillips	$	(2,415	)		(2,306	)		30			(1,874	)		4,150			(2,415	)


Income Statement	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 (benefit) 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
	March 31, 2015
Balance Sheet	ConocoPhillips			ConocoPhillips Company		ConocoPhillips Canada Funding Company I			All Other Subsidiaries		Consolidating Adjustments			Total Consolidated
Assets
Cash and cash equivalents	$	—			64		8			2,592		—			2,664
Accounts and notes receivable		18			1,936		20			6,989		(3,584	)		5,379
Inventories		—			170		—			1,063		—			1,233
Prepaid expenses and other current assets		6			668		23			912		(45	)		1,564

Total Current Assets		24			2,838		51			11,556		(3,629	)		10,840
Investments, loans and long-term receivables*		53,220			70,182		3,760			30,685		(133,873	)		23,974
Net properties, plants and equipment		—			9,910		—			64,310		—			74,220
Other assets		39			171		357			1,198		(757	)		1,008

Total Assets	$	53,283			83,101		4,168			107,749		(138,259	)		110,042

Liabilities and Stockholders’ Equity
Accounts payable	$	—			4,477		15			5,842		(3,584	)		6,750
Short-term debt		(5	)		6		6			186		—			193
Accrued income and other taxes		—			67		—			797		—			864
Employee benefit obligations		—			401		—			151		—			552
Other accruals		101			332		85			731		(45	)		1,204

Total Current Liabilities		96			5,283		106			7,707		(3,629	)		9,563
Long-term debt		7,542			8,195		2,973			3,608		—			22,318
Asset retirement obligations and accrued environmental costs		—			1,335		—			8,969		—			10,304
Deferred income taxes		—			244		—			13,804		(6	)		14,042
Employee benefit obligations		—			2,169		—			810		—			2,979
Other liabilities and deferred credits*		3,552			7,583		1,048			16,370		(26,725	)		1,828

Total Liabilities		11,190			24,809		4,127			51,268		(30,360	)		61,034
Retained earnings		37,345			21,828		(722	)		18,163		(32,747	)		43,867
Other common stockholders’ equity		4,748			36,464		763			37,962		(75,152	)		4,785
Noncontrolling interests		—			—		—			356		—			356

Total Liabilities and Stockholders’ Equity	$	53,283			83,101		4,168			107,749		(138,259	)		110,042

*Includes intercompany loans.

	December 31, 2014
Balance Sheet	ConocoPhillips			ConocoPhillips Company		ConocoPhillips Canada Funding Company I			All Other Subsidiaries		Consolidating Adjustments			Total Consolidated
Assets
Cash and cash equivalents	$	—			770		7			4,285		—			5,062
Accounts and notes receivable		20			2,813		22			6,671		(2,719	)		6,807
Inventories		—			281		—			1,050		—			1,331
Prepaid expenses and other current assets		6			754		15			1,138		(45	)		1,868

Total Current Assets		26			4,618		44			13,144		(2,764	)		15,068
Investments, loans and long-term receivables*		55,568			70,732		3,965			32,467		(137,593	)		25,139
Net properties, plants and equipment		—			9,730		—			65,714		—			75,444
Other assets		40			67		208			1,338		(765	)		888

Total Assets		55,634			85,147		4,217			112,663		(141,122	)		116,539

Liabilities and Stockholders’ Equity
Accounts payable		1			4,149		14			6,581		(2,719	)		8,026
Short-term debt		(5	)		6		5			176		—			182
Accrued income and other taxes		—			117		—			934		—			1,051
Employee benefit obligations		—			595		—			283		—			878
Other accruals		170			337		71			868		(46	)		1,400

Total Current Liabilities		166			5,204		90			8,842		(2,765	)		11,537
Long-term debt		7,541			8,197		2,974			3,671		—			22,383
Asset retirement obligations and accrued environmental costs		—			1,328		—			9,319		—			10,647
Deferred income taxes		—			265		—			14,811		(6	)		15,070
Employee benefit obligations		—			2,162		—			802		—			2,964
Other liabilities and deferred credits*		2,577			7,391		1,142			17,218		(26,663	)		1,665

Total Liabilities		10,284			24,547		4,206			54,663		(29,434	)		64,266
Retained earnings		37,983			21,448		(1,096	)		17,355		(31,186	)		44,504
Other common stockholders’ equity		7,367			39,152		1,107			40,283		(80,502	)		7,407
Noncontrolling interests		—			—		—			362		—			362

Total Liabilities and Stockholders’ Equity	$	55,634			85,147		4,217			112,663		(141,122	)		116,539

*Includes intercompany loans.


	Millions of Dollars
	Three Months Ended March 31, 2015
Statement of Cash Flows	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	$	(131	)		(171	)		1		2,082			89			1,870
Net cash provided by (used in) discontinued operations		—			—			—		—			—			—

Net Cash Provided by (Used in) Operating Activities		(131	)		(171	)		1		2,082			89			1,870

Cash Flows From Investing Activities
Capital expenditures and investments		—			(941	)		—		(2,759	)		368			(3,332	)
Proceeds from asset dispositions		—			88			—		88			(3	)		173
Long-term advances/loans—related parties		—			(72	)		—		(1,482	)		1,554			—
Collection of advances/loans—related parties		—			—			—		52			—			52
Intercompany cash management		974			(1,085	)		—		111			—			—
Other		—			(7	)		—		(2	)		—			(9	)

Net cash provided by (used in) continuing investing activities		974			(2,017	)		—		(3,992	)		1,919			(3,116	)
Net cash provided by (used in) discontinued operations		—			—			—		—			—			—

Net Cash Provided by (Used in) Investing Activities		974			(2,017	)		—		(3,992	)		1,919			(3,116	)

Cash Flows From Financing Activities
Issuance of debt		—			1,482			—		72			(1,554	)		—
Repayment of debt		—			—			—		(57	)		—			(57	)
Issuance of company common stock		66			—			—		—			(100	)		(34	)
Dividends paid		(910	)		—			—		(11	)		11			(910	)
Other		1			—			—		346			(365	)		(18	)

Net cash provided by (used in) continuing financing activities		(843	)		1,482			—		350			(2,008	)		(1,019	)
Net cash used in discontinued operations		—			—			—		—			—			—

Net Cash Provided by (Used in) Financing Activities		(843	)		1,482			—		350			(2,008	)		(1,019	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			—		(133	)		—			(133	)

Net Change in Cash and Cash Equivalents		—			(706	)		1		(1,693	)		—			(2,398	)
Cash and cash equivalents at beginning of period		—			770			7		4,285			—			5,062

Cash and Cash Equivalents at End of Period	$	—			64			8		2,592			—			2,664


	Three Months Ended March 31, 2014
Statement of Cash Flows	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 (used in) 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 (purchases) 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 provided by (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 provided by (used in) discontinued operations		—			—			—		(99	)		99			—

Net Cash Provided by (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

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 45.

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.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural gas. Headquartered in Houston, Texas, we had operations and activities in 27 countries, approximately 18,800 employees worldwide and total assets of $110 billion as of March 31, 2015.

Overview

We are an independent E&P company focused on exploring for, developing and producing crude oil and natural gas globally. Our diverse portfolio primarily includes resource-rich North American unconventional assets; oil sands assets in Canada; lower-risk legacy assets in North America, Europe, Asia and Australia; several major international developments; and an inventory of global conventional and unconventional exploration prospects.

Our value proposition to our shareholders is to deliver a compelling dividend and predictable growth, with a focus on margins and financial returns. In response to a view that commodity prices could be lower and more volatile in the future, we recently updated our three-year operating plan. The plan anticipates annual capital spending of about $11.5 billion in 2015 to 2017, a decrease of about 30 percent compared to the company’s previous plan. Based on this revised plan, we expect to deliver on our value proposition, while achieving production of 1.7 million barrels of oil equivalent per day and cash flow neutrality (cash from continuing operations sufficient to fund our dividend and capital program) in 2017. To achieve these goals, we plan to continue to invest in high-margin developments, apply technical capabilities, maintain financial flexibility and actively pursue operating cost reductions. We have targeted a $1 billion reduction in operating costs in 2016, compared with 2014. Operating costs include production and operating expense; selling, general and administrative expense; and exploration expense excluding dry hole and impairment expense.

Based on our announced 2015 capital budget of $11.5 billion, we expect to achieve 2 to 3 percent production growth in 2015 through investments in our conventional and unconventional assets, as well as project startups, which include Surmont 2, Australia Pacific LNG Pty Ltd (APLNG), CD5, Drill Site 2 and Enochdhu. During the first quarter, the company achieved first production at Eldfisk II and the Brodgar H3 subsea tie-back in Europe and Bayu-Undan Phase III in Australia.

We achieved production of 1,610 thousand barrels of oil equivalent per day (MBOED) in the first quarter of 2015. Adjusted for downtime and dispositions of 2 MBOED, our production from continuing operations, excluding Libya, increased by 82 MBOED, or 5 percent, compared with the first quarter of 2014. Consistent with our commitment to offer our shareholders a compelling dividend, we paid dividends on our common stock of $0.9 billion.

We participate in a capital-intensive industry. As a result, we invest significant capital to acquire acreage, explore for new oil and natural gas fields, develop newly discovered fields, maintain existing fields, and construct infrastructure and liquefied natural gas (LNG) facilities. In the first quarter of 2015, we funded $3.3 billion of capital expenditures, or 29 percent of our annual capital budget. Capital spending is expected to decrease throughout the year as major projects come online and activity ramps down from first quarter levels. We use a disciplined approach to allocate capital to the investment opportunities that will provide the most attractive investment returns in our portfolio. We are focused on growing organically and target investments that will drive higher-margin production from oil, condensate and LNG projects. During the past few years, we have dramatically reduced dry gas drilling in North America. We expect a continued shift in our production mix, as investments bring more liquids production online. As our major capital projects start up, we plan to direct more of our capital to unconventionals, while maintaining the flexibility to respond to changing market conditions. We continue to actively monitor the commodity price environment and will further reduce capital and/or exercise capacity on our balance sheet, as necessary.

Basis of Presentation

Effective April 1, 2014, the Other International segment was restructured to focus on enhancing our capability to operate in emerging and new country business units. As a result, we moved the Latin America and Poland businesses from the historically presented Lower 48 and Latin America segment and the Europe segment to the Other International segment. Results of operations for the Lower 48, Europe and Other International segments have been revised for all periods presented. There was no impact on our consolidated financial results, and the impact on our segment presentation was immaterial. For additional information, see Note 16—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements.

Business Environment

The energy landscape has changed dramatically in the past year. In the first half of 2014, strong crude oil prices were supported by geopolitical tensions impacting supplies, as well as global oil demand growth. This was followed by an abrupt decline in prices beginning in mid-2014 to near five-year lows, as surging production growth from U.S. shale and the decision by the Organization of Petroleum Exporting Countries (OPEC) to maintain production outweighed fears of supply disruptions. This, combined with lower forecasts for global oil demand growth, caused crude oil prices to plummet at the end of 2014. Prices remained low, in the upper $40- to low $50-per-barrel range, in the first quarter of 2015.

The energy industry has periodically experienced this type of extreme volatility due to fluctuating supply and demand conditions. Dramatic swings in commodity prices impact our profitability and cash flows, but are largely beyond our control. Commodity prices are the most significant factor impacting our profitability and related reinvestment of operating cash flows into our business. Other dynamics which have influenced world energy markets and commodity prices included 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. 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. In order to navigate through a volatile market, our strategy is to maintain a strong balance sheet with a diverse and flexible portfolio of assets that can provide the resilience 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 $53.97 per barrel in the first quarter of 2015, a decrease of 50 percent compared with $108.22 per barrel in the first quarter of 2014. Industry crude prices for WTI averaged $48.56 per barrel in the first quarter of 2015, a decrease of 51 percent compared with $98.75 per barrel in the first quarter of 2014. Crude oil prices have remained under pressure in the first quarter of 2015 due to increased U.S. production, OPEC’s decision to maintain production levels, and weaker-than-expected demand in Europe and Asia.

Henry Hub natural gas prices averaged $2.99 per thousand cubic feet (MCF) in the first quarter of 2015, a decrease of 40 percent compared with $4.94 per MCF in the first quarter of 2014. Natural gas prices remained under pressure as production growth continued and U.S. underground gas storage inventories stayed near the five-year average even after a colder-than-normal winter.

While the Canadian heavy crude differential versus WTI remained relatively constant between the fourth quarter of 2014 and first quarter of 2015, declining global crude oil prices contributed to the Western Canada Select benchmark price experiencing a significant decline in the first quarter of 2015, from $58.90 per barrel in the fourth quarter of 2014 to $33.86 per barrel in the first quarter of 2015. As a result, our realized bitumen price experienced a corresponding decrease, from $37.76 per barrel in the fourth quarter of 2014 to $17.22 per barrel in the first quarter of 2015, a decrease of 54 percent.

Our total average realized price was $36.96 per barrel of oil equivalent (BOE) in the first quarter of 2015, a decrease of 48 percent compared with $71.21 per BOE in the first quarter of 2014, which reflected lower average realized prices for crude oil, natural gas, bitumen and natural gas liquids.

Key Operating and Financial Highlights

Significant highlights during the first quarter of 2015 included the following:

•

First-quarter total production of 1,610 MBOED represents a 5 percent growth in production from continuing operations when adjusted for Libya, downtime and dispositions, compared to the same period in 2014.

•

First production at Eldfisk II and the Brodgar H3 subsea tie-back in Europe, as well as Bayu-Undan Phase III in Australia.

•

On track for five major project startups at Surmont 2, APLNG, Enochdhu, CD5 and Drill Site 2S by year-end.

•

Exploration and appraisal activity ongoing with conventional activity in the Gulf of Mexico and Angola; unconventional activity in the Lower 48 and Canada.

Outlook

Production and Capital Guidance

Second-quarter 2015 production guidance, excluding Libya, is expected to be 1,555 MBOED to 1,595 MBOED, reflecting planned downtime and turnaround activity. Full-year 2015 production is unchanged from previous guidance and is expected to grow 2 to 3 percent, excluding Libya.

We are on track to achieve our target of $11.5 billion in capital expenditures and investments in 2015. Capital spending is expected to decrease throughout the year as major projects come online and activity ramps down from first quarter levels.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three-month period ended March 31, 2015, is based on a comparison with the corresponding period of 2014.

Consolidated Results

A summary of the Company’s income (loss) from continuing operations by business segment follows:


	Millions of Dollars
	Three Months Ended March 31
	2015			2014

Alaska	$	145			598
Lower 48		(405	)		324
Canada		(158	)		356
Europe		637			347
Asia Pacific and Middle East		409			756
Other International		(93	)		(29	)
Corporate and Other		(249	)		(235	)

Income from continuing operations	$	286			2,117

Earnings for ConocoPhillips decreased 86 percent in the first quarter of 2015. The decrease primarily resulted from lower commodity prices.

In addition, earnings were negatively impacted by:

•

Higher depreciation, depletion and amortization (DD&A) expenses, mainly due to higher volumes, partly offset by lower unit-of-production rates from reserve additions.

•

Higher exploration expenses.

These items were partially offset by:

•

A $555 million net deferred tax benefit resulting from a change in the U.K. tax rate.

•

Higher crude oil, bitumen and LNG sales volumes and a continued portfolio shift toward liquids.

•

The absence of an $83 million after-tax loss in the first quarter of 2014 related to releases of capacity on transportation and storage capacity agreements.

•

Lower operating expenses.

See the “Segment Results” section for additional information.

Income Statement Analysis

Sales and other operating revenues decreased 50 percent in the first quarter of 2015, mainly as a result of lower prices across all commodities, partly offset by higher crude oil, bitumen, LNG and natural gas volumes.

Equity in earnings of affiliates decreased 64 percent in the first quarter of 2015, primarily as a result of lower earnings from the FCCL Partnership and Qatargas 3 (QG3) due to lower commodity prices. This decrease is partly offset by benefits of foreign exchange-related tax impacts from APLNG.

Purchased commodities decreased 55 percent in the first quarter of 2015, largely as a result of lower natural gas prices and the absence of a $130 million loss in the Lower 48 related to transportation and storage capacity agreements.

Production and operating expenses decreased 5 percent in the first quarter of 2015 as a result of favorable foreign exchange-related impacts in Canada and lower operating expense activity across all segments, partly offset by restructuring charges.

Exploration expenses increased 63 percent in the first quarter of 2015 primarily due to increased dry hole costs associated with the Omosi-1 well in Angola and the Harrier prospect in the Gulf of Mexico.

DD&A increased 13 percent in the first quarter of 2015. The increase was mostly associated with higher production volumes in the Lower 48, Canada, and Asia Pacific and Middle East (APME). The increase was partly offset by lower unit-of-production rates in Lower 48 and Canada, as well as favorable foreign exchange-related impacts in Canada.

Taxes other than income taxes decreased 66 percent in the first quarter of 2015, mainly as a result of lower crude oil prices and volumes in Alaska and lower commodity prices in APME.

See Note 17—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
	2015		2014

Average Net Production
Crude oil (MBD)*		622		599
Natural gas liquids (MBD)		155		159
Bitumen (MBD)		156		124
Natural gas (MMCFD)**		4,059		3,901

Total Production (MBOED)		1,610		1,532


	Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)	$	48.05		101.59
Natural gas liquids (per barrel)		19.60		46.52
Bitumen (per barrel)		17.22		56.47
Natural gas (per thousand cubic feet)		4.72		7.55


	Millions of Dollars
Exploration Expenses
General administrative, geological and geophysical, and lease rentals	$	171		227
Leasehold impairment		40		46
Dry holes		271		23

	$	482		296

Excludes discontinued operations.

*Thousands of barrels per day.

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

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At March 31, 2015, our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar, Libya and Russia.

Total production from continuing operations, including Libya, increased 5 percent in the first quarter of 2015 compared with the same period in 2014, while average liquids production increased 6 percent over the same period. The increase in total average production primarily resulted from additional production from major developments, mainly from shale plays in the Lower 48 and the ramp up of production from Gumusut in Malaysia, APLNG in Australia, the Jasmine Field and the Britannia Long-Term Compression Project in the U.K. and Foster Creek Phase F in Canada, as well as improved well performance, mostly in the Lower 48, western Canada and Norway. These increases were largely offset by normal field decline. In the first quarter of 2015, we achieved production of 1,610 MBOED. Adjusted for downtime and dispositions of 2 MBOED, our production from continuing operations, excluding Libya, increased by 82 MBOED, or 5 percent, compared with the first quarter of 2014.

Segment Results

Alaska


	Three Months Ended March 31
	2015		2014

Income from Continuing Operations (millions of dollars)	$	145		598

Average Net Production
Crude oil (MBD)		163		175
Natural gas liquids (MBD)		14		16
Natural gas (MMCFD)		52		55

Total Production (MBOED)		186		200

Average Sales Prices
Crude oil (dollars per barrel)	$	50.74		106.39
Natural gas (dollars per thousand cubic feet)		4.29		5.22

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. As of March 31, 2015, Alaska contributed 19 percent of our worldwide liquids production and 1 percent of our worldwide natural gas production.

Alaska operations reported earnings of $145 million in the first quarter of 2015, a $453 million decrease compared with the same period in 2014. The decrease in earnings was primarily due to lower crude oil prices. Lower sales volumes also contributed to the earnings decrease, but were offset by lower production taxes, which also mainly resulted from lower crude oil prices and volumes.

Average production decreased 7 percent in the first quarter of 2015 compared with the same period in 2014, due to normal field decline and downtime, partially offset by improved well performance.

Lower 48


	Three Months Ended March 31
	2015			2014

Income (Loss) from Continuing Operations (millions of dollars)	$	(405	)		324

Average Net Production
Crude oil (MBD)		198			171
Natural gas liquids (MBD)		93			91
Natural gas (MMCFD)		1,505			1,468

Total Production (MBOED)		542			507

Average Sales Prices
Crude oil (dollars per barrel)	$	40.77			91.52
Natural gas liquids (dollars per barrel)		15.55			36.06
Natural gas (dollars per thousand cubic feet)		2.60			5.08

As of March 31, 2015, the Lower 48 contributed 31 percent of our worldwide liquids production and 38 percent of our worldwide natural gas production. The Lower 48 segment consists of operations located in the U.S. Lower 48 states and exploration activities in the Gulf of Mexico.

Lower 48 operations reported a loss of $405 million in the first quarter of 2015, a $729 million decrease compared with the same quarter of 2014, primarily due to lower crude oil, natural gas and natural gas liquids prices. In addition, higher DD&A, mainly from increased crude oil production; the absence of the earnings benefit from marketing third-party natural gas volumes realized in the first quarter of 2014; and increased dry hole expense contributed to the decrease in earnings. These decreases were partially offset by higher volumes and the absence of an $83 million after-tax loss recognized in the first quarter of 2014 upon the release of underutilized transportation and storage capacity at rates below our contractual rates.

Rising U.S. production and an increase in pipeline capacity to the Gulf Coast have put downward pressure on Gulf Coast crude oil prices. Prices for Permian Basin crude oil production have been impacted by production increases exceeding pipeline offtake additions. In the first quarter of 2015, our average realized crude oil price of $40.77 per barrel was 16 percent less than WTI of $48.56 per barrel. Current market dynamics indicate this crude differential may remain relatively wide in the near-term.

Total average production in the Lower 48 increased 7 percent in the first quarter of 2015, while average crude oil production increased 16 percent over the same period. The increase in the first quarter of 2015 was mainly attributable to new production, primarily from Eagle Ford and Bakken, and improved drilling and well performance, partially offset by normal field decline, increased ethane rejection and winter weather impacts.

Exploration Update

In April 2015, we began plug and abandon operations on the Harrier exploration well, located in Mississippi Canyon Block 118. As a result, we recorded an approximately $61 million after-tax charge to dry hole expense in the first quarter of 2015. The non-operated Vernaccia exploration well, located in Mississippi Canyon Block 35, is expected to spud in the third quarter of 2015.

Canada


	Three Months Ended March 31
	2015			2014

Income (Loss) from Continuing Operations (millions of dollars)	$	(158	)		356

Average Net Production
Crude oil (MBD)		14			13
Natural gas liquids (MBD)		25			25
Bitumen (MBD)
Consolidated operations		12			13
Equity affiliates		144			111

Total bitumen		156			124
Natural gas (MMCFD)		736			707

Total Production (MBOED)		318			280

Average Sales Prices
Crude oil (dollars per barrel)	$	37.12			80.32
Natural gas liquids (dollars per barrel)		18.28			56.13
Bitumen (dollars per barrel)
Consolidated operations		24.31			61.69
Equity affiliates		16.60			55.85
Total bitumen		17.22			56.47
Natural gas (dollars per thousand cubic feet)		2.21			5.81

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, 2015, Canada contributed 21 percent of our worldwide liquids production and 18 percent of our worldwide natural gas production.

Canada operations reported a loss of $158 million in the first quarter of 2015, a $514 million decrease compared with the same quarter of 2014. The decrease in earnings was primarily due to lower bitumen and natural gas prices. The decrease was partially offset by higher production volumes; lower operating expenses from favorable foreign currency impacts; and lower DD&A resulting from favorable foreign currency impacts, lower unit-of-production rates from reserve additions, and year-end 2014 price-related reserve revisions.

Total average production increased 14 percent in the first quarter of 2015, while bitumen production increased 26 percent in the same period. The increase in total production in the first quarter of 2015 was mainly attributable to lower royalty impacts, strong operational performance at FCCL, improved drilling and well performance and the continued ramp-up of production from Foster Creek Phase F. These increases were partly offset by normal field decline.

Europe


	Three Months Ended March 31
	2015		2014

Income from Continuing Operations (millions of dollars)		637		347

Average Net Production
Crude oil (MBD)		120		135
Natural gas liquids (MBD)		7		7
Natural gas (MMCFD)		494		472

Total Production (MBOED)		209		220

Average Sales Prices
Crude oil (dollars per barrel)	$	54.30		109.05
Natural gas liquids (dollars per barrel)		29.90		60.48
Natural gas (dollars per thousand cubic feet)		8.33		10.94

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 Greenland. As of March 31, 2015, our Europe operations contributed 14 percent of our worldwide liquids production and 12 percent of our worldwide natural gas production.

Europe operations reported earnings of $637 million in the first quarter of 2015, an increase of $290 million compared with the same period in 2014. The increase in earnings was primarily due to a $555 million net deferred tax benefit as a result of a change in the U.K. tax rate, effective at the beginning of 2015. Higher earnings were partially offset by lower crude oil and natural gas prices.

Average production decreased 5 percent in the first quarter of 2015, compared to the same period in 2014. The decrease was mostly due to normal field decline, partly offset by continued ramp-up of production from the Jasmine Field and the Britannia Long-Term Compression Project in the U.K., as well as lower unplanned downtime.

Asia Pacific and Middle East


	Three Months Ended March 31
	2015		2014

Income from Continuing Operations (millions of dollars)	$	409		756

Average Net Production
Crude oil (MBD)
Consolidated operations		108		86
Equity affiliates		15		14

Total crude oil		123		100

Natural gas liquids (MBD)
Consolidated operations		9		13
Equity affiliates		7		7

Total natural gas liquids		16		20

Natural gas (MMCFD)
Consolidated operations		711		726
Equity affiliates		561		469

Total natural gas		1,272		1,195

Total Production (MBOED)		351		319

Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	51.20		104.92
Equity affiliates		52.70		107.49
Total crude oil		51.38		105.32
Natural gas liquids (dollars per barrel)
Consolidated operations		40.90		80.07
Equity affiliates		38.80		79.91
Total natural gas liquids		39.99		80.01
Natural gas (dollars per thousand cubic feet)
Consolidated operations		7.23		10.32
Equity affiliates		7.48		10.43
Total natural gas		7.34		10.37

The Asia Pacific and Middle East segment has operations in China, Indonesia, Malaysia, Australia, Timor-Leste and Qatar, as well as exploration activities in Bangladesh, Brunei and Myanmar. As of March 31, 2015, Asia Pacific and Middle East contributed 15 percent of our worldwide liquids production and 31 percent of our worldwide natural gas production.

Asia Pacific and Middle East operations reported earnings of $409 million in the first quarter of 2015, a $347 million decrease compared with the same period in 2014. The decrease in first-quarter 2015 earnings was mainly due to lower prices across all commodities and higher DD&A from increased crude oil production. The decrease was partially offset by increased crude oil and natural gas volumes; lower production taxes, as a result of lower crude oil prices; and higher equity earnings from foreign exchange tax-related impacts.

Average production increased 10 percent in the first quarter of 2015 compared with the same period of 2014, mainly attributable to new production from Gumusut, in Malaysia, which came online in the fourth quarter of 2014; the ramp up of APLNG production due to additional gas processing facilities online; and improved well performance. The increases were partially offset by normal field decline.

Other International


	Three Months Ended March 31
	2015			2014

Income (Loss) from Continuing Operations (millions of dollars)	$	(93	)		(29	)

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

Total crude oil		4			5

Natural gas (MMCFD)		—			4

Total Production (MBOED)		4			6

Average Sales Prices
Crude oil (dollars per barrel)
Equity affiliates		36.09			67.82
Total crude oil		36.09			67.82
Natural gas (dollars per thousand cubic feet)		—			6.65

The Other International segment includes operations in Libya and Russia, as well as exploration activities in Colombia, Poland, Angola, Senegal and Azerbaijan. As of March 31, 2015, Other International contributed less than one percent of our worldwide liquids production.

Other International operations reported a loss of $93 million in the first quarter of 2015, compared with a loss of $29 million in the first quarter of 2014. The decrease in earnings was primarily due to higher exploration expenses related to the $81 million after-tax dry hole expense for the Omosi-1 well.

Average production decreased by 2 MBOED in the first quarter of 2015 compared with the same period in 2014, due to normal field decline. Libya production remains shut in, as the Es Sider crude oil export terminal closure has continued throughout the first quarter of 2015. The 2015 drilling program remains uncertain as a result of the ongoing civil unrest.

Exploration Update

In April 2015, we plugged and abandoned the Omosi-1 exploration well, located in Block 37 offshore Angola. As a result, we recorded an approximately $81 million after-tax charge to dry hole expense in the first quarter of 2015. Vali-1, the third wildcat in our planned four-well exploration program in the Kwanza Basin, was spud in April 2015.

Corporate and Other


	Millions of Dollars
	Three Months Ended March 31
	2015			2014

Income (Loss) from Continuing Operations
Net interest	$	(155	)		(163	)
Corporate general and administrative expenses		(21	)		(31	)
Technology		(16	)		(28	)
Other		(57	)		(13	)

	$	(249	)		(235	)

Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest decreased 5 percent in the first quarter of 2015 compared with the same period in 2014, primarily as a result of a tax benefit associated with the election of the fair market value method of apportioning interest expense in the United States, partly offset by lower capitalized interest on projects.

Technology includes our investment in new technologies or businesses, as well as licensing revenues. 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 were $16 million in the first quarter of 2015, compared with losses of $28 million in the same period of 2014. The decrease in losses primarily resulted from lower research and development expenses and higher licensing revenues.

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. “Other” expenses increased $44 million in the first quarter of 2015 compared with the same period in 2014, primarily due to higher foreign currency transaction losses and restructuring charges incurred in the first quarter of 2015.

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators


	Millions of Dollars
	March 31 2015			December 31 2014

Short-term debt	$	193			182
Total debt		22,511			22,565
Total equity		49,008			52,273
Percent of total debt to capital*		31	%		30
Percent of floating-rate debt to total debt		5	%		5

*Capital includes total debt and total equity.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from continuing operating activities is the primary source of funding. During the first three months of 2015, the primary uses of our available cash were $3,332 million to support our ongoing capital expenditures and investments program, $910 million to pay dividends and $57 million to repay debt. During the first three months of 2015, cash and cash equivalents decreased by $2,398 million, to $2,664 million.

In addition to cash flows from operating activities and proceeds from asset sales, we rely on our commercial paper and credit facility programs and our shelf registration statement to support our short- and long-term liquidity requirements. We believe current cash balances and cash generated by operations, together with access to external sources of funds as described below in the “Significant Sources of Capital” section, will be sufficient to meet our funding requirements in the near- and long-term, including our capital spending program, dividend payments, and required debt payments.

Significant Sources of Capital

Operating Activities

Cash provided by continuing operating activities was $1,870 million for the first three months of 2015, compared with $6,278 million for the corresponding period of 2014, a 70 percent decrease. The decrease was primarily due to lower prices across all commodities and the absence of the $1.3 billion distribution from FCCL in the first quarter of 2014. The distribution from FCCL resulted from our $2.8 billion prepayment of the remaining joint venture acquisition obligation in 2013, which substantially increased the financial flexibility of our 50 percent owned FCCL Partnership. We do not expect this individually significant distribution to recur in the future under current economic conditions.

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 the volatile crude oil and natural gas price environment, which may impact investment decisions; the effects of price changes on production sharing and variable-royalty contracts; acquisition and disposition of fields; field production decline rates; new technologies; operating efficiencies; timing of startups and major turnarounds; political instability; weather-related disruptions; and 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.

Commercial Paper and Credit Facilities

At March 31, 2015, we had a revolving credit facility totaling $7.0 billion expiring in June 2019. Our revolving credit facility may be used for direct bank borrowings, for the issuance of letters of credit totaling up to $500 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 credit 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 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 as administered by ICE Benchmark Administration 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 $6.1 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $900 million commercial paper program, which is used to fund commitments relating to Qatar Liquefied Gas Company Limited (3). At both March 31, 2015 and December 31, 2014, 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, $806 million of commercial paper was outstanding at March 31, 2015, compared with $860 million at December 31, 2014. Since we had $806 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.2 billion in borrowing capacity under our revolving credit facility at March 31, 2015.

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, 2015 and December 31, 2014, we had direct bank letters of credit of $472 million and $802 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 8—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, 2015, was $22.5 billion, a decrease of $54 million from the balance at December 31, 2014. For more information, see Note 6—Debt, in the Notes to Consolidated Financial Statements.

In February 2015, we announced a dividend of 73 cents per share. The dividend was paid March 2, 2015, to stockholders of record at the close of business on February 17, 2015.

Capital Spending


	Millions of Dollars
	Three Months Ended March 31
	2015		2014

Alaska	$	402		415
Lower 48		1,372		1,312
Canada		455		622
Europe		500		596
Asia Pacific and Middle East		488		848
Other International		83		67
Corporate and Other		32		35

Capital expenditures and investments from continuing operations	$	3,332		3,895

Discontinued operations in Nigeria:	$	—		22

During the first three months of 2015, 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.

•

Major project expenditures associated with the APLNG joint venture in Australia.

•

Oil sands development, notably at Surmont 2, and ongoing liquids-rich plays in Canada.

•

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

•

In Europe, development activities in the Greater Ekofisk, Aasta Hansteen, Clair Ridge, Jasmine and Greater Britannia areas, and exploration and appraisal activities in the Jasmine and Greater Clair areas.

•

Exploration and appraisal drilling in deepwater Gulf of Mexico.

•

Continued development in Malaysia, Indonesia, China and ongoing exploration and appraisal activity in Indonesia and offshore Australia.

•

Exploration activities in Angola.

Contingencies

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. For information on other contingencies, see Note 9—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Legal 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.

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 59–61 of our 2014 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 March 31, 2015, there were 13 sites around the United States in which we were identified as a potentially responsible party under CERCLA and comparable state laws.

At March 31, 2015, our balance sheet included a total environmental accrual of $322 million, compared with $344 million at December 31, 2014, for remediation activities in the United States 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 61–62 of our 2014 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. All statements other than statements of historical fact included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans, and objectives of management for future operations, are forward-looking statements. 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, but not limited to, the following:

•

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

•

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.

•

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

•

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

•

Legislative and regulatory initiatives further regulating hydraulic fracturing, methane emissions, flaring or water disposal.

•

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

•

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.

•

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

•

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.

•

International monetary conditions and exchange controls.

•

Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations, use of competing energy sources or the development of alternative energy sources.

•

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

•

Liability resulting from litigation.

•

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

•

Volatility in the commodity futures markets.

•

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

•

Competition in the oil and gas exploration and production industry.

•

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

•

Delays in, or our inability to, execute asset dispositions.

•

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

•

The operation and financing of our joint ventures.

•

The factors generally described in Item 1A—Risk Factors in our 2014 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, 2015, does not differ materially from that discussed under Item 7A in our 2014 Annual Report on Form 10-K.

Item 4.

CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures designed to ensure information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. As of March 31, 2015, 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 our disclosure controls and procedures were operating effectively as of March 31, 2015.

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 2015 and any material developments with respect to matters previously reported in ConocoPhillips’ 2014 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 or have subsequently become 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

In October 2011 ConocoPhillips was notified by the Attorney General of the State of California that it was investigating possible violations of regulations relating to the operation of underground storage tanks at gas stations in California. On January 3, 2013, the California Attorney General filed a lawsuit notice that alleges such violations. Phillips 66 has reached an agreement to resolve this lawsuit with a settlement payment of $11.5 million to the State of California.

Item 1A.

RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A of our 2014 Annual Report on Form 10-K.

Item 6.

EXHIBITS



10.1*		Form of Retention Award Terms and Conditions, as part of the Restricted Stock Unit Award, granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips.

12*		Computation of Ratio of Earnings to Fixed Charges.

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

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

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

101.INS*		XBRL Instance Document.

101.SCH*		XBRL Schema Document.

101.CAL*		XBRL Calculation Linkbase Document.

101.LAB*		XBRL Labels Linkbase Document.

101.PRE*		XBRL Presentation Linkbase Document.

101.DEF*		XBRL Definition Linkbase Document.

* Filed herewith.

SIGNATURE

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

CONOCOPHILLIPS

/s/ Glenda M. Schwarz

Glenda M. Schwarz

Vice President and Controller

(Chief Accounting and Duly Authorized Officer)

May 5, 2015