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 June 30, 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 1,233,458,569 shares of common stock, $.01 par value, outstanding at June 30, 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		23

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk		48

Item 4. Controls and Procedures		48

Part II – Other Information

Item 1A. Risk Factors		48

Item 6. Exhibits		49

Signature		50

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS


Consolidated Income Statement			ConocoPhillips


	Millions of Dollars
	Three Months						Six Months
	Ended June 30						Ended June 30
	2015			2014			2015			2014

Revenues and Other Income
Sales and other operating revenues	$	8,293			13,821			16,009			29,236
Equity in earnings of affiliates		258			672			463			1,244
Gain on dispositions		52			7			104			16
Other income		57			201			86			253

Total Revenues and Other Income		8,660			14,701			16,662			30,749


Costs and Expenses
Purchased commodities		3,230			5,495			6,467			12,622
Production and operating expenses		1,798			2,030			3,600			3,925
Selling, general and administrative expenses		218			218			377			400
Exploration expenses		549			517			1,031			813
Depreciation, depletion and amortization		2,329			2,070			4,460			3,962
Impairments		78			17			94			18
Taxes other than income taxes		225			612			449			1,263
Accretion on discounted liabilities		122			120			243			237
Interest and debt expense		210			155			412			326
Foreign currency transaction (gains) losses		(8	)		7			(24	)		25

Total Costs and Expenses		8,751			11,241			17,109			23,591

Income (loss) from continuing operations before income taxes		(91	)		3,460			(447	)		7,158
Provision (benefit) for income taxes		73			1,395			(569	)		2,976

Income (Loss) From Continuing Operations		(164	)		2,065			122			4,182
Income from discontinued operations*		—			33			—			53

Net income (loss)		(164	)		2,098			122			4,235
Less: net income attributable to noncontrolling interests		(15	)		(17	)		(29	)		(31	)

Net Income (Loss) Attributable to ConocoPhillips	$	(179	)		2,081			93			4,204

Amounts Attributable to ConocoPhillips Common Shareholders:
Income (loss) from continuing operations	$	(179	)		2,048			93			4,151
Income from discontinued operations		—			33			—			53

Net income (loss)	$	(179	)		2,081			93			4,204


Net Income (Loss) Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic
Continuing operations	$	(0.15	)		1.65			0.07			3.36
Discontinued operations		—			0.03			—			0.04

Net Income (Loss) Attributable to ConocoPhillips Per Share of Common Stock	$	(0.15	)		1.68			0.07			3.40

Diluted
Continuing operations	$	(0.15	)		1.64			0.07			3.34
Discontinued operations		—			0.03			—			0.04

Net Income (Loss) Attributable to ConocoPhillips Per Share of Common Stock	$	(0.15	)		1.67			0.07			3.38


Dividends Paid Per Share of Common Stock (dollars)	$	0.73			0.69			1.46			1.38


Average Common Shares Outstanding (in thousands)
Basic		1,241,026			1,236,057			1,240,909			1,235,515
Diluted		1,241,026			1,245,155			1,246,130			1,245,211

*Net of provision (benefit) for income taxes on discontinued operations of:	$	—			(10	)		—			22

See Notes to Consolidated Financial Statements.


Consolidated Statement of Comprehensive Income		ConocoPhillips


	Millions of Dollars
	Three Months Ended						Six Months Ended
	June 30						June 30
	2015			2014			2015			2014

Net Income (Loss)	$	(164	)		2,098			122			4,235

Other comprehensive income (loss)
Defined benefit plans
Prior service cost arising during the period		140			—			140			—
Reclassification adjustment for amortization of prior service credit included in net income		(3	)		(1	)		(4	)		(3	)
Net actuarial gain arising during the period		15			—			15			—
Reclassification adjustment for amortization of net actuarial losses included in net income		102			33			152			66
Nonsponsored plans*		—			(1	)		—			5
Income taxes on defined benefit plans		(93	)		(12	)		(110	)		(23	)

Defined benefit plans, net of tax		161			19			193			45

Foreign currency translation adjustments		796			668			(1,949	)		446
Income taxes on foreign currency translation adjustments		(9	)		9			17			5

Foreign currency translation adjustments, net of tax		787			677			(1,932	)		451

Other Comprehensive Income (Loss), Net of Tax		948			696			(1,739	)		496

Comprehensive Income (Loss)		784			2,794			(1,617	)		4,731
Less: comprehensive income attributable to noncontrolling interests		(15	)		(17	)		(29	)		(31	)

Comprehensive Income (Loss) Attributable to ConocoPhillips	$	769			2,777			(1,646	)		4,700

*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
	June 30			December 31
	2015			2014

Assets
Cash and cash equivalents	$	3,813			5,062
Accounts and notes receivable (net of allowance of $7 million in 2015 and $5 million in 2014)		5,044			6,675
Accounts and notes receivable—related parties		135			132
Inventories		1,277			1,331
Prepaid expenses and other current assets		1,675			1,868

Total Current Assets		11,944			15,068
Investments and long-term receivables		23,902			24,335
Loans and advances—related parties		750			804
Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $73,854 million in 2015 and $70,786 million in 2014)		74,387			75,444
Other assets		1,020			888

Total Assets	$	112,003			116,539


Liabilities
Accounts payable	$	5,833			7,982
Accounts payable—related parties		36			44
Short-term debt		138			182
Accrued income and other taxes		880			1,051
Employee benefit obligations		620			878
Other accruals		1,227			1,400

Total Current Liabilities		8,734			11,537
Long-term debt		24,787			22,383
Asset retirement obligations and accrued environmental costs		10,567			10,647
Deferred income taxes		14,373			15,070
Employee benefit obligations		2,849			2,964
Other liabilities and deferred credits		1,724			1,665

Total Liabilities		63,034			64,266


Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2015—1,775,689,242 shares; 2014—1,773,583,368 shares)
Par value		18			18
Capital in excess of par		46,244			46,071
Treasury stock (at cost: 2015—542,230,673 shares; 2014—542,230,673 shares)		(36,780	)		(36,780	)
Accumulated other comprehensive loss		(3,641	)		(1,902	)
Retained earnings		42,779			44,504

Total Common Stockholders’ Equity		48,620			51,911
Noncontrolling interests		349			362

Total Equity		48,969			52,273

Total Liabilities and Equity	$	112,003			116,539

See Notes to Consolidated Financial Statements.


Consolidated Statement of Cash Flows			ConocoPhillips


	Millions of Dollars
	Six Months Ended June 30
	2015			2014*

Cash Flows From Operating Activities
Net income	$	122			4,235
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		4,460			3,962
Impairments		94			18
Dry hole costs and leasehold impairments		713			403
Accretion on discounted liabilities		243			237
Deferred taxes		(602	)		633
Undistributed equity earnings		(41	)		681
Gain on dispositions		(104	)		(16	)
Income from discontinued operations		—			(53	)
Other		(454	)		(192	)
Working capital adjustments
Decrease in accounts and notes receivable		1,419			80
Decrease (increase) in inventories		42			(103	)
Decrease (increase) in prepaid expenses and other current assets		153			(238	)
Decrease in accounts payable		(1,358	)		(13	)
Increase (decrease) in taxes and other accruals		(645	)		123

Net cash provided by continuing operating activities		4,042			9,757
Net cash provided by discontinued operations		—			130

Net Cash Provided by Operating Activities		4,042			9,887


Cash Flows From Investing Activities
Capital expenditures and investments		(5,739	)		(8,141	)
Working capital changes associated with investing activities		(678	)		84
Proceeds from asset dispositions		294			63
Net purchases of short-term investments		—			(8	)
Collection of advances/loans—related parties		52			77
Other		291			96

Net cash used in continuing investing activities		(5,780	)		(7,829	)
Net cash used in discontinued operations		—			(63	)

Net Cash Used in Investing Activities		(5,780	)		(7,892	)


Cash Flows From Financing Activities
Issuance of debt		2,498			—
Repayment of debt		(62	)		(450	)
Issuance of company common stock		(46	)		46
Dividends paid		(1,819	)		(1,711	)
Other		(35	)		(28	)

Net Cash Provided by (Used in) Financing Activities		536			(2,143	)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		(47	)		44


Net Change in Cash and Cash Equivalents		(1,249	)		(104	)
Cash and cash equivalents at beginning of period		5,062			6,246

Cash and Cash Equivalents at End of Period	$	3,813			6,142

*Certain amounts have been reclassified to conform to current-period presentation. See Note 14–Cash Flow Information, in the Notes to the Consolidated Financial Statements.

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.

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 June 30, 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 9—Guarantees, for additional information.

Note 3—Inventories

Inventories consisted of the following:


	Millions of Dollars
	June 30 2015		December 31 2014

Crude oil and natural gas	$	474		538
Materials, supplies and other		803		793

	$	1,277		1,331

Inventories valued on the last-in, first-out (LIFO) basis totaled $351 million and $440 million at June 30, 2015 and December 31, 2014, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was approximately $44 million and $6 million at June 30, 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 June 30, 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 9—Guarantees, for additional information.

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. See Note 2—Variable Interest Entities (VIEs), for additional information.

At June 30, 2015, the book value of our equity method investment in APLNG was $12,105 million, net of a $530 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 June 30, 2015, the book value of our equity method investment in FCCL was $8,979 million, net of a $1,004 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 June 30, 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 and Unproved Property Impairments

The capitalized cost of suspended wells at June 30, 2015, was $1,423 million, an increase of $124 million from $1,299 million at year-end 2014. No suspended wells were charged to dry hole expense during the first six months of 2015 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2014.

In the second quarter of 2015, we decided not to pursue further evaluation of our Lebork, Damnica and Karwia concessions in Poland and Block 37 lease in Angola. Accordingly, we recorded pre-tax impairments of $93 million and $116 million, respectively, for the associated carrying value of capitalized undeveloped leasehold cost. The impairments are included in the “Exploration expenses” line on our consolidated income statement.

Note 6—Impairments

During the three- and six-month periods ended June 30, 2015 and 2014, we recognized before-tax impairment charges within the following segments:


	Millions of Dollars
	Three Months Ended June 30				Six Months Ended June 30
	2015		2014		2015		2014

Alaska	$	7		—		7		—
Lower 48		—		17		—		17
Europe		71		—		87		—
Corporate and Other		—		—		—		1

	$	78		17		94		18

The three- and six-month periods of 2015 included impairments in our Europe segment of $71 million, primarily as a result of lower natural gas prices.

In addition, during the three-month period ended June 30, 2015, we recognized $209 million of expense in our Other International segment related to impairment of individually significant unproved properties. These unproved property impairments, included in the “Exploration expenses” line on our consolidated income statement, are further discussed in Note 5—Suspended Wells and Unproved Property Impairments.

Note 7—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 June 30, 2015 and December 31, 2014, we had no direct outstanding borrowings under the revolving credit facility, with no letters of credit as of June 30, 2015 or December 31, 2014. Under the ConocoPhillips Qatar Funding Ltd. commercial paper program, $806 million of commercial paper was outstanding at June 30, 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 June 30, 2015.

At June 30, 2015, we classified $750 million of short-term debt as long-term debt, based on our ability and intent to refinance the obligation on a long-term basis under our revolving credit facility.

In May 2015, we issued notes consisting of:

•

The $750 million of 1.50% Notes due 2018.

•

The $250 million of Floating Rate Notes due 2018 bearing interest at three-month LIBOR, plus 0.33%.

•

The $500 million of 2.20% Notes due 2020.

•

The $500 million of Floating Rate Notes due 2022 bearing interest at three-month LIBOR, plus 0.90%.

•

The $500 million of 3.35% Notes due 2025.

The net proceeds were used for general corporate purposes.

Note 8—Noncontrolling Interests

Activity attributable to common stockholders’ equity and noncontrolling interests for the first six 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		93			29			122			4,204			31			4,235
Dividends		(1,819	)		—			(1,819	)		(1,711	)		—			(1,711	)
Distributions to noncontrolling interests		—			(43	)		(43	)		—			(62	)		(62	)
Other changes, net*		(1,565	)		1			(1,564	)		732			—			732

Balance at June 30	$	48,620			349			48,969			55,315			371			55,686

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

Note 9—Guarantees

At June 30, 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 June 30, 2015, we had 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 June 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 $100 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 June 30, 2015, is $3.1 billion based upon our pro-rata share of the facility used at that date. At June 30, 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 30 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $170 million and would become payable if APLNG does not perform.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $370 million, which consist primarily of guarantees of the residual value of leased corporate aircraft, a guarantee for our portion of a joint venture’s debt obligations, a guarantee to fund the short-term cash liquidity deficit of a joint venture, and a guarantee of minimum charter revenue for an LNG vessel. These guarantees have remaining terms of up to nine 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 June 30, 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 June 30, 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 10—Contingencies and Commitments.

On April 30, 2012, the separation of our Downstream businesses was completed, creating two independent energy companies: ConocoPhillips and Phillips 66. In connection with the separation, we entered into an Indemnification and Release Agreement, which provides for cross-indemnities between Phillips 66 and us and established procedures for handling claims subject to indemnification and related matters. We evaluated the impact of the indemnifications given and the Phillips 66 indemnifications received as of the separation date and concluded those fair values were immaterial.

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 June 30, 2015, the carrying value of this guarantee is approximately $100 million and the remaining term is nine 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 10—Contingencies and Commitments

A number of lawsuits involving a variety of claims arising in the ordinary course of business have been made against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. With respect to income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.

Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.

Environmental

We are subject to international, federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.

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

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state and international sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. At June 30, 2015, our balance sheet included a total environmental accrual of $306 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.

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.

Other Contingencies

We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at June 30, 2015, we had performance obligations secured by letters of credit of $400 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 June 30, 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 11—Derivative and Financial Instruments

Derivative Instruments

We use futures, forwards, swaps and options in various markets to meet our customer needs and capture market opportunities. Our commodity business primarily consists of natural gas, crude oil, bitumen, LNG and natural gas liquids.

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

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


	Millions of Dollars
	June 30 2015		December 31 2014

Assets
Prepaid expenses and other current assets	$	2,386		4,500
Other assets		112		157
Liabilities
Other accruals		2,398		4,426
Other liabilities and deferred credits		101		144

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


	Millions of Dollars
	Three Months Ended June 30						Six Months Ended June 30
	2015			2014			2015			2014

Sales and other operating revenues	$	44			184			28			421
Other income		2			1			1			2
Purchased commodities		(47	)		(163	)		(3	)		(384	)

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


	Open Position Long/(Short)
	June 30 2015			December 31 2014

Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price		(23	)		(11	)
Basis		(13	)		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
	June 30 2015		December 31 2014

Assets
Prepaid expenses and other current assets	$	25		1
Liabilities
Other accruals		2		1

The gains 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 June 30						Six Months Ended June 30
	2015			2014			2015			2014

Foreign currency transaction gains	$	(37	)		(7	)		(13	)		(7	)

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


	In Millions Notional Currency
	June 30 2015		December 31 2014

Sell U.S. dollar, buy other currencies*	USD	55		7
Buy U.S. dollar, sell other currencies**	USD	20		44
Sell British pound, buy euro	GBP	6		—
Buy British pound, sell other currencies***	GBP	309		20

*Primarily Canadian dollar and British pound.

**Primarily Canadian dollar and Norwegian krone.

***Primarily Canadian dollar 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
	June 30 2015		December 31 2014

Cash	$	677		946
Money Market Funds		—		50
Time deposits
Remaining maturities from 1 to 90 days		3,136		3,726
Commercial paper
Remaining maturities from 1 to 90 days		—		340

	$	3,813		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.

The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on June 30, 2015 and December 31, 2014, was $100 million and $150 million, respectively. For these instruments, no collateral was posted as of June 30, 2015 or December 31, 2014. If our credit rating had been lowered one level from its “A” rating (per Standard and Poor’s) on June 30, 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 $100 million of additional collateral, either with cash or letters of credit.

Note 12—Fair Value Measurement

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

•

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

•

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

•

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

The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities that are initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. Transfers occur at the end of the reporting period. There were no material transfers in or out of Level 1 during 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
	June 30, 2015								December 31, 2014
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total

Assets
Deferred compensation investments	$	27		—		—		27		297		—		—		297
Commodity derivatives		2,236		192		70		2,498		4,221		361		75		4,657

Total assets	$	2,263		192		70		2,525		4,518		361		75		4,954


Liabilities
Commodity derivatives	$	2,263		224		12		2,499		4,200		354		16		4,570

Total liabilities	$	2,263		224		12		2,499		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

June 30, 2015
Assets	$	2,498		2,334		164		—		12		152
Liabilities		2,499		2,334		165		28		9		128


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

At June 30, 2015 and December 31, 2014, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.

Non-Recurring Fair Value Measurement

The following table summarizes the fair value hierarchy by major category for assets accounted for at fair value on a non-recurring basis:

Millions of Dollars

Fair Value
Measurements Using

Fair Value

Level 3
Inputs

Before-Tax
Loss

June 30, 2015

Net PP&E (held for use)

Net properties, plants and equipment (PP&E) held for use is comprised of various producing properties impaired to their individual fair values less costs to sell. The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges and pricing service companies, costs, and a discount rate believed to be consistent with those used by principal market participants.

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

June 30
2015

December 31
2014

June 30
2015

December 31
2014

Financial assets

Deferred compensation investments

297

Commodity derivatives

164

297

164

297

Total loans and advances—related parties

861

913

861

913

Financial liabilities

Total debt, excluding capital leases

24,068

21,707

26,746

25,191

Commodity derivatives

137

214

137

214

Deferred compensation investments

Note 13—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)		193			(1,932	)		(1,739	)

June 30, 2015	$	(1,068	)		(2,573	)		(3,641	)

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

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

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


	Millions of Dollars
	Three Months Ended June 30				Six Months Ended June 30
	2015		2014		2015		2014

Defined benefit plans	$	64		20		96		40

Above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of:	$	35		12		52		23
See Note 15—Employee Benefit Plans, for additional information.

Note 14—Cash Flow Information


	Millions of Dollars
	Six Months Ended June 30
	2015		2014

Cash Payments
Interest	$	399		311
Income taxes*		172		2,321


Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased	$	—		(492	)
Short-term investments sold		—		484

	$	—		(8	)

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

In relation to certain working capital changes associated with investing activities, we reclassified $84 million of the “Decrease in accounts payable” line within “Cash Flows From Operating Activities” to the “Working capital changes associated with investing activities” line within “Cash Flows From Investing Activities” for the six months ended June 30, 2014. There was no impact to “Cash and Cash Equivalents at End of Period.”

Note 15—Employee Benefit Plans

Pension and Postretirement Plans


	Millions of Dollars
	Pension Benefits												Other Benefits
	2015						2014						2015			2014

	U.S.			Int’l.			U.S.			Int’l.

Components of Net Periodic Benefit Cost
Three Months Ended June 30
Service cost	$	36			31			31			28			—			—
Interest cost		39			34			41			42			7			7
Expected return on plan assets		(53	)		(43	)		(53	)		(46	)		—			—
Amortization of prior service cost (credit)		1			(2	)		2			(2	)		(2	)		(1	)
Recognized net actuarial loss		29			21			19			14			—			—
Settlements		52			—			—			—			—			—

Net periodic benefit cost	$	104			41			40			36			5			6


Six Months Ended June 30
Service cost	$	72			63			62			56			1			1
Interest cost		79			68			82			84			14			14
Expected return on plan assets		(107	)		(87	)		(106	)		(92	)		—			—
Amortization of prior service cost (credit)		3			(4	)		3			(4	)		(3	)		(2	)
Recognized net actuarial loss (gain)		57			42			38			29			1			(1	)
Settlements		52			—			—			—			—			—

Net periodic benefit cost	$	156			82			79			73			13			12

During the first six months of 2015, we contributed $34 million to our domestic benefit plans and $71 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.

During the three-month period ended June 30, 2015, we determined lump-sum benefit payments will exceed the sum of service and interest costs for the fiscal year for the U.S. qualified pension plan and certain U.S. non-qualified supplemental retirement plans. As a result, we recognized a proportionate share of prior actuarial losses from other comprehensive income as pension settlement expense of $52 million. In conjunction with the recognition of pension settlement expense, the assets and pension benefit obligation of the U.S. qualified pension plan were remeasured and the impact on the net pension liability was immaterial.

Due to an ongoing restructuring program in the Europe segment, we recognized additional expense of $10 million associated with employee special termination benefits during the three-month period ended June 30, 2015, and $60 million during the six-month period ended June 30, 2015, of which approximately 62 percent is expected to be recovered from partners.

During the three-month period ended June 30, 2015, there was an amendment to the other postretirement benefit plan. The benefit obligation decreased by $140 million for changes in the substantive plan made to retiree medical benefits. The $140 million decrease consists of a decrease of $91 million related to cost sharing changes for retirees for medical benefits, and a decrease of $49 million associated with excluding employees and retirees of Phillips 66 who were not enrolled in a ConocoPhillips retiree medical plan as of July 1, 2015. In conjunction with the recognition of the changes in the amendment, the benefit obligation was remeasured. At the remeasurement date, the benefit obligation decreased an additional $14 million related to changes in the discount rate and demographics of plan participants. The other postretirement benefits obligation decrease of $154 million resulted in a corresponding increase to other comprehensive income. The

measurement of the accumulated postretirement benefit obligation for the post-65 retiree medical plan assumes a health care cost trend rate of 2 percent in 2015 that increases to 5 percent in 2018.

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 occurred during 2015. The following table summarizes our severance accrual activity for the six-month period ended June 30, 2015:


	Millions of Dollars
Balance at December 31, 2014	$	61
Accruals		88
Accrual reversals		(4	)
Benefit payments		(84	)
Foreign currency translation adjustments		(2	)

Balance at June 30, 2015	$	59

Of the remaining balance at June 30, 2015, $21 million is classified as short-term.

Note 16—Related Party Transactions

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


	Millions of Dollars
	Three Months Ended June 30						Six Months Ended June 30
	2015			2014			2015			2014

Operating revenues and other income	$	27			36			52			57
Purchases		25			52			47			100
Operating expenses and selling, general and administrative expenses*		17			14			35			32
Net interest (income) expense**		(2	)		(12	)		(4	)		(24	)

* 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 17—Segment Disclosures and Related Information

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

After agreeing to sell our Nigeria business in 2012, we completed the sale 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 June 30						Six Months Ended June 30
	2015			2014			2015			2014

Sales and Other Operating Revenues
Alaska	$	1,338			2,407			2,388			4,593

Lower 48		3,176			5,530			6,315			12,114
Intersegment eliminations		(13	)		(22	)		(35	)		(60	)

Lower 48		3,163			5,508			6,280			12,054

Canada		653			1,168			1,356			3,027
Intersegment eliminations		(79	)		(145	)		(189	)		(490	)

Canada		574			1,023			1,167			2,537

Europe		1,775			2,745			3,329			5,954
Intersegment eliminations		(1	)		(44	)		(1	)		(44	)

Europe		1,774			2,701			3,328			5,910

Asia Pacific and Middle East		1,286			2,151			2,674			4,100
Other International		—			3			(5	)		5
Corporate and Other		158			28			177			37

Consolidated sales and other operating revenues	$	8,293			13,821			16,009			29,236


Net Income (loss) Attributable to ConocoPhillips
Alaska	$	195			627			340			1,225
Lower 48		(293	)		265			(698	)		589
Canada		(166	)		182			(324	)		538
Europe		37			259			674			606
Asia Pacific and Middle East		328			845			723			1,587
Other International		(148	)		121			(241	)		92
Corporate and Other		(132	)		(251	)		(381	)		(486	)
Discontinued operations		—			33			—			53

Consolidated net income (loss) attributable to ConocoPhillips	$	(179	)		2,081			93			4,204


	Millions of Dollars
	June 30 2015		December 31 2014

Total Assets
Alaska	$	13,193		12,655
Lower 48		29,545		30,185
Canada		20,623		21,764
Europe		15,420		16,125
Asia Pacific and Middle East		25,136		25,976
Other International		1,645		1,961
Corporate and Other		6,441		7,815
Discontinued operations		—		58

Consolidated total assets	$	112,003		116,539

Note 18—Income Taxes

Our effective tax rates from continuing operations for the second quarter and first six months of 2015 were negative 80 percent and positive 127 percent, respectively, compared with positive 40 percent and positive 42 percent for the same periods of 2014. The decrease in the effective tax rate for the second quarter was

primarily due to our overall pre-tax loss position, the effect of the 2015 Canadian tax law change generating a tax expense, discussed below, and pre-tax income in high tax jurisdictions, partially offset by pre-tax losses in low tax jurisdictions. The increase in the effective tax rate for the first six months of 2015 was primarily due to our overall pre-tax loss position; the effect of the first quarter 2015 U.K. tax law change generating a tax benefit, discussed below; and pre-tax losses in low tax jurisdictions, partially offset by the second quarter 2015 Canadian tax law change and pre-tax income in high tax jurisdictions.

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.

In Canada, legislation was enacted on June 29, 2015, to increase the overall Canadian corporation tax rate from 25 percent to 27 percent effective July 1, 2015. As a result, a $129 million net tax expense for revaluing the Canadian deferred tax liability is reflected in the “Provision (benefit) for income taxes” line on our consolidated income statement.

Note 19—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 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 do not expect the adoption of this ASU to have a material impact on our consolidated financial statements and disclosures.

Note 20—Subsequent Events

In July 2015, we announced our plan to reduce future deepwater exploration spending. The decision will most significantly impact our operated Gulf of Mexico program, where we have provided a notice of termination of the contract for a Gulf of Mexico deepwater drillship. The drillship was scheduled for delivery in late 2015 to begin drilling our operated deepwater well inventory on a three-year term. Under the terms of the contract, we are subject to a termination fee that represents up to two years of contract day rates. The termination fee is reduced for cost savings when the rig is idle and without a contract, as well as if the rig is re-contracted to another party. As a result of this cancellation, we expect to record pre-tax charges in our third quarter 2015 earnings of up to $400 million for the rig termination fee and approximately $60 million for the write-off of certain capitalized rig-related costs.

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, reflected in the second quarter 2015 Condensed Consolidating Financial Information for ConocoPhillips and ConocoPhillips Company, had no impact on our consolidated financial statements.


	Millions of Dollars
	Three Months Ended June 30, 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	$	—			3,102			—			5,191			—			8,293
Equity in earnings of affiliates		(120	)		215			—			138			25			258
Gain on dispositions		—			2			—			50			—			52
Other income		—			10			—			47			—			57
Intercompany revenues		18			82			63			952			(1,115	)		—

Total Revenues and Other Income		(102	)		3,411			63			6,378			(1,090	)		8,660

Costs and Expenses
Purchased commodities		—			2,568			—			1,610			(948	)		3,230
Production and operating expenses		—			395			—			1,405			(2	)		1,798
Selling, general and administrative expenses		3			162			—			53			—			218
Exploration expenses		—			143			—			406			—			549
Depreciation, depletion and amortization		—			301			—			2,028			—			2,329
Impairments		—			—			—			78			—			78
Taxes other than income taxes		—			50			—			175			—			225
Accretion on discounted liabilities		—			15			—			107			—			122
Interest and debt expense		121			111			57			86			(165	)		210
Foreign currency transaction (gains) losses		(16	)		1			146			(139	)		—			(8	)

Total Costs and Expenses		108			3,746			203			5,809			(1,115	)		8,751

Income (loss) from continuing operations before income taxes		(210	)		(335	)		(140	)		569			25			(91	)
Provision (benefit) for income taxes		(31	)		(215	)		(20	)		339			—			73

Net income (loss)		(179	)		(120	)		(120	)		230			25			(164	)
Less: net income attributable to noncontrolling interests		—			—			—			(15	)		—			(15	)

Net Income (Loss) Attributable to ConocoPhillips	$	(179	)		(120	)		(120	)		215			25			(179	)

Comprehensive Income (Loss) Attributable to ConocoPhillips	$	769			828			(33	)		988			(1,783	)		769


Income Statement	Three Months Ended June 30, 2014
Revenues and Other Income
Sales and other operating revenues	$	—			5,105			—			8,716			—			13,821
Equity in earnings of affiliates		2,119			2,514			—			539			(4,500	)		672
Gain on dispositions		—			2			—			5			—			7
Other income		—			27			—			174			—			201
Intercompany revenues		19			111			71			1,598			(1,799	)		—

Total Revenues and Other Income		2,138			7,759			71			11,032			(6,299	)		14,701

Costs and Expenses
Purchased commodities		—			4,431			—			2,631			(1,567	)		5,495
Production and operating expenses		—			481			—			1,596			(47	)		2,030
Selling, general and administrative expenses		3			156			—			59			—			218
Exploration expenses		—			238			—			279			—			517
Depreciation, depletion and amortization		—			261			—			1,809			—			2,070
Impairments		—			17			—			—			—			17
Taxes other than income taxes		—			71			—			541			—			612
Accretion on discounted liabilities		—			15			—			105			—			120
Interest and debt expense		148			62			58			72			(185	)		155
Foreign currency transaction (gains) losses		(22	)		2			151			(124	)		—			7

Total Costs and Expenses		129			5,734			209			6,968			(1,799	)		11,241

Income (loss) from continuing operations before income taxes		2,009			2,025			(138	)		4,064			(4,500	)		3,460
Provision (benefit) for income taxes		(39	)		(94	)		(4	)		1,532			—			1,395

Income (Loss) From Continuing Operations		2,048			2,119			(134	)		2,532			(4,500	)		2,065
Income from discontinued operations		33			33			—			33			(66	)		33

Net income (loss)		2,081			2,152			(134	)		2,565			(4,566	)		2,098
Less: net income attributable to noncontrolling interests		—			—			—			(17	)		—			(17	)

Net Income (Loss) Attributable to ConocoPhillips	$	2,081			2,152			(134	)		2,548			(4,566	)		2,081

Comprehensive Income (Loss) Attributable to ConocoPhillips	$	2,777			2,848			(14	)		3,220			(6,054	)		2,777


	Millions of Dollars
	Six Months Ended June 30, 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	$	—			6,035			—			9,974			—			16,009
Equity in earnings of affiliates		261			1,028			—			716			(1,542	)		463
Gain on dispositions		—			33			—			71			—			104
Other income		—			17			—			69			—			86
Intercompany revenues		37			180			127			1,795			(2,139	)		—

Total Revenues and Other Income		298			7,293			127			12,625			(3,681	)		16,662

Costs and Expenses
Purchased commodities		—			5,128			—			3,104			(1,765	)		6,467
Production and operating expenses		—			795			—			2,839			(34	)		3,600
Selling, general and administrative expenses		6			282			—			98			(9	)		377
Exploration expenses		—			343			—			688			—			1,031
Depreciation, depletion and amortization		—			560			—			3,900			—			4,460
Impairments		—			—			—			94			—			94
Taxes other than income taxes		—			119			—			330			—			449
Accretion on discounted liabilities		—			29			—			214			—			243
Interest and debt expense		242			212			114			175			(331	)		412
Foreign currency transaction (gains) losses		47			—			(232	)		161			—			(24	)

Total Costs and Expenses		295			7,468			(118	)		11,603			(2,139	)		17,109

Income (loss) from continuing operations before income taxes		3			(175	)		245			1,022			(1,542	)		(447	)
Benefit from income taxes		(90	)		(436	)		(9	)		(34	)		—			(569	)

Income From Continuing Operations		93			261			254			1,056			(1,542	)		122
Net income		93			261			254			1,056			(1,542	)		122
Less: net income attributable to noncontrolling interests		—			—			—			(29	)		—			(29	)

Net Income Attributable to ConocoPhillips	$	93			261			254			1,027			(1,542	)		93

Comprehensive Income (Loss) Attributable to ConocoPhillips	$	(1,646	)		(1,478	)		(3	)		(886	)		2,367			(1,646	)


Income Statement	Six Months Ended June 30, 2014
Revenues and Other Income
Sales and other operating revenues	$	—			11,248			—			17,988			—			29,236
Equity in earnings of affiliates*		4,331			4,965			—			1,260			(9,312	)		1,244
Gain on dispositions		—			1			—			15			—			16
Other income		—			45			—			208			—			253
Intercompany revenues*		39			265			142			3,241			(3,687	)		—

Total Revenues and Other Income		4,370			16,524			142			22,712			(12,999	)		30,749

Costs and Expenses
Purchased commodities		—			9,948			—			5,921			(3,247	)		12,622
Production and operating expenses		—			841			—			3,134			(50	)		3,925
Selling, general and administrative expenses		6			280			—			128			(14	)		400
Exploration expenses		—			382			—			431			—			813
Depreciation, depletion and amortization		—			503			—			3,459			—			3,962
Impairments		—			18			—			—			—			18
Taxes other than income taxes		—			164			—			1,099			—			1,263
Accretion on discounted liabilities		—			29			—			208			—			237
Interest and debt expense*		307			132			116			147			(376	)		326
Foreign currency transaction (gains) losses		3			2			12			8			—			25

Total Costs and Expenses		316			12,299			128			14,535			(3,687	)		23,591

Income from continuing operations before income taxes		4,054			4,225			14			8,177			(9,312	)		7,158
Provision (benefit) for income taxes		(97	)		(106	)		(2	)		3,181			—			2,976

Income From Continuing Operations		4,151			4,331			16			4,996			(9,312	)		4,182
Income from discontinued operations		53			53			—			53			(106	)		53

Net income		4,204			4,384			16			5,049			(9,418	)		4,235
Less: net income attributable to noncontrolling interests		—			—			—			(31	)		—			(31	)

Net Income Attributable to ConocoPhillips	$	4,204			4,384			16			5,018			(9,418	)		4,204

Comprehensive Income (Loss) Attributable to ConocoPhillips	$	4,700			4,880			(5	)		5,475			(10,350	)		4,700

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


	Millions of Dollars
	June 30, 2015
Balance Sheet	ConocoPhillips			ConocoPhillips Company		ConocoPhillips Canada Funding Company I			All Other Subsidiaries		Consolidating Adjustments			Total Consolidated
Assets
Cash and cash equivalents	$	—			35		8			3,770		—			3,813
Accounts and notes receivable		12			1,950		15			6,492		(3,290	)		5,179
Inventories		—			199		—			1,078		—			1,277
Prepaid expenses and other current assets		1			656		20			1,043		(45	)		1,675

Total Current Assets		13			2,840		43			12,383		(3,335	)		11,944
Investments, loans and long-term receivables*		52,063			70,361		3,777			30,775		(132,324	)		24,652
Net properties, plants and equipment		—			9,924		—			64,463		—			74,387
Other assets		7			143		300			1,310		(740	)		1,020

Total Assets	$	52,083			83,268		4,120			108,931		(136,399	)		112,003

Liabilities and Stockholders’ Equity
Accounts payable	$	—			4,153		4			5,002		(3,290	)		5,869
Short-term debt		(9	)		1		5			141		—			138
Accrued income and other taxes		—			128		—			752		—			880
Employee benefit obligations		—			445		—			175		—			620
Other accruals		170			273		63			766		(45	)		1,227

Total Current Liabilities		161			5,000		72			6,836		(3,335	)		8,734
Long-term debt		7,513			10,661		2,969			3,644		—			24,787
Asset retirement obligations and accrued environmental costs		—			1,320		—			9,247		—			10,567
Deferred income taxes		—			331		—			14,048		(6	)		14,373
Employee benefit obligations		—			1,991		—			858		—			2,849
Other liabilities and deferred credits*		2,348			6,845		1,072			16,542		(25,083	)		1,724

Total Liabilities		10,022			26,148		4,113			51,175		(28,424	)		63,034
Retained earnings		36,258			21,707		(842	)		18,366		(32,710	)		42,779
Other common stockholders’ equity		5,803			35,413		849			39,041		(75,265	)		5,841
Noncontrolling interests		—			—		—			349		—			349

Total Liabilities and Stockholders’ Equity	$	52,083			83,268		4,120			108,931		(136,399	)		112,003

*Includes intercompany loans.

Balance Sheet	December 31, 2014
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
	Six Months Ended June 30, 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) Operating Activities		(124	)		348			1		3,623			194			4,042

Cash Flows From Investing Activities
Capital expenditures and investments		—			(1,642	)		—		(4,773	)		676			(5,739	)
Working capital changes associated with investing activities		—			(27	)		—		(651	)		—			(678	)
Proceeds from asset dispositions		2,000			94			—		205			(2,005	)		294
Long-term advances/loans—related parties		—			(179	)		—		(551	)		730			—
Collection of advances/loans—related parties		—			—			—		152			(100	)		52
Intercompany cash management		(231	)		(574	)		—		805			—			—
Other		—			292			—		(1	)		—			291

Net Cash Provided by (Used in) Investing Activities		1,769			(2,036	)		—		(4,814	)		(699	)		(5,780	)

Cash Flows From Financing Activities
Issuance of debt		—			3,049			—		179			(730	)		2,498
Repayment of debt		—			(100	)		—		(62	)		100			(62	)
Issuance of company common stock		172			—			—		—			(218	)		(46	)
Dividends paid		(1,819	)		—			—		(24	)		24			(1,819	)
Other		2			(1,996	)		—		630			1,329			(35	)

Net Cash Provided by (Used in) Financing Activities		(1,645	)		953			—		723			505			536

Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			—		(47	)		—			(47	)

Net Change in Cash and Cash Equivalents		—			(735	)		1		(515	)		—			(1,249	)
Cash and cash equivalents at beginning of period		—			770			7		4,285			—			5,062

Cash and Cash Equivalents at End of Period	$	—			35			8		3,770			—			3,813


Statement of Cash Flows	Six Months Ended June 30, 2014*
Cash Flows From Operating Activities
Net cash provided by continuing operating activities	$	14,876			55			31		9,868			(15,073	)		9,757
Net cash provided by discontinued operations		—			170			—		232			(272	)		130

Net Cash Provided by Operating Activities		14,876			225			31		10,100			(15,345	)		9,887

Cash Flows From Investing Activities
Capital expenditures and investments		—			(1,981	)		—		(7,106	)		946			(8,141	)
Working capital changes associated with investing activities		—			40			—		44			—			84
Proceeds from asset dispositions		16,912			13			—		60			(16,922	)		63
Net purchases of short-term investments		—			—			—		(8	)		—			(8	)
Long-term advances/loans—related parties		—			(546	)		—		(7	)		553			—
Collection of advances/loans—related parties		—			30			—		47			—			77
Intercompany cash management		(29,908	)		33,248			—		(3,340	)		—			—
Other		—			103			—		(7	)		—			96

Net cash provided by (used in) continuing investing activities		(12,996	)		30,907			—		(10,317	)		(15,423	)		(7,829	)
Net cash used in discontinued operations		—			(1	)		—		(63	)		1			(63	)

Net Cash Provided by (Used in) Investing Activities		(12,996	)		30,906			—		(10,380	)		(15,422	)		(7,892	)

Cash Flows From Financing Activities
Issuance of debt		—			—			—		553			(553	)		—
Repayment of debt		(400	)		—			—		(50	)		—			(450	)
Issuance of company common stock		234			—			—		—			(188	)		46
Dividends paid		(1,711	)		(15,088	)		—		(275	)		15,363			(1,711	)
Other		(3	)		(16,876	)		—		875			15,976			(28	)

Net cash provided by (used in) continuing financing activities		(1,880	)		(31,964	)		—		1,103			30,598			(2,143	)
Net cash used in discontinued operations		—			—			—		(169	)		169			—

Net Cash Provided by (Used in) Financing Activities		(1,880	)		(31,964	)		—		934			30,767			(2,143	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			—		44			—			44

Net Change in Cash and Cash Equivalents		—			(833	)		31		698			—			(104	)
Cash and cash equivalents at beginning of period		—			2,434			229		3,583			—			6,246

Cash and Cash Equivalents at End of Period	$	—			1,601			260		4,281			—			6,142

*Certain amounts have been reclassified to conform to current-period presentation. See Note 14—Cash Flow Information, in the Notes to the Consolidated Financial Statements.

Item 2.

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

Management’s Discussion and Analysis is the Company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes. It contains forward-looking statements including, without limitation, statements relating to the Company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The Company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the Company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 47.

Due to discontinued operations reporting, income (loss) from continuing operations is more representative of ConocoPhillips’ earnings. The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to income (loss) from continuing operations.

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 25 countries, approximately 18,100 employees worldwide and total assets of $112 billion as of June 30, 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 modest 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 set our 2015 capital budget at $11.5 billion. In April 2015, the company also set its operating plan for 2016 and 2017 at $11.5 billion of anticipated annual capital spending. This three-year plan was expected 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. In the second quarter, we revised our 2015 capital guidance to $11.0 billion. We also stated that 2016 and 2017 capital spending could be adjusted based on commodity prices. We can achieve cash flow neutrality in 2017 at a Brent price of approximately $60 per barrel by further exercising capital flexibility.

To improve cash flow generation and margins, 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 revised 2015 capital guidance of $11.0 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 second quarter, the company achieved first steam at Surmont 2 in Canada and first production at Enochdhu in Europe.

We achieved production of 1,595 thousand barrels of oil equivalent per day (MBOED) in the second quarter of 2015. Adjusted for downtime and dispositions of 30 MBOED, our production from continuing operations, excluding Libya, increased by 69 MBOED, or 4 percent, compared with the second 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. Through the second quarter of 2015, we funded $5.7 billion of capital expenditures, or 52 percent of our updated capital guidance. 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. Considering these objectives, the competitive cost of supply and shorter cycle time of our captured resource project inventory, and the continued weakness in oil and gas prices, we recently announced plans to reduce future capital spending in our deepwater exploration program, primarily in the operated Gulf of Mexico. We continue to actively monitor the commodity price environment and will further adjust capital and/or exercise capacity on our balance sheet, as necessary.

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 the third quarter of 2014, as surging production growth from U.S. tight oil and the decision by the Organization of Petroleum Exporting Countries (OPEC) to maintain production outweighed fears of supply disruptions. These developments, combined with lower forecasts for global oil demand growth, caused crude oil prices to plummet to near five-year lows at the end of 2014. Although prices rebounded slightly to the upper $50- to low $60-per barrel range in the second quarter of 2015, they remained significantly lower than the same period in 2014.

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 beyond our control. Commodity prices are the most significant factor impacting our profitability and the related reinvestment of operating cash flows into our business. Other dynamics that influence world energy markets and commodity prices include global economic health, 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, primarily due to advances in technology responsible for the rapid growth of unconventional 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, competitive cost structure, and a diverse low cost-of-supply portfolio 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 $61.92 per barrel in the second quarter of 2015, a decrease of 44 percent compared with $109.63 per barrel in the second quarter of 2014, and an increase of 15 percent compared with $53.97 per barrel in the first quarter of 2015. Industry crude prices for WTI averaged $57.84 per barrel in the second quarter of 2015, a decrease of 44 percent compared with $103.05 per barrel in the second quarter of 2014, and an increase of 19 percent compared with $48.56 per barrel in the first quarter of 2015. Although marginally improved in comparison to the first quarter of 2015, crude oil prices have remained under pressure through the second quarter of 2015 due to continued growth in global production outpacing increasing demand growth, as evidenced by a large observed inventory increase.

Henry Hub natural gas prices averaged $2.65 per thousand cubic feet (MCF) in the second quarter of 2015, a decrease of 43 percent compared with $4.68 per MCF in the second quarter of 2014, and a decrease of 11 percent compared with $2.99 in the first quarter of 2015. 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.

Bitumen prices remained low in the second quarter of 2015, mainly as a result of decreased global crude oil prices. Our realized bitumen price was $33.30 per barrel in the second quarter of 2015, a decrease of 49 percent compared with $65.82 in the second quarter of 2014. The second quarter realized price increased 93 percent from $17.22 per barrel in the first quarter of 2015 as both WTI and light-to-heavy differentials strengthened.

Our total average realized price was $39.09 per barrel of oil equivalent (BOE) in the second quarter of 2015, a decrease of 44 percent compared with $70.17 per BOE in the second quarter of 2014. In the first six months of 2015, our total realized price was $38.03 per BOE, a decrease of 46 percent compared with $70.68 in the first six months of 2014. Both the quarterly and annual price decreases reflected lower average realized prices for crude oil, natural gas, bitumen and natural gas liquids.

Key Operating and Financial Highlights

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

•

Increased quarterly dividend to $0.74 per share in July.

•

Achieved second-quarter total production of 1,595 MBOED; on track to achieve higher end of 2015 growth target.

•

Four percent year-over-year production growth from continuing operations when adjusted for Libya, downtime and dispositions.

•

Achieved major project startup at Enochdhu in Europe and first steam at Surmont 2 in Canada; on track for first production at Surmont 2, APLNG, CD5 and Drill Site 2S by year-end.

•

Announced reductions in future deepwater exploration spending.

•

Lowering 2015 capital expenditures guidance from $11.5 billion to $11.0 billion.

Outlook

Production and Capital Guidance

Third-quarter 2015 production guidance, excluding Libya, is expected to be 1,510 MBOED to 1,550 MBOED, reflecting planned downtime and turnaround activity. Full-year 2015 production is expected to be at the higher end of our 2015 production target of 2 to 3 percent growth, excluding Libya.

The company has reduced its 2015 capital expenditures guidance from $11.5 billion to $11.0 billion. The reductions are a result of deflation and foreign exchange rate benefits, project deferrals, and improved program efficiencies.

Deepwater Exploration Update

Restructuring Costs

In response to the current commodity price environment, we have targeted a $1 billion reduction in operating costs in 2016 compared to 2014 aimed at increasing efficiency and achieving sustainable cost reductions. Given this initiative, as well as the reduction in future deepwater exploration spending noted above, we expect to incur additional restructuring charges in the second half of 2015. As the cost reduction analysis is ongoing, it is not reasonably possible to quantify the financial impact, but the impact could be material to our results of operations for the period in which the restructuring costs are incurred.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and six-month periods ended June 30, 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						Six Months Ended
	June 30						June 30
	2015			2014			2015			2014

Alaska	$	195			627			340			1,225
Lower 48		(293	)		265			(698	)		589
Canada		(166	)		182			(324	)		538
Europe		37			259			674			606
Asia Pacific and Middle East		343			862			752			1,618
Other International		(148	)		121			(241	)		92
Corporate and Other		(132	)		(251	)		(381	)		(486	)

Income (loss) from continuing operations	$	(164	)		2,065			122			4,182

Earnings for ConocoPhillips decreased 108 and 97 percent for the second quarter of 2015 and the six-month period ended June 30, 2015, respectively. The decrease in both periods primarily resulted from lower commodity prices.

In addition, earnings were negatively impacted by:

•

Higher depreciation, depletion and amortization (DD&A) expenses.

•

The absence of $154 million after-tax income in the second quarter of 2014 associated with the favorable resolution of a contingent liability.

•

An adverse deferred tax charge of $129 million, from increased corporate tax rates in Canada in the second quarter of 2015.

•

Higher exploration expenses, primarily in the first quarter of 2015.

These items were partially offset by:

•

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

•

A $555 million net deferred tax benefit resulting from a change in the U.K. tax rate in the first quarter of 2015.

•

Lower operating expense.

•

Higher licensing revenues in the second quarter of 2015.

•

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

See the “Segment Results” section for additional information.

Income Statement Analysis

Sales and other operating revenues decreased 40 percent in the second quarter and 45 percent in the six-month period of 2015, mainly as a result of lower prices across all commodities. Lower prices in both periods were partly offset by higher crude oil, bitumen, LNG and natural gas sales volumes.

Equity in earnings of affiliates decreased 62 percent in the second quarter and 63 percent in the six-month period of 2015, primarily as a result of lower earnings from the FCCL Partnership and Qatar Liquefied Gas Company Limited (3) (QG3) due to lower commodity prices. The decrease in the second quarter was partly offset by lower operating expenses in FCCL and QG3. The decrease in the six-month period of 2015 was also partly offset by benefits of foreign exchange-related tax impacts from APLNG.

Other income decreased 72 percent in the second quarter and 66 percent in the six-month period of 2015. The decrease in both periods was mainly due to the absence of income from the second quarter of 2014 related to the resolution of a contingent liability.

Purchased commodities decreased 41 percent in the second quarter and 49 percent in the six-month period 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 recognized in the first quarter of 2014.

Production and operating expenses decreased 11 percent in the second quarter of 2015, primarily as a result of favorable foreign exchange-related impacts and lower operating expense activity.

Exploration expenses increased 27 percent in the six-month period of 2015, primarily due to dry hole costs associated with the Vali-1 and Omosi-1 wells offshore Angola and the Harrier prospect in the Gulf of Mexico, along with undeveloped leasehold impairments in Angola and Poland. The increased expense was partly offset by the absence of a $145 million impairment of undeveloped leasehold costs associated with the offshore Canada Amauligak discovery, Arctic Islands and Beaufort properties in the second quarter of 2014.

DD&A increased 13 percent in the second quarter and in the six-month period of 2015. The increase in both periods was associated with higher production volumes in the Lower 48 and Asia Pacific and Middle East. Additionally, a significant decline in the 12-month rolling-average price used to calculate proved reserves resulted in an increase in the second quarter of 2015 of approximately $90 million in the Lower 48 and Alaska combined. The increases were partly offset by reserve additions in Lower 48.

Taxes other than income taxes decreased 63 percent for the second quarter and 64 percent for the six-month period of 2015, mainly as a result of lower crude oil prices and volumes in Alaska and lower commodity prices in Asia Pacific and Middle East and Lower 48.

See Note 18—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.

Summary Operating Statistics

Three Months Ended
June 30

Six Months Ended
June 30

2015

2014

2015

2014

Average Net Production

Crude oil (MBD)*

608

596

615

597

Natural gas liquids (MBD)

160

167

158

163

Bitumen (MBD)

138

128

147

126

Natural gas (MMCFD)**

4,136

3,998

4,098

3,950

Total Production (MBOED)

1,595

1,557

1,603

1,544

Dollars Per Unit

Average Sales Prices

Crude oil (per barrel)

58.00

103.39

53.00

102.51

Natural gas liquids (per barrel)

19.62

40.36

19.61

43.31

Bitumen (per barrel)

33.30

65.82

24.79

61.21

Natural gas (per thousand cubic feet)

3.90

6.82

4.30

7.18

Millions of Dollars

Exploration Expenses

General administrative, geological and geophysical, and

lease rentals

147

183

318

410

Leasehold impairment

245

189

285

235

Dry holes

157

145

428

168

549

517

1,031

813

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 June 30, 2015, our 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, and average liquids production both increased 2 percent in the second quarter of 2015 and 4 percent in the six-month period of 2015. 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 Brodgar H3 subsea tie-back, the Jasmine Field, and the Britannia Long-Term Compression Project in the U.K.; as well as improved well performance, mostly in western Canada, the Lower 48 and Norway. These increases were largely offset by normal field decline and unplanned downtime, including the precautionary shut down of Foster Creek in Canada, for nearby forest fires. In the second quarter of 2015, we achieved production of 1,595 MBOED. Adjusted for downtime and dispositions of 30 MBOED, our production from continuing operations, excluding Libya, increased by 69 MBOED, or 4 percent, compared with the second quarter of 2014.

Segment Results

Alaska


	Three Months Ended June 30				Six Months Ended June 30
	2015		2014		2015		2014

Income From Continuing Operations (millions of dollars)	$	195		627		340		1,225

Average Net Production
Crude oil (MBD)		154		170		159		173
Natural gas liquids (MBD)		13		16		13		16
Natural gas (MMCFD)		41		45		46		50

Total Production (MBOED)		174		193		180		197

Average Sales Prices
Crude oil (dollars per barrel)	$	61.51		108.93		55.99		107.67
Natural gas (dollars per thousand cubic feet)		4.50		6.03		4.38		5.59

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. As of June 30, 2015, Alaska contributed 19 percent of our worldwide liquids production and 1 percent of our worldwide natural gas production.

Earnings from Alaska decreased 69 percent in the second quarter and 72 percent for the six-month period of 2015. The decrease in earnings in both periods was primarily due to lower crude oil prices, partly offset by lower production taxes. Lower sales volumes in the second quarter also contributed to the earnings decrease.

Average production decreased 10 percent in the second quarter and 9 percent for the six-month period of 2015, compared with the same period in 2014, due to normal field decline and downtime.

Lower 48


	Three Months Ended June 30					Six Months Ended June 30
	2015			2014		2015			2014

Income (Loss) From Continuing Operations (millions of dollars)	$	(293	)		265		(698	)		589

Average Net Production
Crude oil (MBD)		209			191		204			181
Natural gas liquids (MBD)		97			100		95			96
Natural gas (MMCFD)		1,501			1,495		1,503			1,482

Total Production (MBOED)		556			540		549			524

Average Sales Prices
Crude oil (dollars per barrel)	$	52.01			93.73		46.58			92.69
Natural gas liquids (dollars per barrel)		15.29			31.28		15.41			33.54
Natural gas (dollars per thousand cubic feet)		2.38			4.43		2.49			4.75

As of June 30, 2015, the Lower 48 contributed 33 percent of our worldwide liquids production and 37 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 losses of $293 million in the second quarter and $698 million in the six-month period of 2015, a $558 million and $1,287 million decrease compared with the same periods of 2014, respectively. Earnings decreases in both periods were primarily due to lower crude oil, natural gas and natural gas liquids prices and higher DD&A from increased crude oil production, partly offset by higher sales volumes. For the six-month period of 2015, earnings decreases were partially offset by 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 second quarter of 2015, our average realized crude oil price of $52.01 per barrel was 10 percent less than WTI of $57.84 per barrel. Current market dynamics indicate this crude differential may remain relatively wide in the near-term.

Total average production increased 3 percent in the second quarter and 5 percent for the six-month period of 2015. Average crude oil production increased 9 percent and 13 percent over the same periods, respectively. The increases in both periods were mainly attributable to new production, primarily from Eagle Ford and Bakken, and improved drilling and well performance, partially offset by normal field decline and increased ethane rejection.

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. We completed plug and abandon operations on the Harrier exploration well in the second quarter of 2015.

Canada


	Three Months Ended June 30					Six Months Ended June 30
	2015			2014		2015			2014

Income (Loss) From Continuing Operations (millions of dollars)	$	(166	)		182		(324	)		538

Average Net Production
Crude oil (MBD)		13			12		14			12
Natural gas liquids (MBD)		26			25		26			25
Bitumen (MBD)
Consolidated operations		12			14		12			13
Equity affiliates		126			114		135			113

Total bitumen		138			128		147			126
Natural gas (MMCFD)		768			713		752			710

Total Production (MBOED)		306			284		312			282

Average Sales Prices
Crude oil (dollars per barrel)	$	46.58			86.33		41.72			83.27
Natural gas liquids (dollars per barrel)		19.23			46.56		18.77			51.36
Bitumen (dollars per barrel)
Consolidated operations		39.74			68.00		32.03			64.95
Equity affiliates		32.66			65.55		24.11			60.75
Total bitumen		33.30			65.82		24.79			61.21
Natural gas (dollars per thousand cubic feet)		1.88			4.13		2.04			4.96

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 June 30, 2015, Canada contributed 20 percent of our worldwide liquids production and 18 percent of our worldwide natural gas production.

Canada operations reported losses of $166 million in the second quarter and $324 million for the six-month period of 2015, a $348 million and $862 million decrease compared with the same periods of 2014, respectively. The decrease in earnings, in both periods, was primarily due to lower bitumen and natural gas prices partly offset by higher production volumes, lower operating expenses from favorable foreign currency impacts, and lower DD&A from lower unit-of-production rates and favorable foreign currency impacts. Earnings in the second quarter were also reduced due to the $136 million impact of a 2 percent increase in Alberta corporate tax rates on deferred taxes.

Total average production increased 8 percent in the second quarter and 11 percent for the six-month period of 2015, while bitumen production increased 8 percent and 17 percent over the same periods, respectively. The increases in total production in both periods were mainly attributable to strong well performance in western Canada, strong plant performance at Foster Creek and Christina Lake, lower royalty impacts and the continued ramp-up of production from Foster Creek Phase F. These increases were partly offset by normal field decline and unplanned downtime from the precautionary shut down of Foster Creek for nearby forest fires in the second quarter of 2015.

Europe


	Three Months Ended June 30				Six Months Ended June 30
	2015		2014		2015		2014

Income From Continuing Operations (millions of dollars)	$	37		259		674		606

Average Net Production
Crude oil (MBD)		120		126		119		130
Natural gas liquids (MBD)		6		7		7		7
Natural gas (MMCFD)		482		480		488		476

Total Production (MBOED)		206		213		208		216

Average Sales Prices
Crude oil (dollars per barrel)	$	62.35		111.38		58.44		110.17
Natural gas liquids (dollars per barrel)		29.54		57.32		29.69		58.99
Natural gas (dollars per thousand cubic feet)		7.23		8.99		7.78		9.95

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 June 30, 2015, our Europe operations contributed 14 percent of our worldwide liquids production and 12 percent of our worldwide natural gas production.

Earnings for Europe operations decreased 86 percent in the second quarter and increased 11 percent for the six-month period of 2015. Earnings in both periods were primarily impacted by lower crude oil and natural gas prices. The second-quarter earnings decrease was also due to a $33 million after-tax property impairment, given lower natural gas prices, offset by lower operating expense from favorable foreign currency impacts. For the six-month period of 2015, earnings increased 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.

Average production decreased 3 percent in the second quarter and 4 percent for the six-month period of 2015, compared to the same periods in 2014. The decrease in both periods was mostly due to normal field decline, partly offset by continued ramp-up of production from the Greater Britannia Area, the Jasmine Field and the Greater Ekofisk Area; as well as lower downtime.

Asia Pacific and Middle East


	Three Months Ended June 30				Six Months Ended June 30
	2015		2014		2015		2014

Income From Continuing Operations (millions of dollars)	$	343		862		752		1,618

Average Net Production
Crude oil (MBD)
Consolidated operations		93		76		100		81
Equity affiliates		15		16		15		15

Total crude oil		108		92		115		96

Natural gas liquids (MBD)
Consolidated operations		10		11		9		12
Equity affiliates		8		8		8		7

Total natural gas liquids		18		19		17		19

Natural gas (MMCFD)
Consolidated operations		721		748		716		738
Equity affiliates		622		516		592		492

Total natural gas		1,343		1,264		1,308		1,230

Total Production (MBOED)		349		322		350		320

Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	60.55		105.65		55.47		105.30
Equity affiliates		63.49		108.09		58.07		107.82
Total crude oil		60.97		106.07		55.82		105.71
Natural gas liquids (dollars per barrel)
Consolidated operations		40.35		71.52		40.62		75.48
Equity affiliates		38.24		68.84		38.51		73.71
Total natural gas liquids		39.45		70.46		39.72		74.80
Natural gas (dollars per thousand cubic feet)
Consolidated operations		6.48		10.32		6.85		10.32
Equity affiliates		4.42		10.46		5.85		10.45
Total natural gas		5.53		10.38		6.40		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 Brunei and Myanmar. As of June 30, 2015, Asia Pacific and Middle East contributed 14 percent of our worldwide liquids production and 32 percent of our worldwide natural gas production.

Earnings for Asia Pacific and Middle East operations decreased 60 percent in the second quarter and 54 percent in the six-month period of 2015. The decrease in earnings for both periods was mainly due to lower prices across all commodities and higher DD&A. The decrease was partially offset by lower production taxes, as a result of lower crude oil prices, increased crude oil and LNG volumes, and lower feedstock costs in Australia West.

Average production increased 8 percent in the second quarter and 9 percent in the six-month period of 2015 compared with the same periods of 2014. The production increase in both periods was 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 drilling and well performance in China. Production increases were partially offset by normal field decline.

Other International


	Three Months Ended June 30					Six Months Ended June 30
	2015			2014		2015			2014

Income (Loss) From Continuing Operations (millions of dollars)	$	(148	)		121		(241	)		92

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

Total crude oil		4			5		4			5

Natural gas (MMCFD)		1			1		1			2

Total Production (MBOED)		4			5		4			5

Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	—			107.33		—			107.33
Equity affiliates		45.44			72.59		40.50			70.16
Total crude oil		45.44			74.91		40.50			71.42
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, Angola, Senegal and Azerbaijan. As of June 30, 2015, Other International contributed less than 1 percent of our worldwide liquids production.

Other International operations reported a loss of $148 million in the second quarter and $241 million for the six-month period of 2015, compared with gains of $121 million and $92 million, respectively, in the same periods of 2014. The second quarter decrease in earnings was primarily due to the absence of a $154 million benefit from the favorable resolution of a contingent liability in 2014, higher exploration expenses related to the Angola Block 37 and Poland leasehold impairments, and the $59 million after-tax dry hole expense for the Vali-1 well. Dry hole expense for the Omosi-1 well, coupled with the second quarter decreases drive the earnings decrease for the six-month period of 2015.

Average production decreased by 1 MBOED in both the second quarter and six-month period of 2015 compared with the same periods in 2014, due to the current situation in Libya. Libya production remains shut in, as the Es Sider crude oil export terminal closure has continued throughout the second 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. In June 2015, we plugged and abandoned the Vali-1 exploration well, the third wildcat in our planned four-well exploration program in the Kwanza Basin. In June 2015, due to lack of commerciality of wells drilled, the decision was made to impair Block 37 offshore Angola. We have a 50 percent participating interest in Block 36 offshore Angola with a leasehold net book value of $377 million.

Corporate and Other


	Millions of Dollars
	Three Months Ended June 30						Six Months Ended June 30
	2015			2014			2015			2014

Income (Loss) From Continuing Operations
Net interest	$	(161	)		(158	)		(316	)		(321	)
Corporate general and administrative expenses		(71	)		(51	)		(92	)		(82	)
Technology		88			(20	)		72			(48	)
Other		12			(22	)		(45	)		(35	)

	$	(132	)		(251	)		(381	)		(486	)

Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased 2 percent in the second quarter and decreased 2 percent in the six-month period of 2015 compared with the same periods in 2014. Net interest in the second quarter increased primarily due to increased debt and lower capitalized interest on projects. For the six-month period of 2015, this increase was offset by a tax benefit associated with the election of the fair market value method of apportioning interest expense in the United States.

Corporate general and administrative expenses increased 39 percent in the second quarter and 12 percent in the six-month period of 2015. The increase was mainly due to pension settlement expenses incurred in the second quarter of 2015.

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. Earnings from Technology were $88 million in the second quarter and $72 million in the six-month period of 2015, compared with losses of $20 million and $48 million, respectively, in the same periods of 2014. The increase in earnings primarily resulted from 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 decreased 155 percent in the second quarter of 2015, reflecting lower environmental expenses and favorable foreign currency transaction impacts. For the six-month period of 2015, “Other” expenses increased 29 percent, as the second quarter reductions were more than offset by foreign currency transaction losses and restructuring charges incurred in the first quarter of 2015.

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators


	Millions of Dollars
	June 30 2015			December 31 2014

Short-term debt	$	138			182
Total debt		24,925			22,565
Total equity		48,969			52,273
Percent of total debt to capital*		34	%		30
Percent of floating-rate debt to total debt		7	%		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 six months of 2015, the primary uses of our available cash were $5,739 million to support our ongoing capital expenditures and investments program, $1,819 million to pay dividends and $62 million to repay debt. During the first six months of 2015, cash and cash equivalents decreased by $1,249 million, to $3,813 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 $4,042 million for the first six months of 2015, compared with $9,757 million for the corresponding period of 2014, a 59 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.

Investing Activities

Proceeds from asset sales for the first six months of 2015 were $294 million, compared with $63 million for the corresponding period of 2014. We continue to optimize our asset portfolio by focusing on assets which offer the highest returns and growth potential, while selling nonstrategic holdings.

In May 2015, we liquidated certain deferred compensation investments for proceeds of $267 million, which is included in the “Other” line within “Cash Flows From Investing Activities” on our consolidated statement of cash flows. We do not expect further material liquidations associated with deferred compensation investments. For additional information, see Note 12—Fair Value Measurement, in the Notes to Consolidated Financial Statements.

Commercial Paper and Credit Facilities

At June 30, 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 QG3. At both June 30, 2015 and December 31, 2014, we had no direct borrowings or letters of credit issued under the revolving credit facility. Under the ConocoPhillips Qatar Funding Ltd. commercial paper programs, $806 million of commercial paper was outstanding at June 30, 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 June 30, 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 June 30, 2015 and December 31, 2014, we had direct bank letters of credit of $400 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 9—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Capital Requirements

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

Our debt balance at June 30, 2015, was $24.9 billion, an increase of $2.4 billion from the balance at December 31, 2014, primarily as a result of the May 2015 issuance of $2.5 billion in new fixed and floating rate notes. For more information, see Note 7—Debt, in the Notes to Consolidated Financial Statements.

In May 2015, we announced a dividend of 73 cents per share. The dividend was paid June 1, 2015, to stockholders of record at the close of business on May 22, 2015. In July 2015, we announced an increase in the quarterly dividend rate to 74 cents per share. The dividend will be paid September 1, 2015, to stockholders of record at the close of business on July 27, 2015.

Capital Spending


	Millions of Dollars
	Six Months Ended June 30
	2015		2014

Alaska	$	781		805
Lower 48		2,254		2,697
Canada		727		1,137
Europe		867		1,252
Asia Pacific and Middle East		920		1,942
Other International		126		239
Corporate and Other		64		69

Capital expenditures and investments from continuing operations	$	5,739		8,141

Discontinued operations in Nigeria:	$	—		50

Working capital changes associated with investing activities decreased cash flow by $678 million for the first six months of 2015, compared with an increase of $84 million for the corresponding period of 2014. The decrease is attributable to reduced capital accruals from lower activity levels in 2015, primarily in the Lower 48 and Canada. We do not anticipate any further significant changes to working capital from activity levels in 2015.

During the first six 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 exploration and appraisal activity in Malaysia, Indonesia, China and offshore Australia.

•

Exploration activities in Angola.

Contingencies

Legal Matters

Environmental

We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. For a discussion of the most significant of these environmental laws and regulations, including those with associated remediation obligations, see the “Environmental” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 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 June 30, 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 June 30, 2015, our balance sheet included a total environmental accrual of $306 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 six months ended June 30, 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 June 30, 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 June 30, 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 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



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)

August 4, 2015