Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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CONOCOPHILLIPS

INDEX TO FINANCIAL STATEMENTS


	Page
Report of Management		82

Reports of Independent Registered Public Accounting Firm		83

Consolidated Income Statement for the years ended December 31, 2018, 2017 and 2016		85

Consolidated Statement of Comprehensive Income for the years ended December 31, 2018, 2017 and 2016		86

Consolidated Balance Sheet at December 31, 2018 and 2017		87

Consolidated Statement of Cash Flows for the years ended December 31, 2018, 2017 and 2016		88

Consolidated Statement of Changes in Equity for the years ended December 31, 2018, 2017 and 2016		89

Notes to Consolidated Financial Statements		90

Supplementary Information

Oil and Gas Operations		153

Selected Quarterly Financial Data		180

Condensed Consolidating Financial Information		181

Report of Management

Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the company’s financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the company includes amounts that are based on estimates and judgments management believes are reasonable under the circumstances. The company’s financial statements have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed by the Audit and Finance Committee of the Board of Directors and ratified by stockholders. Management has made available to Ernst & Young LLP all of the company’s financial records and related data, as well as the minutes of stockholders’ and directors’ meetings.

Assessment of Internal Control Over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. ConocoPhillips’ internal control system was designed to provide reasonable assurance to the company’s management and directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2018. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework (2013). Based on our assessment, we believe the company’s internal control over financial reporting was effective as of December 31, 2018.

Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2018, and their report is included herein.


/s/ Ryan M. Lance				/s/ Don E. Wallette, Jr.

Ryan M. Lance				Don E. Wallette, Jr.
Chairman and Chief Executive Officer				Executive Vice President and Chief Financial Officer

February 19, 2019

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of ConocoPhillips

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of ConocoPhillips as of December 31, 2018 and 2017, and the related consolidated income statement, consolidated statements of comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2018, and the related notes, condensed consolidating financial information listed in the Index at Item 8, and financial statement schedule listed in Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of ConocoPhillips at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), ConocoPhillips’ internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 19, 2019, expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of ConocoPhillips’ management. Our responsibility is to express an opinion on ConocoPhillips’ financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to ConocoPhillips in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as ConocoPhillips’ auditor since 1949.

Houston, Texas

February 19, 2019

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of ConocoPhillips

Opinion on Internal Control over Financial Reporting

We have audited ConocoPhillips’ internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, ConocoPhillips maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets as of December 31, 2018 and 2017, and the related consolidated income statement, consolidated statements of comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2018, and the related notes, condensed consolidating financial information listed in the Index at Item 8, and financial statement schedule listed in Item 15(a) of ConocoPhillips and our report dated February 19, 2019 expressed an unqualified opinion thereon.

Basis for Opinion

ConocoPhillips’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included under the heading “Assessment of Internal Control Over Financial Reporting” in the accompanying “Report of Management.” Our responsibility is to express an opinion on ConocoPhillips’ internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to ConocoPhillips in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Houston, Texas

February 19, 2019


Consolidated Income Statement		ConocoPhillips

Years Ended December 31


	Millions of Dollars

	2018			2017*			2016*

Revenues and Other Income
Sales and other operating revenues	$	36,417			29,106			23,693
Equity in earnings of affiliates		1,074			772			52
Gain on dispositions		1,063			2,177			360
Other income		173			529			255

Total Revenues and Other Income		38,727			32,584			24,360


Costs and Expenses
Purchased commodities		14,294			12,475			9,994
Production and operating expenses		5,213			5,162			5,643
Selling, general and administrative expenses		401			427			473
Exploration expenses		369			934			1,912
Depreciation, depletion and amortization		5,956			6,845			9,062
Impairments		27			6,601			139
Taxes other than income taxes		1,048			809			739
Accretion on discounted liabilities		353			362			425
Interest and debt expense		735			1,098			1,245
Foreign currency transaction (gains) losses		(17	)		35			(19	)
Other expenses		375			451			277

Total Costs and Expenses		28,754			35,199			29,890

Income (loss) before income taxes		9,973			(2,615	)		(5,530	)
Income tax provision (benefit)		3,668			(1,822	)		(1,971	)

Net income (loss)		6,305			(793	)		(3,559	)
Less: net income attributable to noncontrolling interests		(48	)		(62	)		(56	)

Net Income (Loss) Attributable to ConocoPhillips	$	6,257			(855	)		(3,615	)


Net Income (Loss) Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic	$	5.36			(0.70	)		(2.91	)
Diluted		5.32			(0.70	)		(2.91	)


Average Common Shares Outstanding (in thousands)
Basic		1,166,499			1,221,038			1,245,440
Diluted		1,175,538			1,221,038			1,245,440

*Certain amounts have been reclassified to conform to the current-period presentation resulting from the adoption of ASU No. 2017-07. See Note 2—Changes in Accounting Principles, for additional information.

See Notes to Consolidated Financial Statements.


Consolidated Statement of Comprehensive Income		ConocoPhillips

Years Ended December 31


	Millions of Dollars

	2018			2017			2016


Net Income (Loss)	$	6,305			(793	)		(3,559	)
Other comprehensive income (loss)
Defined benefit plans
Prior service credit (cost) arising during the period		(7	)		2			23
Reclassification adjustment for amortization of prior service credit included in net loss		(40	)		(38	)		(35	)

Net change		(47	)		(36	)		(12	)

Net actuarial gain (loss) arising during the period		(150	)		19			(481	)
Reclassification adjustment for amortization of net actuarial losses included in net income (loss)		279			247			309

Net change		129			266			(172	)
Nonsponsored plans*		(1	)		(2	)		2
Income taxes on defined benefit plans		(42	)		(81	)		78

Defined benefit plans, net of tax		39			147			(104	)

Unrealized holding loss on securities		-			(58	)		-

Unrealized loss on securities, net of tax**		-			(58	)		-

Foreign currency translation adjustments		(645	)		586			153
Reclassification adjustment for gain included in net loss		-			-			5
Income taxes on foreign currency translation adjustments		3			-			-

Foreign currency translation adjustments, net of tax		(642	)		586			158

Other Comprehensive Income (Loss), Net of Tax		(603	)		675			54

Comprehensive Income (Loss)		5,702			(118	)		(3,505	)
Less: comprehensive income attributable to noncontrolling interests		(48	)		(62	)		(56	)

Comprehensive Income (Loss) Attributable to ConocoPhillips	$	5,654			(180	)		(3,561	)

* Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates. ** See Note 2—Changes in Accounting Principles and Note 20—Accumulated Other Comprehensive Loss, for additional information relating to the adoption of ASU No. 2016-01.
See Notes to Consolidated Financial Statements.


Consolidated Balance Sheet		ConocoPhillips


At December 31	Millions of Dollars

		2018		2017

Assets
Cash and cash equivalents	$	5,915		6,325
Short-term investments		248		1,873
Accounts and notes receivable (net of allowance of $25 million in 2018 and $4 million in 2017)		3,920		4,179
Accounts and notes receivable—related parties		147		141
Investment in Cenovus Energy		1,462		1,899
Inventories		1,007		1,060
Prepaid expenses and other current assets		575		1,035

Total Current Assets		13,274		16,512
Investments and long-term receivables		9,329		9,599
Loans and advances—related parties		335		461
Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $64,899 million in 2018 and $64,748 million in 2017)		45,698		45,683
Other assets		1,344		1,107

Total Assets	$	69,980		73,362


Liabilities
Accounts payable	$	3,863		4,009
Accounts payable—related parties		32		21
Short-term debt		112		2,575
Accrued income and other taxes		1,320		1,038
Employee benefit obligations		809		725
Other accruals		1,259		1,029

Total Current Liabilities		7,395		9,397
Long-term debt		14,856		17,128
Asset retirement obligations and accrued environmental costs		7,688		7,631
Deferred income taxes		5,021		5,282
Employee benefit obligations		1,764		1,854
Other liabilities and deferred credits		1,192		1,269

Total Liabilities		37,916		42,561


Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2018—1,791,637,434 shares; 2017—1,785,419,175 shares)
Par value		18		18
Capital in excess of par		46,879		46,622
Treasury stock (at cost: 2018—653,288,213 shares; 2017—608,312,034 shares)		(42,905	)	(39,906	)
Accumulated other comprehensive loss		(6,063	)	(5,518	)
Retained earnings		34,010		29,391

Total Common Stockholders’ Equity		31,939		30,607
Noncontrolling interests		125		194

Total Equity		32,064		30,801

Total Liabilities and Equity	$	69,980		73,362

See Notes to Consolidated Financial Statements.


Consolidated Statement of Cash Flows		ConocoPhillips


Years Ended December 31	Millions of Dollars

	2018			2017			2016

Cash Flows From Operating Activities
Net income (loss)	$	6,305			(793	)		(3,559	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization		5,956			6,845			9,062
Impairments		27			6,601			139
Dry hole costs and leasehold impairments		95			566			1,184
Accretion on discounted liabilities		353			362			425
Deferred taxes		283			(3,681	)		(2,221	)
Undistributed equity earnings		152			(232	)		299
Gain on dispositions		(1,063	)		(2,177	)		(360	)
Other		191			(429	)		(85	)
Working capital adjustments
Decrease (increase) in accounts and notes receivable		235			(886	)		820
Decrease (increase) in inventories		86			(55	)		44
Decrease (increase) in prepaid expenses and other current assets		(55	)		69			105
Increase (decrease) in accounts payable		(52	)		265			(524	)
Increase (decrease) in taxes and other accruals		421			622			(926	)

Net Cash Provided by Operating Activities		12,934			7,077			4,403


Cash Flows From Investing Activities
Capital expenditures and investments		(6,750	)		(4,591	)		(4,869	)
Working capital changes associated with investing activities		(68	)		132			(331	)
Proceeds from asset dispositions		1,082			13,860			1,286
Net sales (purchases) of short-term investments		1,620			(1,790	)		(51	)
Collection of advances/loans—related parties		119			115			108
Other		154			36			(2	)

Net Cash Provided by (Used in) Investing Activities		(3,843	)		7,762			(3,859	)


Cash Flows From Financing Activities
Issuance of debt		-			-			4,594
Repayment of debt		(4,995	)		(7,876	)		(2,251	)
Issuance of company common stock		121			(63	)		(63	)
Repurchase of company common stock		(2,999	)		(3,000	)		(126	)
Dividends paid		(1,363	)		(1,305	)		(1,253	)
Other		(123	)		(112	)		(137	)

Net Cash Provided by (Used in) Financing Activities		(9,359	)		(12,356	)		764


Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash		(117	)		232			(66	)


Net Change in Cash, Cash Equivalents and Restricted Cash		(385	)		2,715			1,242
Cash, cash equivalents and restricted cash at beginning of period		6,536	*****		3,610			2,368

Cash, Cash Equivalents and Restricted Cash at End of Period	$	6,151			6,325			3,610

* Restated to include $211 million of restricted cash at January 1, 2018. See Note 2—Changes in Accounting Principles for additional information relating to the adoption of ASU No. 2016-18.

Restricted cash totaling $236 million is included in the “Other assets” line of our Consolidated Balance Sheet as of December 31, 2018.

See Notes to Consolidated Financial Statements.


Consolidated Statement of Changes in Equity		ConocoPhillips


		Millions of Dollars

		Attributable to ConocoPhillips

		Common Stock

	Par Value		Capital in Excess of Par		Treasury Stock			Accum. Other Comprehensive Income (Loss)			Retained Earnings			Non- Controlling Interests			Total


December 31, 2015	$	18		46,357		(36,780	)		(6,247	)		36,414			320			40,082
Net income (loss)												(3,615	)		56			(3,559	)
Other comprehensive income									54									54
Dividends paid ($1.00/share of common stock)												(1,253	)					(1,253	)
Repurchase of company common stock						(126	)											(126	)
Distributions to noncontrolling interests and other															(124	)		(124	)
Distributed under benefit plans				150														150
Other												2						2

December 31, 2016	$	18		46,507		(36,906	)		(6,193	)		31,548			252			35,226
Net income (loss)												(855	)		62			(793	)
Other comprehensive income									675									675
Dividends paid ($1.06/share of common stock)												(1,305	)					(1,305	)
Repurchase of company common stock						(3,000	)											(3,000	)
Distributions to noncontrolling interests and other															(120	)		(120	)
Distributed under benefit plans				115														115
Other												3						3

December 31, 2017	$	18		46,622		(39,906	)		(5,518	)		29,391			194			30,801
Net income												6,257			48			6,305
Other comprehensive loss									(603	)								(603	)
Dividends paid ($1.16/share of common stock)												(1,363	)					(1,363	)
Repurchase of company common stock						(2,999	)											(2,999	)
Distributions to noncontrolling interests and other															(121	)		(121	)
Distributed under benefit plans				257														257
Changes in Accounting Principles*									58			(278	)					(220	)
Other												3			4			7

December 31, 2018	$	18		46,879		(42,905	)		(6,063	)		34,010			125			32,064

*See Note 2—Changes in Accounting Principles for additional information.

See Notes to Consolidated Financial Statements.


Notes to Consolidated Financial Statements		ConocoPhillips

Note 1—Accounting Policies

∎

Consolidation Principles and Investments—Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries and variable interest entities where we are the primary beneficiary. The equity method is used to account for investments in affiliates in which we have the ability to exert significant influence over the affiliates’ operating and financial policies. When we do not have the ability to exert significant influence, the investment is measured at fair value except when the investment does not have a readily determinable fair value. For those exceptions, it will be measured at cost minus impairment, plus or minus observable price changes in orderly transactions for an identical or similar investment of the same issuer. Undivided interests in oil and gas joint ventures, pipelines, natural gas plants and terminals are consolidated on a proportionate basis. Other securities and investments are generally carried at cost.

We manage our operations through six operating segments, defined by geographic region: Alaska, Lower 48, Canada, Europe and North Africa, Asia Pacific and Middle East, and Other International. For additional information, see Note 25—Segment Disclosures and Related Information.

∎

Foreign Currency Translation—Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in accumulated other comprehensive income in common stockholders’ equity. Foreign currency transaction gains and losses are included in current earnings. Some of our foreign operations use their local currency as the functional currency.

∎	Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.

∎

Revenue Recognition—Revenues associated with the sales of crude oil, bitumen, natural gas, liquified natural gas (LNG), natural gas liquids and other items are recognized at the point in time when the customer obtains control of the asset. In evaluating when a customer has control of the asset, we primarily consider whether the transfer of legal title and physical delivery has occurred, whether the customer has significant risks and rewards of ownership, and whether the customer has accepted delivery and a right to payment exists. These products are typically sold at prevailing market prices. We allocate variable market-based consideration to deliveries (performance obligations) in the current period as that consideration relates specifically to our efforts to transfer control of current period deliveries to the customer and represents the amount we expect to be entitled to in exchange for the related products. Payment is typically due within 30 days or less.

Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale of inventory with the same counterparty are entered into “in contemplation” of one another, are combined and reported net (i.e., on the same income statement line).

∎

Shipping and Handling Costs—We typically incur shipping and handling costs prior to control transferring to the customer and account for these activities as fulfillment costs. Accordingly, we include shipping and handling costs in production and operating expenses for production activities. Transportation costs related to marketing activities are recorded in purchased commodities. Freight costs billed to customers are treated as a component of the transaction price and recorded as a component of revenue when the customer obtains control.

∎	Cash Equivalents—Cash equivalents are highly liquid, short-term investments that are readily convertible to known amounts of cash and have original maturities of 90 days or less from their date of purchase. They are carried at cost plus accrued interest, which approximates fair value.

∎	Short-Term Investments—Investments in bank time deposits and marketable securities (commercial paper and government obligations) with original maturities of greater than 90 days but less than one year are classified as short-term investments.

∎

Inventories—We have several valuation methods for our various types of inventories and consistently use the following methods for each type of inventory. Our commodity-related inventories are recorded at cost primarily using the last-in, first-out (LIFO) basis. We measure these inventories at the lower-of-cost-or-market in the aggregate. Any necessary lower-of-cost-or-market write-downs at year end are recorded as permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with current revenues. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location, but not unusual/nonrecurring costs or research and development costs. Materials, supplies and other miscellaneous inventories, such as tubular goods and well equipment, are valued using various methods, including the weighted-average-cost method, and the first-in, first-out (FIFO) method, consistent with industry practice.

∎

Fair Value Measurements—Assets and liabilities measured at fair value and required to be categorized within the fair value hierarchy are categorized into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or our assumptions about pricing by market participants.

∎	Derivative Instruments—Derivative instruments are recorded on the balance sheet at fair value. If the right of offset exists and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the balance sheet and the collateral payable or receivable is netted against derivative assets and derivative liabilities, respectively.

Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives not accounted for as hedges are recognized immediately in earnings.

∎	Oil and Gas Exploration and Development—Oil and gas exploration and development costs are accounted for using the successful efforts method of accounting.

Property Acquisition Costs—Oil and gas leasehold acquisition costs are capitalized and included in the balance sheet caption properties, plants and equipment (PP&E). Leasehold impairment is recognized based on exploratory experience and management’s judgment. Upon achievement of all conditions necessary for reserves to be classified as proved, the associated leasehold costs are reclassified to proved properties.

Exploratory Costs—Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or “suspended,” on the balance sheet pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the potential oil and gas field or while we seek government or co-venturer approval of development plans or seek environmental permitting. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas resources are designated as proved reserves.

Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as dry holes when it judges the potential field does not warrant further investment in the near term. See Note 8—Suspended Wells and Other Exploration Expenses, for additional information on suspended wells.

Development Costs—Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.

Depletion and Amortization—Leasehold costs of producing properties are depleted using the unit-of-production method based on estimated proved oil and gas reserves. Amortization of intangible development costs is based on the unit-of-production method using estimated proved developed oil and gas reserves.

∎	Capitalized Interest—Interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets.

∎

Depreciation and Amortization—Depreciation and amortization of PP&E on producing hydrocarbon properties and certain pipeline and LNG assets (those which are expected to have a declining utilization pattern), are determined by the unit-of-production method. Depreciation and amortization of all other PP&E are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units).

∎

Impairment of Properties, Plants and Equipment—PP&E used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group and annually in the fourth quarter following updates to corporate planning assumptions. If there is an indication the carrying amount of an asset may not be recovered, the asset is monitored by management through an established process where changes to significant assumptions such as prices, volumes and future development plans are reviewed. If, upon review, the sum of the undiscounted before-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value through additional amortization or depreciation provisions and reported as impairments in the periods in which the determination of the impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for exploration and production assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. Long-lived assets committed by management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell, with fair value determined using a binding negotiated price, if available, or present value of expected future cash flows as previously described.

The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, prices and costs, considering all available evidence at the date of review. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. Additionally, when probable and possible reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the impairment calculation.

∎

Impairment of Investments in Nonconsolidated Entities—Investments in nonconsolidated entities are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred and annually following updates to corporate planning assumptions. When such a condition is judgmentally determined to be other than temporary, the carrying value of the investment is written down to fair value. The fair value of the impaired investment is based on quoted market prices, if available, or upon the present value of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate.

∎	Maintenance and Repairs—Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.

∎

Property Dispositions—When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in the “Gain on dispositions” line of our consolidated income statement. When less than complete units of depreciable property are disposed of or retired which do not significantly alter the depreciation, depletion and amortization (DD&A) rate, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.

∎

Asset Retirement Obligations and Environmental Costs—The fair value of legal obligations to retire and remove long-lived assets are recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize this cost by increasing the carrying amount of the related PP&E. If, in subsequent periods, our estimate of this liability changes, we will record an adjustment to both the liability and PP&E. Over time the liability is increased for the change in its present value, and the capitalized cost in PP&E is depreciated over the useful life of the related asset. Reductions to estimated liabilities for assets that are no longer producing are recorded as a credit to impairment, if the asset had been previously impaired, or as a credit to DD&A, if the asset had not been previously impaired. For additional information, see Note 10—Asset Retirement Obligations and Accrued Environmental Costs.

Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures relating to an existing condition caused by past operations, and those having no future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless acquired in a purchase business combination, which we record on a discounted basis) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is probable and estimable.

∎

Guarantees—The fair value of a guarantee is determined and recorded as a liability at the time the guarantee is given. The initial liability is subsequently reduced as we are released from exposure under the guarantee. We amortize the guarantee liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is indefinite, we reverse the liability when we have information indicating the liability is essentially relieved or amortize it over an appropriate time period as the fair value of our guarantee exposure declines over time. We amortize the guarantee liability to the related income statement line item based on the nature of the guarantee. When it becomes probable that we will have to perform on a guarantee, we accrue a separate liability if it is reasonably estimable, based on the facts and circumstances at that time. We reverse the fair value liability only when there is no further exposure under the guarantee.

∎

Share-Based Compensation—We recognize share-based compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the award) or the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement. We have elected to recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.

∎

Income Taxes—Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial reporting basis and the tax basis of our assets and liabilities, except for deferred taxes on income and temporary differences related to the cumulative translation adjustment considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures. Allowable tax credits are applied currently as reductions of the provision for income taxes. Interest related to unrecognized tax benefits is reflected in interest and debt expense, and penalties related to unrecognized tax benefits are reflected in production and operating expenses.

∎	Taxes Collected from Customers and Remitted to Governmental Authorities—Sales and value-added taxes are recorded net.

∎

Net Income (Loss) Per Share of Common Stock—Basic net income (loss) per share of common stock is calculated based upon the daily weighted-average number of common shares outstanding during the year. Also, this calculation includes fully vested stock and unit awards that have not yet been issued as common stock, along with an adjustment to net income (loss) for dividend equivalents paid on unvested unit awards that are considered participating securities. Diluted net income per share of common stock includes unvested stock, unit or option awards granted under our compensation plans and vested but unexercised stock options, but only to the extent these instruments dilute net income per share, primarily under the treasury-stock method. Diluted net loss per share, which is calculated the same as basic net loss per share, does not assume conversion or exercise of securities that would have an antidilutive effect. Treasury stock is excluded from the daily weighted-average number of common shares outstanding in both calculations. The earnings per share impact of the participating securities is immaterial.

Note 2—Changes in Accounting Principles

We adopted the provisions of Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers,” and its amendments issued by the provisions of ASU No. 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” ASU No. 2016-10, “Identifying Performance Obligations and Licensing,” ASU No. 2016-12, “Narrow-Scope Improvements and Practical Expedients,” and ASU No. 2016-20, “Technical Corrections and Improvements to Topic 606, Revenue From Contracts with Customers,” collectively Accounting Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers,” (ASC Topic 606) beginning January 1, 2018. ASC Topic 606 outlines a single comprehensive model for an entity to use in accounting for revenue arising from all contracts with customers except where revenues are in scope of another accounting standard. The ASU superseded the revenue recognition requirements in ASC Topic 605, “Revenue Recognition,” and most industry-specific guidance. ASC Topic 606 sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity is 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 and services. ASC Topic 606 also requires certain additional revenue-related disclosures. The adoption of ASC Topic 606 did not have a material impact on our consolidated financial statements. See Note 24—Sales and Other Operating Revenues for additional information related to this ASC.

We adopted the provisions of FASB ASU No. 2016-01, “Recognition and Measurement of Financial Assets and Liabilities,” (ASU No. 2016-01) beginning January 1, 2018. The ASU, among other things, requires an entity to record the changes in fair value of equity investments, other than investments accounted for using the equity method, within net income. Under this ASU, an entity is no longer able to recognize unrealized holding gains and losses on equity securities in other comprehensive income and instead must recognize them in the income statement. See Note 7—Investment in Cenovus Energy and Note 20—Accumulated Other Comprehensive Loss for additional information relating to this ASU.

The cumulative effect of the changes made to our consolidated balance sheet at January 1, 2018, for the adoption of ASC Topic 606 and ASU No. 2016-01 were as follows:


	Millions of Dollars
	December 31 2017			ASC Topic 606 Adjustments			ASU No. 2016-01 Adjustments			January 1 2018

Liabilities
Other accruals	$	1,029			104			-			1,133
Total current liabilities		9,397			104			-			9,501
Deferred income taxes		5,282			(31	)		-			5,251
Other liabilities and deferred credits		1,269			147			-			1,416
Total liabilities		42,561			220			-			42,781


Equity
Accumulated other comprehensive loss	$	(5,518	)		-			58			(5,460	)
Retained earnings		29,391			(220	)		(58	)		29,113
Total common stockholders’ equity		30,607			(220	)		-			30,387
Total equity		30,801			(220	)		-			30,581

For discussion of adjustments for ASU No. 2016-01 and ASC Topic 606, see Note 7—Investment in Cenovus Energy and Note 24—Sales and Other Operating Revenues, respectively.

We adopted the provisions of FASB ASU No. 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost,” beginning January 1, 2018. We retrospectively applied the presentation of service cost separate from the other components of net periodic costs. The interest cost, expected return on plan assets, amortization of prior service cost/credit, recognized net actuarial loss/gain, settlement expense, curtailment loss/gain, and special termination benefits have been reclassified from the “Production and operating expenses,” “Selling, general and administrative expenses,” and “Exploration expenses” lines to the “Other expenses” line on our consolidated income statement. We elected to apply the practical expedient which allows us to reclassify amounts disclosed previously in the employee benefit plans footnote as the basis for applying retrospective presentation for prior comparative periods as it is impracticable to determine the disaggregation of the cost components for amounts capitalized and amortized in those periods. On a prospective basis, the other components of net periodic benefit costs will not be included in amounts capitalized in inventory or PP&E.

The effect of the retrospective presentation change related to the net periodic benefit cost of our defined benefit pension and other postretirement employee benefits plans on our consolidated income statement was as follows:


	Millions of Dollars
	Previously Reported		Effect of Change Higher/(Lower)			As Revised

Year Ended December 31, 2017
Production and operating expenses	$	5,173		(11	)		5,162
Selling, general and administrative expenses		561		(134	)		427
Exploration expenses		938		(4	)		934
Other expenses		302		149			451


Year Ended December 31, 2016
Production and operating expenses	$	5,667		(24	)		5,643
Selling, general and administrative expenses		723		(250	)		473
Exploration expenses		1,915		(3	)		1,912
Other expenses		-		277			277

We adopted the provisions of FASB ASU No. 2016-15, “Classification of Certain Cash Receipts and Cash Payments,” beginning January 1, 2018. This ASU clarifies how certain cash receipts and cash payments should be classified and presented in the statement of cash flows. We have made an accounting policy election to classify distributions received from equity method investees using the nature of the distribution approach which classifies distributions received from investees as either cash inflows from operating activities or cash inflows from investing activities in the statement of cash flows based on the nature of the activities of the investee that generated the distribution. The impact of adopting this ASU was not material to prior presented periods.

We adopted the provisions of FASB ASU No. 2016-18, “Restricted Cash,” beginning January 1, 2018. This ASU requires amounts deemed restricted cash to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows, and presentation should permit a reconciliation when cash, cash equivalents and restricted cash are presented in more than one line item on the balance sheet. We have amounts deposited in statutory bank accounts in certain countries to satisfy asset retirement obligations (ARO). These amounts are deemed restricted cash and are included in the “Other assets” line of our consolidated balance sheet. This standard is required to be applied retrospectively to all periods presented, but the impact in those periods was not material.

Note 3—Variable Interest Entities (VIEs)

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

Australia Pacific LNG Pty Ltd (APLNG)

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

As of December 31, 2018, 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 6—Investments, Loans and Long-Term Receivables, and Note 12—Guarantees, for additional information.

Marine Well Containment Company, LLC (MWCC)

MWCC provides well containment equipment and technology and related services in the deepwater U.S. Gulf of Mexico. Its principal activities involve the development and maintenance of rapid-response hydrocarbon well containment systems that are deployable in the Gulf of Mexico on a call-out basis. We have a 10 percent ownership interest in MWCC, and it is accounted for as an equity method investment because MWCC is a limited liability company in which we are a Founding Member and exercise significant influence through our permanent seat on the ten-member Executive Committee responsible for overseeing the affairs of MWCC. In 2016, MWCC executed a $154 million term loan financing arrangement with an external financial institution whose terms required the financing be secured by letters of credit provided by certain owners of MWCC, including ConocoPhillips. In connection with the financing transaction, we issued a letter of credit of $22 million which can be drawn upon in the event of a default by MWCC on its obligation to repay the proceeds of the term loan. The fair value of this letter of credit is immaterial and not recognized on our consolidated balance sheet. MWCC is considered a VIE, as it has entered into arrangements that provide it with additional forms of subordinated financial support. We are not the primary beneficiary and do not consolidate MWCC because we share the power to govern the business and operation of the company and to undertake certain obligations that most significantly impact its economic performance with nine other unaffiliated owners of MWCC.

At December 31, 2018, the book value of our equity method investment in MWCC was $130 million. We have not provided any financial support to MWCC other than amounts previously contractually required. Unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of MWCC.

Note 4—Inventories

Inventories at December 31 were:


	Millions of Dollars

		2018	2017


Crude oil and natural gas	$	432	512
Materials and supplies		575	548

	$	1,007	1,060

Inventories valued on the LIFO basis totaled $292 million and $341 million at December 31, 2018 and 2017, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was approximately $75 million and $124 million at December 31, 2018 and December 31, 2017, respectively. In 2018, liquidation of LIFO inventory values decreased the net income attributable to ConocoPhillips by $6 million.

Note 5—Assets Held for Sale, Sold or Acquired and Other Planned Dispositions

Assets Held for Sale

In 2018, we signed a definitive agreement to sell an office building for $90 million, and the held for sale criteria were met in the fourth quarter of 2018. As of December 31, 2018, the building had a carrying value of $90 million which we reclassified to “Prepaid expenses and other current assets” on our consolidated balance sheet. The transaction closed in January 2019. The building is included in our Corporate and other segment.

2018

Assets Sold

All gains or losses on asset dispositions are reported before-tax and are included net in the “Gain on dispositions” line on our consolidated income statement. All cash proceeds are included in the “Cash Flows From Investing Activities” section of our consolidated statement of cash flows.

In the first quarter of 2018, we completed the sale of certain properties in the Lower 48 segment for net proceeds of $112 million. No gain or loss was recognized on the sale. In the second quarter of 2018, we completed the sale of a package of largely undeveloped acreage in the Lower 48 segment for net proceeds of $105 million and no gain or loss was recognized on the sale. In the third quarter of 2018, we completed a noncash exchange of undeveloped acreage in the Lower 48 segment. The transaction was recorded at fair value resulting in the recognition of a $56 million gain. In the fourth quarter of 2018, we sold several packages of undeveloped acreage in the Lower 48 segment for total net proceeds of $162 million and recognized gains of approximately $140 million.

On October 31, 2018, we completed the sale of our interests in the Barnett to Lime Rock Resources for $196 million after customary adjustments and recognized a loss of $5 million. We recorded impairments of $87 million in 2018 and $572 million in 2017 to reduce the net carrying value of the Barnett to fair value. At the time of the disposition, our interest in Barnett had a net carrying value of $201 million, consisting

of $250 million of PP&E and $49 million of AROs. The before-tax losses associated with our interests in the Barnett, including both the impairments and loss on disposition noted above, were $59 million, $566 million and $66 million for the years ended December 31, 2018, 2017 and 2016, respectively. The Barnett results of operations are included in our Lower 48 segment.

On December 18, 2018, we completed the sale of a ConocoPhillips subsidiary to BP. The subsidiary held a 16.5 percent interest in the BP-operated Clair Field in the United Kingdom. We retained a 7.5 percent interest in the field. At the same time, we acquired BP’s 39.2 percent nonoperated interest in the Greater Kuparuk Area in Alaska, including their 38 percent interest in the Kuparuk Transportation Company (Kuparuk Assets). The transaction was recorded at a fair value of $1,743 million and was cash neutral except for customary adjustments which resulted in net proceeds of $253 million. At closing, our 16.5 percent interest in the Clair Field had a net carrying value of approximately $1,028 million consisting primarily of $1,553 million of PP&E, $485 million of deferred tax liabilities, and $59 million of AROs. We recognized a before-tax gain of $715 million on the transaction. The 2018 before-tax earnings associated with our 16.5 percent interest in the Clair Field, including the recognized gain, were $748 million. The before-tax losses associated with our 16.5 percent interest in the Clair Field were $0.4 million and $8 million for the years ended December 31, 2017 and 2016, respectively. Results of operations for our interest in the Clair Field are reported within our Europe and North Africa segment and the Kuparuk Assets are included in our Alaska segment.

Other Planned Dispositions

In the fourth quarter of 2018, we entered into an agreement to sell our 30 percent interest in Greater Sunrise Fields to the government of Timor-Leste for $350 million, subject to customary adjustments. The transaction is conditional on the funding approval from the Timor-Leste government as well as regulatory approvals. The Greater Sunrise Fields are included in our Asia Pacific and Middle East segment.

In January 2019, we entered into agreements to sell our 12.4 percent ownership interests in the Golden Pass LNG Terminal and Golden Pass Pipeline located adjacent to the Sabine-Neches Industrial Ship Channel northwest of Sabine Pass, Texas. The terminal and pipeline capacity are used for receipt, storage and regasification of LNG purchased from Qatar Liquefied Gas Company Limited (QG3) and transportation of the regasified natural gas. As a result of entering into these agreements, we expect to recognize a loss of approximately $60 million in the first quarter of 2019. We have also entered into agreements to amend our contractual obligations for retaining use of the facilities. Completion of the sale is subject to regulatory approval.

Acquisitions

In May 2018, we completed the acquisition of Anadarko’s 22 percent nonoperated interest in the Western North Slope of Alaska, as well as its interest in the Alpine Transportation Pipeline for $386 million, after customary adjustments. This transaction was accounted for as a business combination resulting in the recognition of approximately $297 million of proved property and $114 million of unproved property within PP&E, $20 million of inventory, $14 million of investments, and $59 million of AROs. These assets are included in our Alaska segment.

As discussed in the Clair Field transaction with BP above, we acquired BP’s Kuparuk Assets on December 18, 2018. The transaction was accounted for as an asset acquisition with a net acquisition cost of $1,490 million, comprised of the fair value of $1,743 million associated with the disposed 16.5 percent interest in the Clair Field, reduced by the net proceeds of $253 million. Accordingly, we recorded approximately $1.9 billion to proved property within PP&E, $42 million to inventory, $15 million to investments, $374 million of asset retirement obligations, and a $100 million decrease to net working capital. The Kuparuk Assets are included in our Alaska segment.

2017

On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the Foster Creek Christina Lake (FCCL) Partnership, as well as the majority of our western Canada gas assets to Cenovus Energy. Consideration for the transaction was $11.0 billion in cash after customary adjustments, 208 million Cenovus Energy common shares and a five-year uncapped contingent payment. The value of the shares at closing was

$1.96 billion based on a price of $9.41 per share on the New York Stock Exchange. The contingent payment, calculated and paid on a quarterly basis, is $6 million Canadian dollars (CAD) for every $1 CAD by which the Western Canada Select (WCS) quarterly average crude price exceeds $52 CAD per barrel. Contingent payments received during the five-year period are reflected as “Gain on dispositions” on our consolidated income statement. We reported before-tax equity earnings associated with FCCL of $197 million and $89 million for the years ended December 31, 2017 and 2016, respectively. We reported before-tax losses of $26 million and $572 million for the western Canada gas producing properties for the same periods, respectively. In 2018, we recorded a gain on dispositions for these contingent payments of $95 million.

At closing, the carrying value of our equity investment in FCCL was $8.9 billion. The carrying value of our interest in the western Canada gas assets was $1.9 billion consisting primarily of $2.6 billion of PP&E, partly offset by AROs of $585 million and approximately $100 million of environmental and other accruals. A gain of $2.1 billion was included in the “Gain on dispositions” line on our consolidated income statement in 2017. Both FCCL and the western Canada gas assets were reported in our Canada segment.

For more information on the Canada disposition and our investment in Cenovus Energy see Note 7—Investment in Cenovus Energy, Note 15—Fair Value Measurement, and Note 20—Accumulated Other Comprehensive Loss.

In July 2017, we completed the sale of our interests in the San Juan Basin to an affiliate of Hilcorp Energy Company for $2.5 billion in cash after customary adjustments and recognized a loss on disposition of $22 million. The transaction includes a contingent payment of up to $300 million. The six-year contingent payment, effective beginning January 1, 2018, is due annually for the periods in which the monthly U.S. Henry Hub price is at or above $3.20 per million British thermal units. In 2018, we recorded a gain on dispositions for these contingent payments of $28 million. In the second quarter of 2017, we recorded an impairment of $3.3 billion to reduce the carrying value of our interests in the San Juan Basin to fair value. At the time of disposition, the San Juan Basin interests had a net carrying value of approximately $2.5 billion, consisting of $2.9 billion of PP&E and $406 million of liabilities, primarily AROs. The before-tax losses associated with our interests in the San Juan Basin, including both the $3.3 billion impairment and $22 million loss on disposition noted above, were $3.2 billion and $239 million for the years ended December 31, 2017 and 2016, respectively. The San Juan Basin results were reported in our Lower 48 segment.

In September 2017, we completed the sale of our interest in the Panhandle assets for $178 million in cash after customary adjustments, and recognized a loss on disposition of $28 million. At the time of the disposition, the carrying value of our interest was $206 million, consisting primarily of $279 million of PP&E and $72 million of AROs. Including the $28 million loss on disposition noted above, we reported before-tax losses for the Panhandle properties of $14 million and $21 million for the years ended December 31, 2017 and 2016, respectively. The Panhandle results were reported in our Lower 48 segment.

2016

In April 2016, we sold our interest in the Alaska Beluga River Unit natural gas field in the Cook Inlet for $134 million, net of settlement of gas imbalances and customary adjustments, and recognized a gain on disposition of $56 million. At the time of disposition, the net carrying value of our Beluga River Unit interest, which was included in the Alaska segment, was $78 million, consisting primarily of $100 million of PP&E and $19 million of AROs.

In October 2016, we completed an asset exchange with Bonavista Energy in which we gave up approximately 141,000 net acres of noncore developed properties in central Alberta in exchange for approximately 40,000 net acres of primarily undeveloped properties in northeast British Columbia. The fair value of the transaction was determined to be approximately $69 million and an impairment of $57 million was recognized in the third quarter of 2016 when the assets were considered held for sale, to reduce the carrying value to fair value. A loss on disposition of approximately $1 million was recognized upon completion of the transaction. The divested properties were included in the Canada segment.

Also in October 2016, we sold ConocoPhillips Senegal B.V., the entity that held our 35 percent interest in three exploration blocks offshore Senegal for $442 million and recognized a gain on disposition of $146 million. At the time of disposition, the carrying value of our interest was $286 million, which was primarily PP&E. Senegal results of operations were reported within our Other International segment.

In November 2016, we completed the sale of our 40 percent interest in South Natuna Sea Block B for $225 million and recognized a loss on disposition of $26 million. Our interest in Block B was included in the Asia Pacific and Middle East segment. In 2016, we recognized an impairment of $42 million at the time it was considered held for sale to reduce the carrying value to fair value. At the time of the disposition, the carrying value of our interest was approximately $251 million, which included primarily $154 million of PP&E, $178 million of accounts receivable, $25 million of inventory, $54 million of deferred tax assets, $130 million of accounts payable and other accruals, and $38 million of employee benefit obligations.

In December 2016, we completed the sale of certain mineral and non-mineral fee lands in northeastern Minnesota, which were included in the Lower 48 segment, for $148 million and recorded a gain on disposition of $4 million. The majority of the assets sold were acquired during the fourth quarter of 2016 as a result of ConocoPhillips holding a reversionary interest in the Greater Northern Iron Ore Properties Trust (the Trust), a grantor trust that owned mineral and surface interests in the Mesabi Iron Range in northeastern Minnesota and certain other personal property. Pursuant to the terms of the Trust Agreement, the Trust terminated on April 6, 2015. In November 2016, upon completion of the wind-down period, documents memorializing ConocoPhillips’ ownership of certain Trust property, including all of the Trust’s mineral properties and active leases, were delivered to us and we recognized the fair value of the net assets resulting in a gain of $88 million recorded in the “Other income” line on our consolidated income statement. At the time of the disposition, the carrying value of our interests, which included the assets obtained from the Trust, consisted of $144 million of PP&E.

Note 6—Investments, Loans and Long-Term Receivables

Components of investments, loans and long-term receivables at December 31 were:


	Millions of Dollars

	2018		2017


Equity investments	$	9,005		9,129
Loans and advances—related parties		335		461
Long-term receivables		238		375
Other investments		86		95

	$	9,664		10,060

Equity Investments

Affiliated companies in which we had a significant equity investment at December 31, 2018, included:

	•		APLNG—37.5 percent owned joint venture with Origin Energy (37.5 percent) and Sinopec (25 percent)—to develop coalbed methane production from the Bowen and Surat basins in Queensland, Australia, as well as process and export LNG.

	•		Qatar Liquefied Gas Company Limited (3) (QG3)—30 percent owned joint venture with affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent)—produces and liquefies natural gas from Qatar’s North Field, as well as exports LNG.

Summarized 100 percent earnings information for equity method investments in affiliated companies, combined, was as follows:


		Millions of Dollars

		2018	2017		2016


Revenues	$	11,654	11,554		10,149
Income (loss) before income taxes		3,660	(2,875	)	660
Net income (loss)		3,244	(1,431	)	799

Summarized 100 percent balance sheet information for equity method investments in affiliated companies, combined, was as follows:


		Millions of Dollars

		2018	2017


Current assets	$	3,285	2,920
Noncurrent assets		41,563	42,693
Current liabilities		2,625	2,453
Noncurrent liabilities		23,874	25,522

Our share of income taxes incurred directly by an equity company is reported in equity in earnings of affiliates, and as such is not included in income taxes on our consolidated financial statements.

At December 31, 2018, retained earnings included $27 million related to the undistributed earnings of affiliated companies. Dividends received from affiliates were $1,226 million, $605 million and $398 million in 2018, 2017 and 2016, respectively.

APLNG

APLNG is focused on coalbed methane production from the Bowen and Surat basins in Queensland, Australia, to supply the domestic gas market and on LNG processing and export sales. Our investment in APLNG gives us access to coalbed methane resources in Australia and enhances our LNG position. The majority of APLNG LNG is sold under two long-term sales and purchase agreements, supplemented with sales of additional LNG spot cargoes targeting the Asia Pacific markets. Origin Energy, an integrated Australian energy company, is the operator of APLNG’s production and pipeline system, while we operate the LNG facility.

APLNG executed project financing agreements for an $8.5 billion project finance facility in 2012. The $8.5 billion project finance facility was initially composed 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 December 31, 2018, all amounts have been drawn from the facility. APLNG made its first principal and interest repayment in March 2017 and is scheduled to make bi-annual payments until March 2029.

APLNG made a voluntary repayment of $1.4 billion to the Export-Import Bank of China in September 2018. At the same time, APLNG obtained a United States Private Placement (USPP) bond facility of $1.4 billion. Interest payments are scheduled to commence in March 2019 and principal payments in September 2023, with bi-annual payments due on the facility until September 2030. At December 31, 2018, a balance of $7.2 billion was outstanding on the facilities.

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. In October 2016, we reached financial completion for Train 1, which reduced our associated guarantee by 60 percent. In August 2017, we reached financial completion for both trains, which removed the remaining guarantee.

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. See Note 3—Variable Interest Entities (VIEs) for additional information.

On July 1, 2016, APLNG changed its tax functional currency from Australian dollar to U.S. dollar and translated all APLNG assets and liabilities into U.S. dollar, utilizing the exchange rate as of that date. As a result of this change, we recorded a reduction to our investment in APLNG for the deferred tax effect of $174 million in the “Equity in earnings of affiliates” line of our consolidated income statement.

During the first half of 2017, the outlook for crude oil prices deteriorated, and as a result of significantly reduced price outlooks, the estimated fair value of our investment in APLNG declined to an amount below carrying value. Based on a review of the facts and circumstances surrounding this decline in fair value, we concluded in the second quarter of 2017 the impairment was other than temporary under the guidance of FASB ASC Topic 323, “Investments—Equity Method and Joint Ventures,” and the recognition of an impairment of our investment to fair value was necessary. Accordingly, we recorded a noncash $2,384 million, before- and after-tax impairment in our second-quarter 2017 results. Fair value was estimated based on an internal discounted cash flow model using estimated future production, an outlook of future prices from a combination of exchanges (short-term) and pricing service companies (long-term), costs, a market outlook of foreign exchange rates provided by a third party, and a discount rate believed to be consistent with those used by principal market participants. The impairment was included in the “Impairments” line on our consolidated income statement.

At December 31, 2018, the carrying value of our equity method investment in APLNG was $7,522 million. The historical cost basis of our 37.5 percent share of net assets on the books of APLNG was $7,231 million, resulting in a basis difference of $291 million on our books. The basis difference, which is substantially all associated with PP&E and subject to amortization, has been allocated on a relative fair value basis to individual exploration and production license areas owned by APLNG, some of which are not currently in production. Any future additional payments are expected to be allocated in a similar manner. Each exploration license area will periodically be reviewed for any indicators of potential impairment, which, if required, would result in acceleration of basis difference amortization. As the joint venture produces natural gas from each license, we amortize the basis difference allocated to that license using the unit-of-production method. Included in net income (loss) attributable to ConocoPhillips for 2018, 2017 and 2016 was after-tax expense of $44 million, $100 million and $92 million, respectively, representing the amortization of this basis difference on currently producing licenses.

Distributions from APLNG commenced in April 2018.

FCCL

FCCL Partnership, a Canadian upstream 50/50 general partnership with Cenovus Energy Inc., produces bitumen in the Athabasca oil sands in northeastern Alberta and sells the bitumen blend. Cenovus is the operator and managing partner of FCCL.

On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets to Cenovus Energy. Financial information presented within this footnote includes our historical interest up to the date of sale. For additional information on the Canada disposition and our investment in Cenovus Energy, see Note 5—Assets Held for Sale, Sold or Acquired and Other Planned Dispositions and Note 7—Investment in Cenovus Energy.

QG3

QG3 is a joint venture that owns an integrated large-scale LNG project located in Qatar. We provided project financing, with a current outstanding balance of $461 million as described below under “Loans and Long-Term Receivables.” At December 31, 2018, the book value of our equity method investment in QG3, excluding the project financing, was $921 million. We have terminal and pipeline use agreements with Golden Pass LNG Terminal and affiliated Golden Pass Pipeline near Sabine Pass, Texas, in which we have a 12.4 percent interest, intended to provide us with terminal and pipeline capacity for the receipt, storage and regasification of LNG purchased from QG3. However, currently the LNG from QG3 is being sold to markets outside of the United States. In January 2019, we entered into agreements to sell our ownership interests in Golden Pass LNG Terminal and Golden Pass Pipeline. For additional information, see Note 5—Assets Held for Sale, Sold or Acquired and Other Planned Dispositions.

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 and long-term receivables to certain affiliated and non-affiliated companies. Loans are recorded when cash is transferred or seller financing is provided to the affiliated or non-affiliated company pursuant to a loan agreement. The loan balance will increase as interest is earned on the outstanding loan balance and will decrease as interest and principal payments are received. Interest is earned at the loan agreement’s stated interest rate. Loans and long-term receivables are assessed for impairment when events indicate the loan balance may not be fully recovered.

At December 31, 2018, significant loans to affiliated companies include $461 million in project financing to QG3. We own a 30 percent interest in QG3, for which we use the equity method of accounting. The other participants in the project are affiliates of Qatar Petroleum and Mitsui. QG3 secured project financing of $4.0 billion in December 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA and commercial bank facilities. On December 15, 2011, QG3 achieved financial completion and all project loan facilities became nonrecourse to the project participants. Semi-annual repayments began in January 2011 and will extend through July 2022.

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 7—Investment in Cenovus Energy

On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets, to Cenovus Energy. Consideration for the transaction included 208 million Cenovus Energy common shares, which approximated 16.9 percent of issued and outstanding Cenovus Energy common stock at closing. See Note 5—Assets Held for Sale, Sold or Acquired and Other Planned Dispositions for additional information on the Canada disposition. At closing of the sale, the fair value and cost basis of our investment in 208 million Cenovus Energy common shares was $1.96 billion based on a price of $9.41 per share on the New York Stock Exchange.

We adopted the provisions of ASU No. 2016-01, beginning January 1, 2018, using the cumulative-effect approach. Results for reporting periods beginning January 1, 2018, are presented under ASU No. 2016-01 with all changes in the fair value of our equity securities reflected within the “Other income” line of our consolidated income statement and within the “Other” line in the “Cash Flows From Operating Activities” section of our consolidated statement of cash flows. Prior period amounts are not adjusted under the cumulative-effect method of adopting ASU No. 2016-01. See Note 2—Changes in Accounting Principles and Note 20—Accumulated Other Comprehensive Loss for the effect on our consolidated balance sheet and the line items that have been impacted by the adoption of this standard.

The cumulative effect of applying the standard was the reclassification of accumulated unrealized holding losses of $58 million, recognized in 2017, related to our investment in Cenovus Energy from accumulated other comprehensive loss to retained earnings.

Our investment is carried at fair value of $1.46 billion as of December 31, 2018, reflecting the closing price of Cenovus Energy shares on the New York Stock Exchange of $7.03 per share, a decrease from its fair value of $1.90 billion at year-end 2017. For the year ended December 31, 2018, we recorded a before-tax unrealized loss of $437 million, related to the shares held at the reporting date. See Note 15—Fair Value Measurement, for additional information. Subject to market conditions, we intend to decrease our investment over time through market transactions, private agreements or otherwise.

Note 8—Suspended Wells and Other Exploration Expenses

The following table reflects the net changes in suspended exploratory well costs during 2018, 2017 and 2016:


		Millions of Dollars

		2018	2017	2016


Beginning balance at January 1	$	853	1,063	1,260
Additions pending the determination of proved reserves		140	118	225
Reclassifications to proved properties		(37)	(66)	(27)
Sales of suspended wells		(93)	-	(247)
Charged to dry hole expense		(7)	(262)	(148)

Ending balance at December 31	$	856	853	1,063


The following table provides an aging of suspended well balances at December 31:
	Millions of Dollars

		2018	2017	2016


Exploratory well costs capitalized for a period of one year or less	$	145	67	132
Exploratory well costs capitalized for a period greater than one year		711	786	931

Ending balance	$	856	853	1,063

Number of projects with exploratory well costs capitalized for a period greater than one year		24	23	26

The following table provides a further aging of those exploratory well costs that have been capitalized for more than one year since the completion of drilling as of December 31, 2018:


		Millions of Dollars

			Suspended Since

		Total	2015–2017	2012–2014	2004–2011


Greater Poseidon—Australia(2)		177	-	165	12
Barossa/Caldita—Australia(2)		136	59	-	77
Surmont—Canada(1)		108	18	56	34
NPRA—Alaska(1)		77	39	38	-
Middle Magdalena Basin—Colombia(1)		65	65	-	-
Greater Clair—UK(2)		42	8	30	4
Bohai—China(2)		19	19	-	-
Kamunsu East—Malaysia(2)		19	-	19	-
NC 98—Libya(2)		15	-	11	4
Sunrise—Australia(2)		13	-	-	13
Other of $10 million or less each(1)(2)		40	5	18	17

Total	$	711	213	337	161

(1)Additional appraisal wells planned.

(2)Appraisal drilling complete; costs being incurred to assess development.

In July 2016, we entered into an agreement to terminate our final Gulf of Mexico deepwater drillship contract. The drillship, used to drill our operated deepwater well inventory in the Gulf of Mexico through April 2016, was contracted on a shared, three-year term. Accordingly, we recorded before-tax rig cancellation charges and third-party costs of $146 million in our Lower 48 segment in 2016.

In February 2017, we reached a settlement agreement on our contract for the Athena drilling rig, initially secured for our four-well commitment program in Angola. As a result of the cancellation, we recognized a before-tax charge of $43 million net in the first quarter of 2017. These charges are included in the “Exploration expenses” line on our consolidated income statement and in our Other International segment in 2017.

Note 9—Impairments

During 2018, 2017 and 2016, we recognized the following before-tax impairment charges:


		Millions of Dollars

		2018		2017	2016


Alaska	$	20		180	1
Lower 48		63		3,969	149
Canada		9		22	88
Europe and North Africa		(79	)	46	(160	)
Asia Pacific and Middle East		14		2,384	44
Corporate		-		-	17

	$	27		6,601	139

2018

In Alaska, we recorded impairments of $20 million primarily due to cancelled projects.

In the Lower 48, we recorded impairments of $63 million, primarily related to developed properties in our Barnett asset which were written down to fair value less costs to sell, partly offset by a revision to reflect finalized proceeds on a separate transaction.

In our Europe and North Africa segment, we recorded a credit to impairment of $79 million, primarily due to decreased ARO estimates on fields in the United Kingdom which have ceased production and were impaired in prior years, partly offset by an increased ARO estimate on a field in Norway which has ceased production.

2017

In Alaska, we recorded impairments of $180 million primarily for the associated PP&E carrying value of our small interest in the Point Thomson unit.

In the Lower 48, we recorded impairments of $3,969 million primarily due to certain developed properties which were written down to fair value less costs to sell. See Note 5—Assets Held for Sale, Sold or Acquired and Other Planned Dispositions, for additional information on our dispositions.

In Canada, we recorded impairments of $22 million primarily due to cancelled projects.

In Europe and North Africa, we recorded impairments of $46 million primarily due to reduced volume forecasts for a field in the United Kingdom and restructured ownership and a change in commercial premises for a gas processing plant in Norway, partly offset by decreased ARO estimates on fields at or nearing the end of life which were impaired in prior years.

In Asia Pacific and Middle East, we recorded impairments of $2,384 million, including the impairment of our APLNG investment. For more information, see the “APLNG” section of Note 6—Investments, Loans and Long-Term Receivables.

The charges discussed below, within this section, are included in the “Exploration expenses” line on our consolidated income statement and are not reflected in the table above.

In our Lower 48 segment, we recorded a before-tax impairment of $51 million for the associated carrying value of capitalized undeveloped leasehold costs of Shenandoah in deepwater Gulf of Mexico following the suspension of appraisal activity by the operator. Additionally, we recorded a $38 million before-tax impairment for mineral assets primarily due to plan of development changes.

2016

In the Lower 48, we recorded impairments of $149 million primarily due to cancelled projects associated with plan of development changes for Eagle Ford infrastructure, as well as lower natural gas prices and increased ARO estimates.

In Canada, we recorded impairments of $88 million mainly due to plan of development changes, as well as certain developed properties being written down to fair value less costs to sell.

In Europe and North Africa, we recorded a credit to impairment of $160 million, primarily in the United Kingdom, due to decreased ARO estimates on fields at or nearing the end of life which were impaired in prior years, partly offset by asset impairments due to lower natural gas prices in the United Kingdom.

In Asia Pacific and Middle East, we recorded impairments of $44 million, mainly due to a write-down to fair value less costs to sell of our developed properties in Block B, offshore Indonesia, in the third quarter of 2016.

In Corporate and Other, we recorded impairments of $17 million due to cancelled projects in our Houston and Bartlesville offices.

The charges discussed below, within this section, are included in the “Exploration expenses” line on our consolidated income statement and are not reflected in the table above.

Charges recorded in exploration expenses in 2016 were related to our decision announced in 2015 to reduce deepwater exploration spending.

In our Lower 48 segment, we recorded a $203 million before-tax impairment for the associated carrying value of our Gibson and Tiber undeveloped leaseholds in deepwater Gulf of Mexico. Additionally, we recorded a $95 million before-tax impairment for the associated carrying value of capitalized undeveloped leasehold costs of the Melmar prospect and a $79 million before-tax impairment, primarily as a result of changes in the estimated market value following the completion of marketing efforts.

In our Canada segment, we recorded before-tax unproved property impairments of $31 million, primarily due to decisions to discontinue additional testing of undeveloped leaseholds.

Note 10—Asset Retirement Obligations and Accrued Environmental Costs

Asset retirement obligations and accrued environmental costs at December 31 were:


		Millions of Dollars

		2018		2017


Asset retirement obligations	$	7,908		7,798
Accrued environmental costs		178		180

Total asset retirement obligations and accrued environmental costs		8,086		7,978
Asset retirement obligations and accrued environmental costs due within one year*		(398	)	(347	)

Long-term asset retirement obligations and accrued environmental costs	$	7,688		7,631

*Classified as a current liability on the balance sheet under “Other accruals.”

Asset Retirement Obligations

We record the fair value of a liability for an ARO when it is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize the associated asset retirement cost by increasing the carrying amount of the related PP&E. If, in subsequent periods, our estimate of this liability changes, we will record an adjustment to both the liability and PP&E. Over time, the liability increases for the change in its present value, while the capitalized cost depreciates over the useful life of the related asset.

We have numerous AROs we are required to perform under law or contract once an asset is permanently taken out of service. Most of these obligations are not expected to be paid until several years, or decades, in the future and will be funded from general company resources at the time of removal. Our largest individual obligations involve plugging and abandonment of wells and removal and disposal of offshore oil and gas platforms around the world, as well as oil and gas production facilities and pipelines in Alaska.

During 2018 and 2017, our overall ARO changed as follows:


		Millions of Dollars

		2018		2017


Balance at January 1	$	7,798		8,405
Accretion of discount		348		358
New obligations		657		113
Changes in estimates of existing obligations		(266	)	(150	)
Spending on existing obligations		(228	)	(152	)
Property dispositions		(161	)	(1,065	)
Foreign currency translation		(240	)	289

Balance at December 31	$	7,908		7,798

Accrued Environmental Costs

Total accrued environmental costs at December 31, 2018 and 2017, were $178 million and $180 million, respectively.

We had accrued environmental costs of $100 million and $105 million at December 31, 2018 and 2017, respectively, related to remediation activities in the United States and Canada. We had also accrued in Corporate and Other $67 million and $60 million of environmental costs associated with sites no longer in operation at December 31, 2018 and 2017, respectively. In addition, $11 million and $15 million were included at both December 31, 2018 and 2017, respectively, where the company has been named a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act, or similar state laws. Accrued environmental liabilities are expected to be paid over periods extending up to 30 years.

Expected expenditures for environmental obligations acquired in various business combinations are discounted using a weighted-average 5 percent discount factor, resulting in an accrued balance for acquired environmental liabilities of $88 million at December 31, 2018. The expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are: $6 million in 2019, $6 million in 2020, $10 million in 2021, $6 million in 2022, $2 million in 2023, and $109 million for all future years after 2023.

Note 11—Debt

Long-term debt at December 31 was:


		Millions of Dollars

		2018		2017


9.125% Debentures due 2021	$	123		150
8.20% Debentures due 2025		134		150
8.125% Notes due 2030		390		600
7.9% Debentures due 2047		60		100
7.8% Debentures due 2027		203		300
7.65% Debentures due 2023		78		88
7.40% Notes due 2031		500		500
7.375% Debentures due 2029		92		92
7.25% Notes due 2031		500		500
7.20% Notes due 2031		575		575
7% Debentures due 2029		200		200
6.95% Notes due 2029		1,549		1,549
6.875% Debentures due 2026		67		67
6.50% Notes due 2039		2,750		2,750
5.951% Notes due 2037		645		645
5.95% Notes due 2036		500		500
5.95% Notes due 2046		500		500
5.90% Notes due 2032		505		505
5.90% Notes due 2038		600		600
4.95% Notes due 2026		1,250		1,250
4.30% Notes due 2044		750		750
4.20% Notes due 2021		-		1,000
4.15% Notes due 2034		246		500
3.35% Notes due 2024		426		1,000
3.35% Notes due 2025		199		500
2.875% Notes due 2021		-		750
2.4% Notes due 2022		329		1,000
2.2% Notes due 2020		-		500
Floating rate notes due 2018 at 1.24% – 1.75% during 2017		-		250
Floating rate notes due 2022 at 2.32% – 3.52% during 2018 and 1.81% – 2.32% during 2017		500		500
Industrial Development Bonds due 2018 through 2038 at 0.95% – 1.86% during 2018 and 0.64% – 1.74% during 2017		18		18
Marine Terminal Revenue Refunding Bonds due 2031 at 0.88% – 1.95% during 2018 and 0.64% – 1.74% during 2017		265		265
Other		17		23

Debt at face value		13,971		18,677
Capitalized leases		777		774
Net unamortized premiums, discounts and debt issuance costs		220		252

Total debt		14,968		19,703
Short-term debt		(112	)	(2,575	)

Long-term debt	$	14,856		17,128

Maturities of long-term borrowings, inclusive of net unamortized premiums and discounts, in 2019 through 2023 are: $112 million, $101 million, $213 million, $935 million and $195 million, respectively.

In May 2018, we refinanced our revolving credit facility from a total aggregate principal amount of $6.75 billion to $6.0 billion with a new expiration date of May 2023. Our revolving credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as support for our commercial paper program. 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 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.

The revolving credit facility supports the ConocoPhillips Company $6.0 billion commercial paper program, which is primarily a funding source for short-term working capital needs. Commercial paper maturities are generally limited to 90 days. We had no commercial paper outstanding in programs in place at December 31, 2018 or December 31, 2017. We had no direct outstanding borrowings or letters of credit under the revolving credit facility at December 31, 2018 or December 31, 2017. Since we had no commercial paper outstanding and had issued no letters of credit, we had access to $6.0 billion in borrowing capacity under our revolving credit facility at December 31, 2018.

In 2018, we repaid the $250 million floating rate note due in 2018 at its natural maturity.

We also redeemed or repurchased a total $4,450 million of debt in 2018, described below, incurring $208 million in net premiums above book value, which are reported in the “Other expenses” line on our consolidated income statement.

	•		4.20% Notes due 2021 with remaining principal of $1.0 billion.

	•		2.875% Notes due 2021 with principal of $750 million.

	•		2.4% Notes due 2022 with principal of $1.0 billion (partial repurchase of $671 million).

	•		3.35% Notes due 2024 with principal of $1.0 billion (partial repurchase of $574 million).

	•		2.2% Notes due 2020 with principal of $500 million.

	•		3.35% Notes due 2025 with principal of $500 million (partial repurchase of $301 million).

	•		4.15% Notes due 2034 with principal of $500 million (partial repurchase of $254 million).

	•		8.125% Notes due 2030 with principal of $600 million (partial repurchase of $210 million).

	•		7.8% Notes due 2027 with principal of $300 million (partial repurchase of $97 million).

	•		7.9% Notes due 2047 with principal of $100 million (partial repurchase of $40 million).

	•		9.125% Notes due 2021 with principal of $150 million (partial repurchase of $27 million).

	•		8.20% Notes due 2025 with principal of $150 million (partial repurchase of $16 million).

	•		7.65% Notes due 2023 with principal of $88 million (partial repurchase of $10 million).

At both December 31, 2018 and 2017, we had $283 million of certain variable rate demand bonds (VRDBs) outstanding with maturities ranging through 2035. The VRDBs are redeemable at the option of the bondholders on any business day. The VRDBs are included in the “Long-term debt” line on our consolidated balance sheet.

During 2013, a lease of a semi-submersible floating production system (FPS) commenced for the Gumusut development, located in Malaysia, in which we are a co-venturer. The FPS lease provides for an initial noncancelable term of 15 years, a subsequent 5-year cancelable term with no required lease payments, and an

additional 5-year term with terms and conditions to be agreed at a later date. The lease has no ongoing purchase options or escalation clauses. Adjustments to provisional contingent rental payments may occur due to the finalization of actual commissioning costs. The lease does not impose any significant restrictions concerning dividends, debt or further leasing activities.

A capital lease asset and capital lease obligation were recognized for our proportionate interest in the FPS of $906 million, based on the present value of the future minimum lease payments using our before-tax incremental borrowing rate of 3.58 percent for debt with similar terms. Our proportionate interest in the FPS is 29 percent as of December 31, 2018. The net carrying value of the capital lease asset was approximately $353 million and $434 million as of December 31, 2018 and 2017, respectively. The capital lease asset is being depreciated over a period consistent with the estimated proved reserves of Gumusut using the unit-of-production method with the associated depreciation included in the “Depreciation, depletion and amortization” line on our consolidated income statement. As of December 31, 2018 and 2017, accumulated depreciation of the capital lease asset amounted to approximately $462 million and $381 million, respectively.

At December 31, 2018, future minimum payments due under capital leases were:


		Millions of Dollars


2019	$	118
2020		116
2021		100
2022		98
2023		87
Remaining years		453

Total		972
Less: portion representing imputed interest		(195	)

Capital lease obligations	$	777

Note 12—Guarantees

At December 31, 2018, 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 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 December 31, 2018, 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 December 2018 exchange rates:

	•		During the third quarter of 2016, we issued a guarantee to facilitate the withdrawal of our pro-rata portion of the funds in a project finance reserve account. We estimate the remaining term of this guarantee is 12 years. Our maximum exposure under this guarantee is approximately $170 million and may become payable if an enforcement action is commenced by the project finance lenders against APLNG. At December 31, 2018, the carrying value of this guarantee is approximately $14 million.

	•		In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy in October 2008, we agreed to reimburse Origin Energy for our share of the existing contingent liability arising under guarantees of an existing obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of up to 23 years. Our maximum potential liability for future payments, or cost of volume delivery, under these guarantees is estimated to be $800 million ($1.4 billion in the event of intentional or reckless breach) and would become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-venturers do not make necessary equity contributions into APLNG.

	•		We have guaranteed the performance of APLNG with regard to certain other contracts executed in connection with the project’s continued development. The guarantees have remaining terms of up to 27 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $140 million and would become payable if APLNG does not perform.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $780 million, which consist primarily of guarantees of the residual value of leased office buildings, guarantees of the residual value of leased corporate aircraft, and a guarantee for our portion of a joint venture’s project finance reserve accounts. These guarantees have remaining terms of up to four years 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 nonperformance 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 December 31, 2018, 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 December 31, 2018, were approximately $30 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 13—Contingencies and Commitments.

In 2012, we completed the separation of our downstream business, creating two independent energy companies: ConocoPhillips and Phillips 66. On March 1, 2015, a supplier to one of the refineries 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. As of December 31, 2017, the carrying value of this guarantee was $98 million. Because Phillips 66 has indemnified us for losses incurred under this guarantee, we also recorded an indemnification asset from Phillips 66 of $98 million. During the third quarter of 2018, a termination agreement between the supplier and Phillips 66 was executed, releasing all parties from their respective obligations under the supply agreement. Since all obligations under the supply agreement were satisfied and discharged, the guarantee was terminated. As of December 31, 2018, the carrying value of this guarantee and the associated indemnification asset have been removed.

Note 13—Contingencies and Commitments

A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed 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. See Note 19—Income Taxes, for additional information about income tax-related contingencies.

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. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings. See Note 10—Asset Retirement Obligations and Accrued Environmental Costs, for a summary of our accrued environmental liabilities.

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 and tax 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 December 31, 2018, we had performance obligations secured by letters of credit of $323 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, ConocoPhillips was unable to reach agreement with respect to the 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, ConocoPhillips initiated international arbitration on November 2, 2007, with the World Bank’s International Centre for Settlement of Investment Disputes (ICSID). On September 3, 2013, an ICSID arbitration tribunal held that Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in June 2007. On January 17, 2017, the Tribunal reconfirmed the decision that the expropriation was unlawful. A separate arbitration phase is currently proceeding to determine the damages owed to ConocoPhillips for Venezuela’s actions.

In 2014, ConocoPhillips filed a separate and independent arbitration under the rules of the International Chamber of Commerce (ICC) against PDVSA under the contracts that had established the Petrozuata and Hamaca projects. The ICC Tribunal issued an award in April 2018, finding that PDVSA owed ConocoPhillips approximately $2 billion under their agreements in connection with the expropriation of the projects and other pre-expropriation fiscal measures. In August 2018, ConocoPhillips entered into a settlement with PDVSA to recover the full amount of this ICC award, plus interest through the payment period, including initial payments totaling approximately $500 million within a period of 90 days from the time of signing of the settlement agreement. The balance of the settlement is to be paid quarterly over a period of four and a half years. By year-end 2018, we collected from PDVSA under the settlement and recognized in other income $430 million before-tax consisting of $230 million from the sale of commodity inventory and $200 million in cash. The remainder of the initial payments will become an adjustment to a future quarterly installment. Per the settlement, PDVSA recognized the ICC award as a judgment in various jurisdictions, and ConocoPhillips agreed to suspend its legal enforcement actions, including in the Dutch Caribbean. ConocoPhillips has ensured that the settlement meets all appropriate U.S. regulatory requirements, including any applicable sanctions imposed by the U.S. against Venezuela.

In 2016, ConocoPhillips filed a separate and independent arbitration under the rules of the ICC against PDVSA under the contracts that had established the Corocoro project. This ICC arbitration is currently in progress.

In February 2017, the ICSID tribunal unanimously awarded Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, $380 million for Ecuador’s unlawful expropriation of Burlington’s investment in Blocks 7 and 21, in breach of the U.S.-Ecuador Bilateral Investment Treaty. The tribunal also issued a separate decision finding Ecuador to be entitled to $42 million for environmental and infrastructure counterclaims. In December 2017, Burlington and Ecuador entered into a settlement agreement by which Ecuador paid Burlington $337 million in two installments. The first installment of $75 million was paid in December 2017, and the second installment of $262 million was paid in April 2018. The settlement included an offset for the counterclaims decision, of which Burlington is entitled to a $24 million contribution from Perenco Ecuador Limited, its co-venturer and consortium operator, pursuant to a joint and several liability provision in the joint operating agreement (JOA). Ecuador’s environmental and infrastructure counterclaims against Perenco remain pending in a separate ICSID arbitration between Perenco and Ecuador, and Burlington may owe Perenco contribution under the JOA for damages found by this tribunal.

In December 2016, ConocoPhillips Angola filed a notice of arbitration against Sonangol E.P. under the Block 36 Production Sharing Contract relating to disputes arising thereunder. In 2018, the parties reached a confidential settlement.

In June 2017, FAR Ltd. initiated arbitration before the ICC against ConocoPhillips Senegal B.V. in connection with the sale of ConocoPhillips Senegal B.V. to Woodside Energy Holdings (Senegal) Limited in 2016. This arbitration is ongoing.

In late 2017, ConocoPhillips (U.K.) Limited (CPUKL) initiated United Nations Commission on International Trade and Law (UNCITRAL) arbitration against Vietnam in accordance with the U.K.-Vietnam Bilateral Investment Treaty relating to a tax dispute arising from the 2012 sale of ConocoPhillips (U.K.) Cuu Long Limited and ConocoPhillips (U.K.) Gama Limited. The tribunal was constituted in February 2018. The arbitration is ongoing.

In 2017 and 2018, cities, counties, a state government, and a trade association in California, New York, Washington, Rhode Island and Maryland, as well as the Pacific Coast Federation of Fishermen’s Association, Inc., have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages and equitable relief to abate alleged climate change impacts. ConocoPhillips is vigorously defending against these lawsuits. The lawsuits brought by the Cities of San Francisco, Oakland and New York have been dismissed by the district courts and appeals are pending.

Several Louisiana parishes and individual landowners have filed lawsuits against oil and gas companies, including ConocoPhillips, seeking compensatory damages in connection with historical oil and gas operations in Louisiana. ConocoPhillips will vigorously defend against these lawsuits.

Long-Term Throughput Agreements and Take-or-Pay Agreements

We have certain throughput agreements and take-or-pay agreements in support of financing arrangements. The agreements typically provide for natural gas or crude oil transportation to be used in the ordinary course of the company’s business. The aggregate amounts of estimated payments under these various agreements are: 2019—$7 million; 2020—$7 million; 2021—$7 million; 2022—$7 million; 2023—$7 million; and 2024 and after—$61 million. Total payments under the agreements were $39 million in 2018, $43 million in 2017 and $42 million in 2016.

Note 14—Derivative and Financial 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 our 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

	2018		2017

Assets
Prepaid expenses and other current assets	$	410		275
Other assets		40		36
Liabilities
Other accruals		370		282
Other liabilities and deferred credits		30		28

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


	Millions of Dollars

	2018		2017		2016


Sales and other operating revenues	$	45		77		(198)
Other income		7		-		(1)
Purchased commodities		(41)		(61)		161

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


	Open Position Long/(Short)

	2018		2017

Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price		(17)		(29)
Basis		(1)		12

Foreign Currency Exchange Derivatives

We have foreign currency exchange rate risk resulting from international operations. Our foreign currency exchange derivative activity primarily relates to managing our cash-related 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, and investments in equity securities. 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

		2018	2017

Assets
Prepaid expenses and other current assets	$	7	1
Other assets		-	6
Liabilities
Other accruals		6	-
Other liabilities and deferred credits		-	15

In December 2017, we entered into foreign exchange zero cost collars buying the right to sell $1.25 billion CAD at $0.707 CAD and selling the right to buy $1.25 billion CAD at $0.842 CAD against the U.S. dollar.

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


	Millions of Dollars

	2018		2017		2016


Foreign currency transaction losses	$	1		13		247

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


	In Millions Notional Currency

		2018	2017

Foreign Currency Exchange Derivatives
Sell U.S. dollar, buy British pound	USD	805	-
Sell British pound, buy other currencies*	GBP	21	1
Sell Canadian dollar, buy U.S. dollar	CAD	1,242	1,225

*Primarily euro and Norwegian krone.

Financial Instruments

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

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

	•		Commercial paper: Unsecured promissory notes issued by a corporation, commercial bank or government agency purchased at a discount to mature at par.

	•		Government or government agency obligations: Short-term securities issued by the U.S. government or U.S. government agencies.

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


	Millions of Dollars

	Carrying Amount

		Cash and Cash Equivalents		Short-Term Investments

		2018	2017	2018	2017


Cash	$	876	948
Time Deposits
Remaining maturities from 1 to 90 days		3,509	5,004	-	821
Commercial Paper
Remaining maturities from 1 to 90 days		229	373	248	978
Remaining maturities from 91 to 180 days		-	-	-	74
Government Obligations
Remaining maturities from 1 to 90 days		1,301	-	-	-

	$	5,915	6,325	248	1,873

Credit Risk

Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, short-term investments, over-the-counter (OTC) derivative contracts and trade receivables. Our cash equivalents and short-term investments are placed in high-quality commercial paper, government 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, swaps and options, 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 to 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 December 31, 2018 and December 31, 2017, was $62 million and $55 million, respectively. For these instruments, no collateral was posted as of December 31, 2018 or December 31, 2017. If our credit rating had been downgraded below investment grade on December 31, 2018, we would be required to post $62 million of additional collateral, either with cash or letters of credit.

Note 15—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 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. At the end of the fourth quarter of 2017, our $1,899 million investment in Cenovus Energy was transferred from Level 2 to Level 1 due to the lapsing of trading restrictions. There were no other material transfers in or out of Level 1 during 2018 or 2017.

Recurring Fair Value Measurement

Financial assets and liabilities reported at fair value on a recurring basis primarily include our investment in Cenovus Energy shares and commodity derivatives. 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 1 also includes our investment in common shares of Cenovus Energy, which is valued using quotes for shares on the New York Stock 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 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
	December 31, 2018					December 31, 2017
		Level 1	Level 2	Level 3	Total		Level 1	Level 2	Level 3	Total

Assets
Investment in Cenovus Energy	$	1,462	-	-	1,462		1,899	-	-	1,899
Commodity derivatives		236	181	33	450		175	106	30	311

Total assets	$	1,698	181	33	1,912		2,074	106	30	2,210


Liabilities
Commodity derivatives	$	225	145	30	400		158	111	41	310

Total liabilities	$	225	145	30	400		158	111	41	310

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

December 31, 2018
Assets	$	450		280		170		-		9		161
Liabilities		400		280		120		10		4		106


December 31, 2017
Assets	$	311		186		125		-		4		121
Liabilities		310		186		124		7		5		112

At December 31, 2018 and December 31, 2017, 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 and date of remeasurement for assets accounted for at fair value on a non-recurring basis:


	Millions of Dollars

			Fair Value Measurements Using

		Fair Value	Level 1 Inputs	Level 3 Inputs	Before-Tax Loss

Year ended December 31, 2018
Net PP&E (held for sale)
March 31, 2018	$	250	-	250	44
September 30, 2018		201	201	-	43


Year ended December 31, 2017
Net PP&E (held for use)
December 31, 2017	$	75	-	75	154
Net PP&E (held for sale)
June 30, 2017		2,830	2,830	-	3,882
December 31, 2017		113	113	-	78
Equity method investments
June 30, 2017		7,656	-	7,656	2,384

Net PP&E (held for sale)

Net PP&E held for sale was written down to fair value, less costs to sell. The fair value of each asset was determined by its negotiated selling price (Level 1) or information gathered during marketing efforts (Level 3). For additional information see Note 5—Assets Held for Sale, Sold or Acquired and Other Planned Dispositions.

Net PP&E (held for use)

Net PP&E held for use is comprised of various producing properties impaired to their individual fair values. 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.

Equity Method Investments

During 2017, our investment in APLNG was written down to its fair value of $7,656 million, resulting in a before-tax-charge of $2,384 million. For additional information on APLNG, see Note 6—Investments, Loans and Long-Term Receivables.

Reported Fair Values of Financial Instruments

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

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

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

	•		Investment in Cenovus Energy shares: See Note 7—Investment in Cenovus Energy for a discussion of the carrying value and fair value of our investment in Cenovus Energy shares.

	•		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 6—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
		2018	2017		2018	2017

Financial assets
Investment in Cenovus Energy	$	1,462	1,899		1,462	1,899
Commodity derivatives		170	125		170	125
Total loans and advances—related parties		468	586		468	586
Financial liabilities
Total debt, excluding capital leases		14,191	18,929		16,147	22,435
Commodity derivatives		110	117		110	117

Commodity Derivatives

At December 31, 2018, commodity derivative assets and liabilities appear net with no obligations to return cash collateral and $10 million of rights to reclaim cash collateral, respectively. At December 31, 2017, commodity derivative assets and liabilities appear net with no obligations to return cash collateral and $7 million of rights to reclaim cash collateral, respectively.

Note 16—Equity

Common Stock

The changes in our shares of common stock, as categorized in the equity section of the balance sheet, were:


	Shares
		2018	2017	2016

Issued
Beginning of year		1,785,419,175	1,782,079,107	1,778,226,388
Distributed under benefit plans		6,218,259	3,340,068	3,852,719

End of year		1,791,637,434	1,785,419,175	1,782,079,107


Held in Treasury
Beginning of year		608,312,034	544,809,771	542,230,673
Repurchase of common stock		44,976,179	63,502,263	2,579,098

End of year		653,288,213	608,312,034	544,809,771

Preferred Stock

We have authorized 500 million shares of preferred stock, par value $.01 per share, none of which was issued or outstanding at December 31, 2018 or 2017.

Noncontrolling Interests

At December 31, 2018 and 2017, we had $125 million and $194 million outstanding, respectively, of equity in less-than-wholly owned consolidated subsidiaries held by noncontrolling interest owners. For both periods, the amounts were related to the Darwin LNG and Bayu-Darwin Pipeline operating joint ventures we control.

Repurchase of Common Stock

On November 10, 2016, we announced plans to purchase up to $3 billion of our common stock through 2019. On March 29, 2017, we announced plans to repurchase an additional $3 billion of common stock through 2019. On July 12, 2018, we announced an authorization of an additional $9 billion for share repurchases bringing the total program authorization to $15 billion. Repurchase of shares began in November 2016, and totaled 111,057,540 shares at a cost of $6.1 billion, through December 31, 2018.

Note 17—Non-Mineral Leases

The company primarily leases drilling equipment and office buildings, as well as ocean transport vessels, tugboats, barges, corporate aircraft and other facilities and equipment. Certain leases include escalation clauses for adjusting rental payments to reflect changes in price indices, as well as renewal options and/or options to purchase the leased property for the fair market value at the end of the lease term. There are no significant restrictions imposed on us by the leasing agreements with regard to dividends, asset dispositions or borrowing ability. For additional information on leased assets under capital leases, see Note 11—Debt.

At December 31, 2018, future minimum rental payments due under noncancelable leases were:


	Millions of Dollars

2019	$	248
2020		425
2021		136
2022		319
2023		54
Remaining years		212

Total		1,394
Less: income from subleases		(7)

Net minimum operating lease payments	$	1,387

Operating lease rental expense for the years ended December 31 was:


	Millions of Dollars
		2018	2017	2016


Total rentals	$	253	264	537
Less: sublease rentals		(16)	(20)	(10)

	$	237	244	527

Note 18—Employee Benefit Plans

Pension and Postretirement Plans

An analysis of the projected benefit obligations for our pension plans and accumulated benefit obligations for our postretirement health and life insurance plans follows:


	Millions of Dollars
	Pension Benefits								Other Benefits
	2018				2017				2018		2017

	U.S.		Int’l.		U.S.		Int’l.

Change in Benefit Obligation
Benefit obligation at January 1	$	3,236		3,845		3,416		3,445		265		286
Service cost		83		81		89		77		1		2
Interest cost		99		107		118		103		8		9
Plan participant contributions		-		2		-		2		22		23
Plan amendments		-		7		-		-		-		-
Actuarial (gain) loss		(44)		(259)		244		52		(10)		12
Benefits paid		(507)		(143)		(631)		(117)		(67)		(68)
Curtailment		(4)		(3)		-		-		-		-
Settlement		(730)		-		-		-		-		-
Recognition of termination benefits		3		-		-		-		-		-
Foreign currency exchange rate change		-		(199)		-		283		(1)		1

Benefit obligation at December 31*	$	2,136		3,438		3,236		3,845		218		265

*Accumulated benefit obligation portion of above at December 31:	$	*1,969*		*3,066*		3,076		3,404

Change in Fair Value of Plan Assets
Fair value of plan assets at January 1	$	2,541		3,647		2,081		3,068		-		-
Actual return on plan assets		(112)		(106)		336		313		-		-
Company contributions		144		156		755		114		45		45
Plan participant contributions		-		2		-		2		22		23
Benefits paid		(507)		(143)		(631)		(117)		(67)		(68)
Settlement		(730)		-		-		-		-		-
Foreign currency exchange rate change		-		(198)		-		267		-		-

Fair value of plan assets at December 31	$	1,336		3,358		2,541		3,647		-		-

Funded Status	$	(800)		(80)		(695)		(198)		(218)		(265)


	Millions of Dollars
	Pension Benefits								Other Benefits
	2018				2017				2018		2017

	U.S.		Int’l.		U.S.		Int’l.

Amounts Recognized in the Consolidated Balance Sheet at December 31
Noncurrent assets	$	-		232		-		205		-		-
Current liabilities		(59)		(4)		(38)		(4)		(44)		(45)
Noncurrent liabilities		(741)		(308)		(657)		(399)		(174)		(220)

Total recognized	$	(800)		(80)		(695)		(198)		(218)		(265)


Weighted-Average Assumptions Used to Determine Benefit Obligations at December 31
Discount rate		4.25%		3.05		3.55		2.80		4.05		3.30
Rate of compensation increase		4.00		3.65		4.00		3.75		-		-


Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31
Discount rate		3.80%		2.90		3.80		3.00		3.30		3.60
Expected return on plan assets		5.80		4.30		6.55		5.05		-		-
Rate of compensation increase		4.00		3.75		4.00		3.85		-		-

For both U.S. and international pensions, the overall expected long-term rate of return is developed from the expected future return of each asset class, weighted by the expected allocation of pension assets to that asset class. We rely on a variety of independent market forecasts in developing the expected rate of return for each class of assets.

Included in accumulated other comprehensive income (loss) at December 31 were the following before-tax amounts that had not been recognized in net periodic benefit cost:


	Millions of Dollars
	Pension Benefits								Other Benefits
	2018				2017				2018		2017

	U.S.		Int’l.		U.S.		Int’l.


Unrecognized net actuarial (gain) loss	$	516		310		588		358		(21)		(12)
Unrecognized prior service cost (credit)		-		(4)		-		(16)		(216)		(249)


	Millions of Dollars
	Pension Benefits								Other Benefits
	2018				2017				2018		2017

	U.S.		Int’l.		U.S.		Int’l.

Sources of Change in Other Comprehensive Income (Loss)
Net gain (loss) arising during the period	$	(177)		17		(40)		71		10		(12)
Amortization of (gain) loss included in income (loss)*		249		31		200		50		(1)		(3)

Net change during the period	$	72		48		160		121		9		(15)


Prior service credit (cost) arising during the period	$	-		(7)		-		2		-		-
Amortization of prior service cost (credit) included in income (loss)		-		(5)		4		(6)		(35)		(36)

Net change during the period	$	-		(12)		4		(4)		(35)		(36)

*Includes settlement losses recognized in 2018 and 2017.

Included in accumulated other comprehensive loss at December 31, 2018, were the following before-tax amounts that are expected to be amortized into net periodic benefit cost during 2019:


	Millions of Dollars
	Pension Benefits				Other Benefits
	U.S.		Int’l.


Unrecognized net actuarial (gain) loss	$	52		31		(2)
Unrecognized prior service credit		-		(2)		(33)

For our tax-qualified pension plans with projected benefit obligations in excess of plan assets, the projected benefit obligation, the accumulated benefit obligation, and the fair value of plan assets were $4,110 million, $3,768 million, and $3,702 million, respectively, at December 31, 2018, and $5,634 million, $5,226 million, and $5,113 million, respectively, at December 31, 2017.

For our unfunded nonqualified key employee supplemental pension plans, the projected benefit obligation and the accumulated benefit obligation were $586 million and $504 million, respectively, at December 31, 2018, and were $578 million and $503 million, respectively, at December 31, 2017.

The components of net periodic benefit cost of all defined benefit plans are presented in the following table:


	Millions of Dollars
	Pension Benefits												Other Benefits
	2018				2017				2016				2018		2017		2016

	U.S.		Int’l.		U.S.		Int’l.		U.S.		Int’l.

Components of Net Periodic Benefit Cost
Service cost	$	83		81		89		77		108		76		1		2		2
Interest cost		99		107		118		103		133		120		8		9		13
Expected return on plan assets		(114)		(155)		(132)		(158)		(149)		(147)		-		-		-
Amortization of prior service cost (credit)		-		(5)		4		(6)		5		(6)		(35)		(36)		(34)
Recognized net actuarial loss (gain)		53		31		69		50		86		26		(1)		(3)		(2)
Settlements		196		-		131		-		202		-		-		-		-
Curtailment loss		-		-		-		-		14		-		-		-		1

Net periodic benefit cost	$	317		59		279		66		399		69		(27)		(28)		(20)

The components of net periodic benefit cost, other than the service cost component, are included in the “Other expenses” line item on our consolidated income statement.

In 2018, we purchased a group annuity contract from Prudential and transferred $730 million of future benefit obligations from the U.S. qualified pension plan to Prudential. The purchase of the group annuity contract was funded directly by plan assets of the U.S. qualified pension plan. Effective January 1, 2019, the Cash Balance Account (Title II) of the ConocoPhillips Retirement Plan, a U.S. qualified pension plan, was closed to new entrants. New employees and rehires on or after January 1, 2019, and employees that elected to opt out of Title II will no longer receive pay credits to their Cash Balance Account and instead will be eligible for a Company Retirement Contribution (CRC) as described in the Defined Contribution Plans section.

We recognized pension settlement losses of $196 million in 2018, $131 million in 2017, and $202 million in 2016 as lump-sum benefit payments from certain U.S. pension plans exceeded the sum of service and interest costs for those plans and led to recognition of settlement losses.

As part of the 2016 restructuring program, we concluded that actions taken during the year resulted in a significant reduction of future services of active employees primarily in the U.S. qualified pension plan and a U.S. nonqualified supplemental retirement plan. As a result, we recognized an increase in the benefit obligation and a proportionate share of prior service cost from other comprehensive income (loss) as a curtailment loss of $15 million during the year ended December 31, 2016.

Also, as part of the 2016 restructuring program in the United States and Europe, we recognized expense for special termination benefits of $15 million during the year ended December 31, 2016, consisting of $14 million in the United States and $1 million in Europe.

In determining net pension and other postretirement benefit costs, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. For net actuarial gains and losses, we amortize 10 percent of the unamortized balance each year.

We have multiple nonpension postretirement benefit plans for health and life insurance. The health care plans are contributory and subject to various cost sharing features, with participant and company contributions adjusted annually; the life insurance plans are noncontributory. The measurement of the U.S. pre-65 retiree medical accumulated postretirement benefit obligation assumes a health care cost trend rate of 7 percent in 2019 that declines to 5 percent by 2024. The measurement of the U.S. post-65 retiree medical accumulated postretirement benefit obligation assumes an ultimate health care cost trend rate of 5 percent achieved in 2019. A one-percentage-point change in the assumed health care cost trend rate would be immaterial to ConocoPhillips.

Plan Assets—We follow a policy of broadly diversifying pension plan assets across asset classes and individual holdings. As a result, our plan assets have no significant concentrations of credit risk. Asset classes that are considered appropriate include U.S. equities, non-U.S. equities, U.S. fixed income, non-U.S. fixed income, real estate and private equity investments. Plan fiduciaries may consider and add other asset classes to the investment program from time to time. The target allocations for plan assets are 39 percent equity securities, 54 percent debt securities, 6 percent real estate and 1 percent other. Generally, the plan investments are publicly traded, therefore minimizing liquidity risk in the portfolio.

The following is a description of the valuation methodologies used for the pension plan assets. There have been no changes in the methodologies used at December 31, 2018 and 2017.

	•		Fair values of equity securities and government debt securities categorized in Level 1 are primarily based on quoted market prices in active markets for identical assets and liabilities.

	•		Fair values of corporate debt securities, agency and mortgage-backed securities and government debt securities categorized in Level 2 are estimated using recently executed transactions and quoted market prices for similar assets and liabilities in active markets and for identical assets and liabilities in markets that are not active. If there have been no market transactions in a particular fixed income security, its fair value is calculated by pricing models that benchmark the security against other securities with actual market prices. When observable quoted market prices are not available, fair value is based on pricing models that use something other than actual market prices (e.g., observable inputs such as benchmark yields, reported trades and issuer spreads for similar securities), and these securities are categorized in Level 3 of the fair value hierarchy.

	•		Fair values of investments in common/collective trusts are determined by the issuer of each fund based on the fair value of the underlying assets.

	•		Fair values of mutual funds are based on quoted market prices, which represent the net asset value of shares held.

	•		Time deposits are valued at cost, which approximates fair value.

	•		Cash is valued at cost, which approximates fair value. Fair values of international cash equivalents categorized in Level 2 are valued using observable yield curves, discounting and interest rates. U.S. cash balances held in the form of short-term fund units that are redeemable at the measurement date are categorized as Level 2.

	•		Fair values of exchange-traded derivatives classified in Level 1 are based on quoted market prices. For other derivatives classified in Level 2, the values are generally calculated from pricing models with market input parameters from third-party sources.

	•		Fair values of insurance contracts are valued at the present value of the future benefit payments owed by the insurance company to the plans’ participants.

	•		Fair values of real estate investments are valued using real estate valuation techniques and other methods that include reference to third-party sources and sales comparables where available.

	•		A portion of U.S. pension plan assets is held as a participating interest in an insurance annuity contract, which is calculated as the market value of investments held under this contract, less the accumulated benefit obligation covered by the contract. The participating interest is classified as Level 3 in the fair value hierarchy as the fair value is determined via a combination of quoted market prices, recently executed transactions, and an actuarial present value computation for contract obligations. At December 31, 2018, the participating interest in the annuity contract was valued at $84 million and consisted of $228 million in debt securities, less $144 million for the accumulated

benefit obligation covered by the contract. At December 31, 2017, the participating interest in the annuity contract was valued at $99 million and consisted of $265 million in debt securities, less $166 million for the accumulated benefit obligation covered by the contract. The net change from 2017 to 2018 is due to a decrease in the fair value of the underlying investments of $37 million offset by a decrease in the present value of the contract obligation of $22 million. The participating interest is not available for meeting general pension benefit obligations in the near term. No future company contributions are required and no new benefits are being accrued under this insurance annuity contract.

The fair values of our pension plan assets at December 31, by asset class were as follows:


	Millions of Dollars

	U.S.								International

	Level 1		Level 2		Level 3		Total		Level 1			Level 2		Level 3		Total

2018
Equity securities
U.S.	$	74		-		20		94		371			-		-		371
International		80		-		-		80		241			-		-		241
Mutual funds		76		-		-		76		213			181		-		394
Debt securities
Government		-		-		-		-		889			-		-		889
Corporate		-		2		-		2		-			-		-		-
Mutual funds		-		-		-		-		363			-		-		363
Cash and cash equivalents		-		-		-		-		71			-		-		71
Time deposits		-		-		-		-		6			-		-		6
Derivatives		-		-		-		-		(17	)		-		-		(17	)
Real estate		-		-		-		-		-			-		124		124

Total in fair value hierarchy	$	230		2		20		252		2,137			181		124		2,442

Investments measured at net asset value*
Equity securities
Common/collective trusts	$	-		-		-		364		-			-		-		153
Debt securities
Corporate		-		-		-		-		-			-		-		-
Agency and mortgage-backed securities		-		-		-		-		-			-		-		-
Common/collective trusts		-		-		-		548		-			-		-		641
Cash and cash equivalents		-		-		-		5		-			-		-		-
Real estate		-		-		-		80		-			-		-		109

Total**	$	230		2		20		1,249		2,137			181		124		3,345

*In accordance with FASB ASC Topic 715, “Compensation—Retirement Benefits,” certain investments that are to be measured at fair value using the net asset value per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Change in Fair Value of Plan Assets.

**Excludes the participating interest in the insurance annuity contract with a net asset value of $84 million and net receivables related to security transactions of $16 million.

The fair values of our pension plan assets at December 31, by asset class were as follows:


	Millions of Dollars

	U.S.								International

	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total

2017
Equity securities
U.S.	$	161		-		14		175		440		-		-		440
International		178		-		-		178		315		-		-		315
Mutual funds		146		-		-		146		292		165		-		457
Debt securities
Government		-		-		-		-		902		-		-		902
Corporate		-		2		-		2		-		-		-		-
Mutual funds		-		-		-		-		144		-		-		144
Cash and cash equivalents		-		-		-		-		111		-		-		111
Time deposits		-		-		-		-		3		-		-		3
Derivatives		-		-		-		-		5		-		-		5
Real estate		-		-		-		-		-		-		123		123

Total in fair value hierarchy	$	485		2		14		501		2,212		165		123		2,500

Investments measured at net asset value*
Equity securities
Common/collective trusts	$	-		-		-		805		-		-		-		183
Debt securities
Corporate		-		-		-		-		-		-		-		172
Agency and mortgage-backed securities		-		-		-		-		-		-		-		15
Common/collective trusts		-		-		-		1,042		-		-		-		648
Cash and cash equivalents		-		-		-		17		-		-		-		24
Real estate		-		-		-		74		-		-		-		94

Total**	$	485		2		14		2,439		2,212		165		123		3,636

**Excludes the participating interest in the insurance annuity contract with a net asset value of $99 million and net payables related to security transactions of $14 million.

Level 3 activity was not material for all periods.

Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code of 1986, as amended. Contributions to foreign plans are dependent upon local laws and tax regulations. In 2019, we expect to contribute approximately $195 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $185 million to our international qualified and nonqualified pension and postretirement benefit plans.

The following benefit payments, which are exclusive of amounts to be paid from the insurance annuity contract and which reflect expected future service, as appropriate, are expected to be paid:


	Millions of Dollars

	Pension Benefits				Other Benefits

	U.S.		Int’l.


2019		$ 400		123		36
2020		251		129		34
2021		232		137		30
2022		222		138		27
2023		216		143		24
2024–2027		880		788		69

Severance Accrual

As a result of staff reductions occurring throughout the year, severance accruals of $70 million were recorded in 2018. The following table summarizes our severance accrual activity for the year ended December 31, 2018:


	Millions of Dollars

Balance at December 31, 2017	$	53
Accruals		70
Benefit payments		(73)
Foreign currency translation adjustments		(2)

Balance at December 31, 2018	$	48

Of the remaining balance at December 31, 2018, $23 million is classified as short-term.

Defined Contribution Plans

Most U.S. employees are eligible to participate in the ConocoPhillips Savings Plan (CPSP). Employees can deposit up to 75 percent of their eligible pay, subject to statutory limits, in the CPSP to a choice of approximately 34 investment options. Employees who participate in the CPSP and contribute 1 percent of their eligible pay receive a 6 percent company cash match with a potential company discretionary cash contribution of up to 6 percent. Effective January 1, 2019, new employees, rehires, and employees that elected to opt out of Title II will be eligible to receive a CRC of 6 percent of eligible pay into their CPSP. After three years of service with the company, the employee is 100 percent vested in any CRC. Company contributions charged to expense for the CPSP and predecessor plans were $82 million in 2018, $77 million in 2017, and $58 million in 2016.

We have several defined contribution plans for our international employees, each with its own terms and eligibility depending on location. Total compensation expense recognized for these international plans was approximately $31 million in 2018, $35 million in 2017, and $44 million in 2016.

Share-Based Compensation Plans

The 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (the Plan) was approved by shareholders in May 2014. Over its 10-year life, the Plan allows the issuance of up to 79 million shares of our common stock for compensation to our employees and directors; however, as of the effective date of the Plan, (i) any shares of common stock available for future awards under the prior plans and (ii) any shares of common stock represented by awards granted under the prior plans that are forfeited, expire or are cancelled without delivery of shares of common stock or which result in the forfeiture of shares of common stock back to the

company shall be available for awards under the Plan, and no new awards shall be granted under the prior plans. Of the 79 million shares available for issuance under the Plan, no more than 40 million shares of common stock are available for incentive stock options. The Human Resources and Compensation Committee of our Board of Directors is authorized to determine the types, terms, conditions and limitations of awards granted. Awards may be granted in the form of, but not limited to, stock options, restricted stock units and performance share units to employees and non-employee directors who contribute to the company’s continued success and profitability.

Total share-based compensation expense is measured using the grant date fair value for our equity-classified awards and the settlement date fair value for our liability-classified awards. We recognize share-based compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the award); or the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement, but not less than six months, as this is the minimum period of time required for an award to not be subject to forfeiture. Our share-based compensation programs generally provide accelerated vesting (i.e., a waiver of the remaining period of service required to earn an award) for awards held by employees at the time of their retirement. Some of our share-based awards vest ratably (i.e., portions of the award vest at different times) while some of our awards cliff vest (i.e., all of the award vests at the same time). We recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.

Compensation Expense—Total share-based compensation expense recognized in income (loss) and the associated tax benefit for the years ended December 31 were as follows:


	Millions of Dollars

	2018		2017		2016


Compensation cost	$	265		227		272
Tax benefit		64		76		92

Stock Options—Stock options granted under the provisions of the Plan and prior plans permit purchase of our common stock at exercise prices equivalent to the average fair market value of ConocoPhillips common stock on the date the options were granted. The options have terms of 10 years and generally vest ratably, with one-third of the options awarded vesting and becoming exercisable on each anniversary date following the date of grant. Options awarded to certain employees already eligible for retirement vest within six months of the grant date, but those options do not become exercisable until the end of the normal vesting period. Beginning in 2018, stock option grants were discontinued and replaced with three-year, time-vested restricted stock units which generally will be cash-settled.

The fair market values of the options granted in 2017 and 2016 were measured on the date of grant using the Black-Scholes-Merton option-pricing model. The weighted-average assumptions used were as follows:


	2017			2016

Assumptions used
Risk-free interest rate		2.24	%		1.55
Dividend yield		4.00	%		4.00
Volatility factor		28.12	%		26.80
Expected life (years)		6.39			6.37

There were no ranges in the assumptions used to determine the fair market values of our options granted in 2017 and 2016.

We believe our historical volatility for periods prior to the 2012 separation of our Downstream businesses is no longer relevant in estimating expected volatility. For 2017 and 2016, expected volatility was based on the weighted-average blend of the company’s historical stock price volatility from May 1, 2012 (the date of separation of our Downstream businesses) through the stock option grant date and the average historical stock price volatility of a group of peer companies for the expected term of the options.

The following summarizes our stock option activity for the year ended December 31, 2018:


	Options		Weighted- Average Exercise Price		Millions of Dollars
	Aggregate Intrinsic Value

Outstanding at December 31, 2017		24,722,803	$	52.18	$	177
Exercised		(3,903,130)		45.71		94
Forfeited		(84,694)		58.23
Expired or cancelled		(1,355,302)		60.53

Outstanding at December 31, 2018		19,379,677	$	52.88	$	214

Vested at December 31, 2018		18,820,388	$	53.16	$	204

Exercisable at December 31, 2018		16,213,002	$	54.89	$	152

The weighted-average remaining contractual term of outstanding options, vested options and exercisable options at December 31, 2018, was 5.16 years, 5.09 years and 4.69 years, respectively. The weighted-average grant date fair value of stock option awards granted during 2017 and 2016 was $9.18 and $5.39, respectively. The aggregate intrinsic value of options exercised was $4 million in 2017 and zero in 2016.

During 2018, we received $178 million in cash and realized a tax benefit of $18 million from the exercise of options. At December 31, 2018, the remaining unrecognized compensation expense from unvested options was $2 million, which will be recognized over a weighted-average period of 0.87 years, the longest period being 1.12 years.

**Stock Unit Program—**Generally, restricted stock units are granted annually under the provisions of the Plan and vest in an aggregate installment on the third anniversary of the grant date. In addition, restricted stock units granted under the Plan for a variable long-term incentive program vest ratably in three equal annual installments beginning on the first anniversary of the grant date. Restricted stock units are also granted ad hoc to attract or retain key personnel, and the terms and conditions under which these restricted stock units vest vary by award.

Stock-Settled

Upon vesting, these restricted stock units are settled by issuing one share of ConocoPhillips common stock per unit. Units awarded to retirement eligible employees vest six months from the grant date; however, those units are not issued as common stock until the earlier of separation from the company or the end of the regularly scheduled vesting period. Until issued as stock, most recipients of the restricted stock units receive a quarterly cash payment of a dividend equivalent that is charged to retained earnings. The grant date fair market value of these restricted stock units is deemed equal to the average ConocoPhillips stock price on the grant date. The grant date fair market value of units that do not receive a dividend equivalent while unvested is deemed equal to the average ConocoPhillips stock price on the grant date, less the net present value of the dividends that will not be received.

The following summarizes our stock-settled stock unit activity for the year ended December 31, 2018:


	Stock Units			Weighted-Average		Millions of Dollars

	Grant Date Fair Value			Total Fair Value


Outstanding at December 31, 2017		7,826,852			$ 45.75
Granted		2,465,100			52.45
Forfeited		(173,265	)		45.72
Issued		(2,571,714	)				$ 154

Outstanding at December 31, 2018		7,546,973			$ 43.41

Not Vested at December 31, 2018		5,090,209			43.69

At December 31, 2018, the remaining unrecognized compensation cost from the unvested stock-settled units was $88 million, which will be recognized over a weighted-average period of 1.68 years, the longest period being 2.76 years. The weighted-average grant date fair value of stock unit awards granted during 2017 and 2016 was $48.77 and $32.15, respectively. The total fair value of stock units issued during 2017 and 2016 was $159 million and $191 million, respectively.

Cash-Settled

Beginning in 2018, cash-settled executive restricted stock units replaced the stock option program. These restricted stock units, subject to elections to defer, will be settled in cash equal to the fair market value of a share of ConocoPhillips common stock per unit on the settlement date and are classified as liabilities on the balance sheet. Units awarded to retirement eligible employees vest six months from the grant date; however, those units are not settled until the earlier of separation from the company or the end of the regularly scheduled vesting period. Compensation expense is initially measured using the average fair market value of ConocoPhillips common stock and is subsequently adjusted, based on changes in the ConocoPhillips stock price through the end of each subsequent reporting period, through the settlement date. Recipients receive an accrued reinvested dividend equivalent that is charged to compensation expense. The accrued reinvested dividend is paid at the time of settlement, subject to the terms and conditions of the award.

The following summarizes our cash-settled stock unit activity for the year ended December 31, 2018:


	Stock Units		Weighted-Average	Millions of Dollars
	Grant Date Fair Value		Total Fair Value

Outstanding at December 31, 2017	-		$ -
Granted	393,571		53.68
Forfeited	(3,849	)	59.17
Issued	(13,114	)		$ 1

Outstanding at December 31, 2018	376,608		$ 62.21

Not Vested at December 31, 2018	90,254		62.21

At December 31, 2018, the remaining unrecognized compensation cost from the unvested cash-settled units was $3 million, which will be recognized over a weighted-average period of 1.79 years, the longest period being 2.12 years.

Performance Share Program—Under the Plan, we also annually grant restricted performance share units (PSUs) to senior management. These PSUs are authorized three years prior to their effective grant date (the performance period). Compensation expense is initially measured using the average fair market value of ConocoPhillips common stock and is subsequently adjusted, based on changes in the ConocoPhillips stock price through the end of each subsequent reporting period, through the grant date for stock-settled awards and the settlement date for cash-settled awards.

Stock-Settled

For performance periods beginning before 2009, PSUs do not vest until the employee becomes eligible for retirement by reaching age 55 with five years of service, and restrictions do not lapse until the employee separates from the company. With respect to awards for performance periods beginning in 2009 through 2012, PSUs do not vest until the earlier of the date the employee becomes eligible for retirement by reaching age 55 with five years of service or five years after the grant date of the award, and restrictions do not lapse until the earlier of the employee’s separation from the company or five years after the grant date (although recipients can elect to defer the lapsing of restrictions until separation). We recognize compensation expense for these awards beginning on the grant date and ending on the date the PSUs are scheduled to vest. Since these awards are authorized three years prior to the grant date, for employees eligible for retirement by or shortly after the grant date, we recognize compensation expense over the period beginning on the date of authorization and ending on the date of grant. Until issued as stock, recipients of the PSUs receive a quarterly cash payment of a dividend equivalent that is charged to retained earnings. Beginning in 2013, PSUs authorized for future grants will vest, absent employee election to defer, upon settlement following the conclusion of the three-year performance period. We recognize compensation expense over the period beginning on the date of authorization and ending on the conclusion of the performance period. PSUs are settled by issuing one share of ConocoPhillips common stock per unit.

The following summarizes our stock-settled Performance Share Program activity for the year ended December 31, 2018:


				Weighted-Average		Millions of Dollars

	Stock Units			Grant Date Fair Value		Total Fair Value


Outstanding at December 31, 2017		2,753,465			$ 50.79
Granted		19,708			53.28
Forfeited		(2,859	)		48.89
Issued		(434,772	)				$ 29

Outstanding at December 31, 2018		2,335,542			$ 50.45

Not Vested at December 31, 2018		58,914			$ 48.41

At December 31, 2018, the remaining unrecognized compensation cost from unvested stock-settled performance share awards was zero. The weighted-average grant date fair value of stock-settled PSUs granted during 2017 and 2016 was $49.76 and $33.13, respectively. The total fair value of stock-settled PSUs issued during 2017 and 2016 was $57 million and $17 million, respectively.

Cash-Settled

In connection with and immediately following the separation of our Downstream businesses in 2012, grants of new PSUs, subject to a shortened performance period, were authorized. Once granted, these PSUs vest, absent employee election to defer, on the earlier of five years after the grant date of the award or the date the employee becomes eligible for retirement. For employees eligible for retirement by or shortly after the grant date, we recognize compensation expense over the period beginning on the date of authorization and ending on the date of grant. Otherwise, we recognize compensation expense beginning on the grant date and ending on

the date the PSUs are scheduled to vest. These PSUs are settled in cash equal to the fair market value of a share of ConocoPhillips common stock per unit on the settlement date and thus are classified as liabilities on the balance sheet. Until settlement occurs, recipients of the PSUs receive a quarterly cash payment of a dividend equivalent that is charged to compensation expense.

Beginning in 2013, PSUs authorized for future grants will vest upon settlement following the conclusion of the three-year performance period. We recognize compensation expense over the period beginning on the date of authorization and ending at the conclusion of the performance period. These PSUs will be settled in cash equal to the fair market value of a share of ConocoPhillips common stock per unit on the settlement date and are classified as liabilities on the balance sheet. For performance periods beginning before 2018, during the performance period, recipients of the PSUs do not receive a quarterly cash payment of a dividend equivalent, but after the performance period ends, until settlement in cash occurs, recipients of the PSUs receive a quarterly cash payment of a dividend equivalent that is charged to compensation expense. For the performance period beginning in 2018, recipients of the PSUs receive an accrued reinvested dividend equivalent that is charged to compensation expense. The accrued reinvested dividend is paid at the time of settlement, subject to the terms and conditions of the award.

The following summarizes our cash-settled Performance Share Program activity for the year ended December 31, 2018:


				Weighted-Average		Millions of Dollars

	Stock Units			Grant Date Fair Value		Total Fair Value


Outstanding at December 31, 2017		1,214,533			$55.19
Granted		321,965			53.28
Forfeited		(9,282	)		59.17
Settled		(396,209	)				$22

Outstanding at December 31, 2018		1,131,007			$62.21

Not Vested at December 31, 2018		87,900			$62.21

At December 31, 2018, the remaining unrecognized compensation cost from unvested cash-settled performance share awards was $1 million, which will be recognized over a weighted-average period of 0.89 years, the longest period being 1.13 years. The weighted-average grant date fair value of cash-settled PSUs granted during 2017 and 2016 was $49.76 and $33.13, respectively. The total fair value of cash-settled performance share awards settled during 2017 and 2016 was $24 million and $31 million, respectively.

From inception of the Performance Share Program through 2013, approved PSU awards were granted after the conclusion of performance periods. Beginning in February 2014, initial target PSU awards are issued near the beginning of new performance periods. These initial target PSU awards will terminate at the end of the performance periods and will be settled after the performance periods have ended. Also in 2014, initial target PSU awards were issued for open performance periods that began in prior years. For the open performance period beginning in 2012, the initial target PSU awards terminated at the end of the three-year performance period and were replaced with approved PSU awards. For the open performance period beginning in 2013, the initial target PSU awards terminated at the end of the three-year performance period and were settled after the performance period ended. There is no effect on recognition of compensation expense.

Other—In addition to the above active programs, we have outstanding shares of restricted stock and restricted stock units that were either issued as part of our non-employee director compensation program for current and former members of the company’s Board of Directors or as part of an executive compensation program that has been discontinued. Generally, the recipients of the restricted shares or units receive a quarterly dividend or dividend equivalent.

The following summarizes the aggregate activity of these restricted shares and units for the year ended December 31, 2018:


				Weighted-Average		Millions of Dollars

	Stock Units			Grant Date Fair Value		Total Fair Value


Outstanding at December 31, 2017		1,301,040			$ 45.77
Granted		70,922			62.01
Cancelled		(1,334	)		23.09
Issued		(263,313	)				$ 17

Outstanding at December 31, 2018		1,107,315			$ 46.57

Not Vested at December 31, 2018		-

At December 31, 2018, all outstanding restricted stock and restricted stock units were fully vested and there was no remaining compensation cost to be recorded. The weighted-average grant date fair value of awards granted during 2017 and 2016 was $48.87 and $40.36, respectively. The total fair value of awards issued during 2017 and 2016 was $4 million and $2 million, respectively.

Note 19—Income Taxes

Income taxes charged to net income (loss) were:


	Millions of Dollars

	2018			2017			2016

Income Taxes
Federal
Current	$	4			79			(9	)
Deferred		545			(3,046	)		(1,634	)
Foreign
Current		3,273			1,729			393
Deferred		(166	)		(510	)		(519	)
State and local
Current		108			51			(135	)
Deferred		(96	)		(125	)		(67	)

	$	3,668			(1,822	)		(1,971	)

Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Major components of deferred tax liabilities and assets at December 31 were:


	Millions of Dollars

	2018			2017

Deferred Tax Liabilities
PP&E and intangibles	$	8,004			9,692
Inventory		60			61
Deferred state income tax		61			178
Other		156			464

Total deferred tax liabilities		8,281			10,395


Deferred Tax Assets
Benefit plan accruals		641			786
Asset retirement obligations and accrued environmental costs		2,891			3,060
Investments in joint ventures		104			57
Other financial accruals and deferrals		330			166
Loss and credit carryforwards		2,378			2,310
Other		398			152

Total deferred tax assets		6,742			6,531
Less: valuation allowance		(3,040	)		(1,254	)

Net deferred tax assets		3,702			5,277

Net deferred tax liabilities	$	4,579			5,118

At December 31, 2018, noncurrent assets and liabilities included deferred taxes of $442 million and $5,021 million, respectively. At December 31, 2017, noncurrent assets and liabilities included deferred taxes of $164 million and $5,282 million, respectively.

At December 31, 2018, the components of our loss and credit carryforwards before and after consideration of the applicable valuation allowances were:


	Millions of Dollars

	Gross Deferred Tax Asset		Net Deferred Tax Asset After Valuation Allowance		Expiration of Net Deferred Tax Asset


U.S. foreign tax credits	$	1,016		17		2027
U.S. general business credits		364		364		2036-2038
State net operating losses and tax credits		312		32		Various
Foreign net operating losses and tax credits		686		647		Post 2025

	$	2,378		1,060

Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than not, be realized. During 2018, valuation allowances increased a total of $1,786 million. The increase primarily relates to deferred tax assets recognized during 2018 as a result of the U.S. Tax Cuts and Jobs Act (Tax Legislation), as further discussed below, and are related to U.S. tax basis and foreign tax credits associated with our foreign branch assets that we do not expect to realize. Based on our historical taxable income, expectations for the future, and available tax-planning strategies, management expects deferred tax assets, net of valuation allowance, will primarily be realized as offsets to reversing deferred tax liabilities.

At December 31, 2018, unremitted income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures totaled approximately $3,808 million. Deferred income taxes have not been provided on this amount, as we do not plan to initiate any action that would require the payment of income taxes. The estimated amount of additional tax, primarily local withholding tax, that would be payable on this income if distributed is approximately $190 million.

The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2018, 2017 and 2016:


	Millions of Dollars

	2018			2017			2016


Balance at January 1	$	882			381			459
Additions based on tax positions related to the current year		268			612			32
Additions for tax positions of prior years		43			109			19
Reductions for tax positions of prior years		(73	)		(129	)		(118	)
Settlements		(35	)		(5	)		(9	)
Lapse of statute		(4	)		(86	)		(2	)

Balance at December 31	$	1,081			882			381

Included in the balance of unrecognized tax benefits for 2018, 2017 and 2016 were $1,081 million, $882 million and $359 million, respectively, which, if recognized, would impact our effective tax rate. The balance of the unrecognized tax benefits increased in 2018 mainly due to the treatment of distributions from certain of foreign subsidiaries. The balance of unrecognized tax benefits increased in 2017 mainly due to the recognition of a U.S. worthless securities deduction that we do not believe will generate a cash tax benefit.

At December 31, 2018, 2017 and 2016, accrued liabilities for interest and penalties totaled $45 million, $54 million and $54 million, respectively, net of accrued income taxes. Interest and penalties resulted in a benefit to earnings of $4 million in 2018, no impact to earnings in 2017, and a benefit to earnings of $18 million in 2016.

We file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions. Audits in major jurisdictions are generally complete as follows: United Kingdom (2015), Canada (2010), United States (2014) and Norway (2017). Issues in dispute for audited years and audits for subsequent years are ongoing and in various stages of completion in the many jurisdictions in which we operate around the world. Consequently, the balance in unrecognized tax benefits can be expected to fluctuate from period to period. It is reasonably possible such changes could be significant when compared with our total unrecognized tax benefits, but the amount of change is not estimable.

The amounts of U.S. and foreign income (loss) before income taxes, with a reconciliation of tax at the federal statutory rate with the provision for income taxes, were:


	Millions of Dollars									Percent of Pre-Tax Income (Loss)

	2018			2017			2016			2018			2017			2016

Income (loss) before income taxes
United States	$	2,867			(5,250	)		(4,410	)		28.7	%		200.8			79.7
Foreign		7,106			2,635			(1,120	)		71.3			(100.8	)		20.3

	$	9,973			(2,615	)		(5,530	)		100.0	%		100.0			100.0


Federal statutory income tax	$	2,095			(915	)		(1,936	)		21.0	%		35.0			35.0
Non-U.S. effective tax rates		1,766			625			361			17.7			(23.9	)		(6.5	)
Tax Legislation		(10	)		(852	)		-			(0.1	)		32.6			-
Canada disposition		-			(1,277	)		-			-			48.8			-
U.K. disposition		(150	)		-			-			(1.5	)		-			-
Recovery of outside basis		(21	)		(962	)		(60	)		(0.2	)		36.8			1.1
Adjustment to tax reserves		(4	)		881			55			-			(33.7	)		(1.0	)
Adjustment to valuation allowance		(26	)		-			-			(0.3	)		-			-
APLNG impairment		-			834			-			-			(31.9	)		-
State income tax		135			(84	)		(122	)		1.4			3.2			2.2
Enhanced oil recovery credit		(99	)		(68	)		(62	)		(1.0	)		2.6			1.1
U.K. rate change		-			-			(161	)		-			-			2.9
Other		(18	)		(4	)		(46	)		(0.2	)		0.2			0.8

	$	3,668			(1,822	)		(1,971	)		36.8	%		69.7			35.6

The decrease in the effective tax rate for 2018 was primarily due to the impact of the Clair Field disposition in the U.K. and our overall income position, partially offset by our mix of income among taxing jurisdictions.

Our effective tax rate for 2018 was favorably impacted by the sale of a ConocoPhillips subsidiary to BP. The subsidiary held a 16.5 percent interest in the BP-operated Clair Field in the United Kingdom. The disposition generated a before-tax gain of $715 million with no associated tax cost. See Note 5—Assets Held for Sale, Sold or Acquired and Other Planned Dispositions for additional information on the U.K. disposition.

Tax Legislation was enacted in the United States on December 22, 2017, reducing the U.S. federal corporate income tax rate to 21 percent from 35 percent, requiring companies to pay a one-time transition tax on earnings of certain foreign subsidiaries that were previously tax deferred and creating new taxes on certain foreign-sourced earnings.

SAB 118 measurement period

We applied the guidance in Staff Accounting Bulletin No. 118 when accounting for the enactment-date effects of Tax Legislation in 2017 and throughout 2018. At December 31, 2017, we had not completed our accounting for all the enactment-date income tax effects of Tax Legislation under ASC 740, Income Taxes, for the remeasurement of deferred tax assets and liabilities and the one-time transition tax. As of December 31, 2018, we have now completed our accounting for all the enactment-date income tax effects of Tax Legislation. As further discussed below, during 2018, we recognized adjustments of $10 million to the provisional amounts recorded at December 31, 2017, and included these adjustments as a component of income tax provision.

Provisional Amounts—Foreign tax effects

The one-time transition tax is based on our total post-1986 earnings, the tax on which we previously deferred from U.S. income taxes under U.S. law. We estimated at December 31, 2017, that we would not incur a one-time transition tax. Upon further analyses of Tax Legislation and Notices and regulations issued and proposed by the U.S. Department of the Treasury and the Internal Revenue Service, we finalized our calculations of the transition tax liability during 2018. Based upon this analysis, we did not incur a one-time transition tax.

As a result of the Tax Legislation, we removed the indefinite reinvestment assertion on one of our foreign subsidiaries and recorded a tax expense of $56 million in the fourth quarter of 2017.

Deferred tax assets and liabilities

As of December 31, 2017, we remeasured certain deferred tax assets and liabilities based on the rates at which they were expected to reverse in the future (which was generally 21 percent), by recording a provisional amount of $908 million. Upon further analysis of certain aspects of Tax Legislation and refinement of our calculations during the 12 months ended December 31, 2018, we adjusted our provisional amount by $10 million, which is included as a component of income tax expense.

Global intangible low-taxed income (GILTI)

We have elected to account for GILTI in the year the tax is incurred. At December 31, 2018, the current-year U.S. income tax impact related to GILTI activities is immaterial.

Our effective tax rate in 2017 was favorably impacted by a tax benefit of $1,277 million related to the Canada disposition. This tax benefit was primarily associated with a deferred tax recovery related to the Canadian capital gains exclusion component of the 2017 Canada disposition and the recognition of previously unrealizable Canadian capital asset tax basis. The Canada disposition, along with the associated restructuring of our Canadian operations, may generate an additional tax benefit of $822 million. However, since we believe it is not likely we will receive a corresponding cash tax savings, this $822 million benefit has been offset by a full tax reserve. See Note 5—Assets Held for Sale, Sold or Acquired and Other Planned Dispositions for additional information on our Canada disposition.

The impairment of our APLNG investment in the second quarter of 2017 did not generate a tax benefit. See the “APLNG” section of Note 6—Investments, Loans and Long-Term Receivables, for information on the impairment of our APLNG investment.

The decrease in the effective tax rate for 2016 was primarily due to our mix of income among taxing jurisdictions, reduced net tax benefit from the tax law changes discussed below, and the absence of a tax benefit associated with electing the fair market value method of apportioning interest expense for prior years.

In the United Kingdom, legislation was enacted on September 15, 2016, to decrease the overall U.K. upstream corporation tax rate from 50 percent to 40 percent effective January 1, 2016. As a result, we recorded a $161 million net tax benefit related to the remeasurement of our U.K. deferred tax balance in 2016.

Certain operating losses in jurisdictions outside of the United States only yield a tax benefit in the United States as a worthless security deduction. For 2018, 2017 and 2016, before consideration of unrecorded tax benefits discussed above, the amount of the tax benefit was $36 million, $962 million and $60 million, respectively.

Note 20—Accumulated Other Comprehensive Loss

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


	Millions of Dollars

	Defined Benefit Plans		Net Unrealized Loss on Securities		Foreign Currency Translation		Accumulated Other Comprehensive Loss


December 31, 2015	$	(443)		-		(5,804)		(6,247)
Other comprehensive income (loss)		(104)		-		158		54

December 31, 2016		(547)		-		(5,646)		(6,193)
Other comprehensive income (loss)		147		(58)		586		675

December 31, 2017		(400)		(58)		(5,060)		(5,518)
Other comprehensive income (loss)		39		-		(642)		(603)
Cumulative effect of adopting ASU No. 2016-01*		-		58		-		58

December 31, 2018	$	(361)		-		(5,702)		(6,063)

*See Note 2—Changes in Accounting Principles for additional information.

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

The following table summarizes reclassifications out of accumulated other comprehensive loss during the years ended December 31:


	Millions of Dollars

	2018		2017


Defined Benefit Plans	$	189		135

Above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of:	$	50		74

See Note 18—Employee Benefit Plans, for additional information.

Note 21—Cash Flow Information


	Millions of Dollars

	2018			2017			2016

Noncash Investing Activities
Increase (decrease) in PP&E related to an increase (decrease) in asset retirement obligations	$	395			(37	)		(1,017	)
Increase (decrease) in assets and liabilities acquired in a nonmonetary exchange*
Accounts receivable		(44	)		-			-
Inventories		42			-			-
Investments and long-term receivables		15			-			-
PP&E		1,907			-			-
Other long-term assets		(9	)		-			-
Accounts payable		7			-			-
Accrued income and other taxes		40			-			-


Cash Payments (Receipts)
Interest	$	772			1,163			1,151
Income taxes		2,976			1,168			(318	)**


Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased	$	(1,953	)		(6,617	)		(1,753	)
Short-term investments sold		3,573			4,827			1,702

	$	1,620			(1,790	)		(51	)

*See Note 5—Assets Held for Sale, Sold, or Acquired and Other Planned Dispositions.

**2016 is net of $585 million related to refunds received from the Internal Revenue Service.

The following items are included in in the “Cash Flows from Operating Activities” section of our consolidated cash flows.

In 2018, we collected $430 million from PDVSA consisting of $230 million from the sale of commodity inventory and $200 million in cash, as partial payments related to an award issued by the ICC Tribunal in 2018. We collected $262 million and $75 million from Ecuador in 2018 and 2017, respectively, as installment payments related to an agreement reached with Ecuador in 2017. For more information on these settlements, see Note 13—Contingencies and Commitments.

We made discretionary payments to our domestic qualified pension plan of $120 million and $600 million in 2018 and 2017, respectively.

In 2017, we recognized a $180 million adverse cash impact from the settlement of cross-currency swap transactions.

Note 22—Other Financial Information


	Millions of Dollars

	2018		2017		2016

Interest and Debt Expense
Incurred
Debt	$	838		1,114		1,279
Other		67		103		123

		905		1,217		1,402
Capitalized		(170)		(119)		(157)

Expensed	$	735		1,098		1,245


Other Income
Interest income	$	97		112		57
Other, net		76		417		198

	$	173		529		255


Research and Development Expenditures—expensed	$	78		100		116


Shipping and Handling Costs*	$	1,075		1,050		1,140

*Amounts included in production and operating expenses. 2017 and 2016 have been reclassified to conform to the current-period presentation resulting from the adoption of ASU No. 2017-07. See Note 2—Changes in Accounting Principles, for additional information.

Foreign Currency Transaction (Gains) Losses—after-tax
Alaska	$	-		-		-
Lower 48		-		-		-
Canada		(11)		3		1
Europe and North Africa		(26)		7		(7)
Asia Pacific and Middle East		3		23		(9)
Other International		-		1		7
Corporate and Other		21		(3)		(18)

	$	(13)		31		(26)


	Millions of Dollars

	2018		2017

Properties, Plants and Equipment
Proved properties	$	100,657		102,044
Unproved properties		4,662		4,491
Other		5,278		3,896

Gross properties, plants and equipment		110,597		110,431
Less: Accumulated depreciation, depletion and amortization		(64,899)		(64,748)

Net properties, plants and equipment	$	45,698		45,683

Note 23—Related Party Transactions

Our related parties primarily include equity method investments and certain trusts for the benefit of employees.

Significant transactions with our equity affiliates were:


	Millions of Dollars
		2018		2017		2016


Operating revenues and other income	$	98		107		133
Purchases		98		99		101
Operating expenses and selling, general and administrative expenses		60		59		63
Net interest (income) expense*		(14	)	(13	)	(12	)

*We paid interest to, or received interest from, various affiliates. See Note 6—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

The table above includes transactions with the FCCL Partnership through the date of the sale. See Note 6—Investments, Loans and Long-Term Receivables, for additional information.

Note 24—Sales and Other Operating Revenues

Transitional Arrangements

We adopted the provisions of ASC Topic 606 beginning January 1, 2018, using the modified retrospective approach, which we have applied to contracts within the scope of the standard that had not been completed as of January 1, 2018. Results for reporting periods beginning after January 1, 2018, are presented under ASC Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with ASC Topic 605. See Note 2—Changes in Accounting Principles for the effect on our consolidated balance sheet and the line items which have been impacted by the adoption of this standard.

The cumulative effect of applying the standard relates solely to certain licensing arrangements where revenue was previously recognized ($61 million in 2011, $146 million in 2015, and $44 million in 2017) based on contractual milestones. Under ASC Topic 606, such revenues are recognized when the customer has the ability to utilize and benefit from its right to use the license. As a result, such historically recognized revenues must be reversed through a cumulative effect adjustment and deferred until such time when the customer has the ability to utilize and benefit from the license. The cumulative effect adjustment relates to contracts that were not substantially completed at the date of implementation.

Practical Expedients

Typically, our commodity sales contracts are less than 12 months in duration; however, certain commodity sales contracts may carry a longer duration, which may extend to the end of field life. We have long-term commodity sales contracts which use prevailing market prices at the time of delivery, and under these contracts, the market-based variable consideration for each performance obligation (i.e., delivery of commodity) is allocated to each wholly unsatisfied performance obligation within the contract. Accordingly, we have applied the practical expedient allowed in ASC Topic 606 and do not disclose the aggregate amount of the transaction price allocated to performance obligations or when we expect to recognize revenues that are unsatisfied (or partially unsatisfied) as of the end of the reporting period.

Revenue from Contracts with Customers

The following table provides further disaggregation of our consolidated sales and other operating revenues:


	Millions of Dollars
		2018	2017	*	2016	*

Revenue from contracts with customers	$	28,098	20,525		16,527
Revenue from contracts outside the scope of ASC Topic 606
Physical contracts meeting the definition of a derivative		8,218	8,669		7,278
Financial derivative contracts		101	(88	)	(112	)

Consolidated sales and other operating revenues	$	36,417	29,106		23,693

*Under the modified retrospective approach, prior period amounts have not been adjusted upon adoption of ASC Topic 606.

Revenues from contracts outside the scope of ASC Topic 606 relate primarily to physical gas contracts at market prices which qualify as derivatives accounted for under ASC Topic 815, “Derivatives and Hedging,” and for which we have not elected normal purchases and normal sales (NPNS). There is no significant difference in contractual terms or the policy for recognition of revenue from these contracts and those within the scope of ASC Topic 606. The following disaggregation of revenues is provided in conjunction with Note 25—Segment Disclosures and Related Information:


	Millions of Dollars
		2018	2017	*	2016	*

Revenue from Outside the Scope of ASC Topic 606 by Segment
Lower 48	$	6,358	6,302		5,391
Canada		629	864		813
Europe and North Africa		1,231	1,503		1,074

Physical contracts meeting the definition of a derivative	$	8,218	8,669		7,278

*Under the modified retrospective approach, prior period amounts have not been adjusted upon adoption of ASC Topic 606.


	Millions of Dollars
		2018	2017	*	2016	*

Revenue from Outside the Scope of ASC Topic 606 by Product
Crude oil	$	1,112	588		436
Natural gas		6,734	7,811		6,502
Other		372	270		340

Physical contracts meeting the definition of a derivative	$	8,218	8,669		7,278

*Under the modified retrospective approach, prior period amounts have not been adjusted upon adoption of ASC Topic 606.

Receivables and Contract Liabilities

Receivables from Contracts with Customers

At December 31, 2018, the “Accounts and notes receivable” line on our consolidated balance sheet included trade receivables of $2,889 million compared with $2,675 million at December 31, 2017, and included both contracts with customers within the scope of ASC Topic 606 and those that are outside the scope of ASC Topic 606. We typically receive payment within 30 days or less (depending on the terms of the invoice) once delivery is made. Revenues that are outside the scope of ASC Topic 606 relate primarily to physical gas sales contracts at market prices for which we do not elect NPNS and are therefore accounted for as a derivative

under ASC Topic 815. There is little distinction in the nature of the customer or credit quality of trade receivables associated with gas sold under contracts for which NPNS has not been elected compared with trade receivables where NPNS has been elected.

Contract Liabilities from Contracts with Customers

We have entered into contractual arrangements where we license proprietary technology to customers related to the optimization process for operating LNG plants. The agreements typically provide for negotiated payments to be made at stated milestones. The payments are not directly related to our performance under the contract and are recorded as deferred revenue to be recognized as revenue when the customer can utilize and benefit from their right to use the license. Payments are received in installments over the construction period.


	Millions of Dollars

Contract Liabilities
At January 1, 2018	$	251
Contractual payments received		103
Revenue recognized		(148	)

At December 31, 2018	$	206


Amounts Recognized in the Consolidated Balance Sheet at December 31, 2018
Current liabilities	$	169
Noncurrent liabilities		37

	$	206

During 2018, we recognized revenue of $148 million in the “Sales and other operating revenues” line on our consolidated income statement. We expect to recognize the contract liabilities as of December 31, 2018, as revenue between the remainder of 2019 and 2022 as construction is completed.

Prior to the adoption of ASC Topic 606, contractual cash payments received were recognized as “Sales and other operating revenues” when received.

Note 25—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 and North Africa, Asia Pacific and Middle East, and Other International.

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

We evaluate performance and allocate resources based on net income (loss) attributable to ConocoPhillips. Segment accounting policies are the same as those in Note 1—Accounting Policies. Intersegment sales are at prices that approximate market.

Analysis of Results by Operating Segment


		Millions of Dollars

		2018	2017	2016

Sales and Other Operating Revenues
Alaska	$	5,740	4,224	3,681

Lower 48		17,029	12,968	10,719
Intersegment eliminations		(40)	(4)	(17)

Lower 48		16,989	12,964	10,702

Canada		3,184	3,178	2,192
Intersegment eliminations		(1,160)	(559)	(218)

Canada		2,024	2,619	1,974

Europe and North Africa		6,635	5,181	3,462
Asia Pacific and Middle East		4,861	4,014	3,705
Corporate and Other		168	104	169

Consolidated sales and other operating revenues	$	36,417	29,106	23,693


Depreciation, Depletion, Amortization and Impairments
Alaska	$	760	1,026	868
Lower 48		2,370	6,693	4,358
Canada		324	461	975
Europe and North Africa		1,041	1,313	1,253
Asia Pacific and Middle East		1,382	3,819	1,606
Other International		-	-	1
Corporate and Other		106	134	140

Consolidated depreciation, depletion, amortization and impairments	$	5,983	13,446	9,201

In 2018, sales by our Lower 48, Alaska and Canada segments to a certain refining company accounted for approximately $4 billion or 11 percent of our total consolidated sales and other operating revenues.


		Millions of Dollars

		2018		2017		2016

Equity in Earnings of Affiliates
Alaska	$	6		7		9
Lower 48		1		5		(6	)
Canada		-		197		89
Europe and North Africa		16		10		22
Asia Pacific and Middle East		1,051		553		(51	)
Other International		-		-		-
Corporate and Other		-		-		(11	)

Consolidated equity in earnings of affiliates	$	1,074		772		52


Income Taxes
Alaska	$	376		(689	)	(59	)
Lower 48		474		(2,453	)	(1,328	)
Canada		(96	)	(616	)	(383	)
Europe and North Africa		2,265		1,165		(46	)
Asia Pacific and Middle East		722		351		306
Other International		30		21		(40	)
Corporate and Other		(103	)	399		(421	)

Consolidated income taxes	$	3,668		(1,822	)	(1,971	)


Net Income (Loss) Attributable to ConocoPhillips
Alaska	$	1,814		1,466		319
Lower 48		1,747		(2,371	)	(2,257	)
Canada		63		2,564		(935	)
Europe and North Africa		1,866		553		394
Asia Pacific and Middle East		2,070		(1,098	)	209
Other International		364		167		(16	)
Corporate and Other		(1,667	)	(2,136	)	(1,329	)

Consolidated net income (loss) attributable to ConocoPhillips	$	6,257		(855	)	(3,615	)


Investments in and Advances to Affiliates
Alaska	$	86		56		58
Lower 48		378		402		426
Canada		-		-		8,784
Europe and North Africa		55		55		62
Asia Pacific and Middle East		8,821		9,077		11,611
Other International		-		-		-
Corporate and Other		-		-		4

Consolidated investments in and advances to affiliates	$	9,340		9,590		20,945


		Millions of Dollars

		2018	2017	2016

Total Assets
Alaska	$	14,648	12,108	12,314
Lower 48		14,888	14,632	22,673
Canada		5,748	6,214	17,548
Europe and North Africa		9,883	11,870	11,727
Asia Pacific and Middle East		16,151	16,985	20,451
Other International		89	97	97
Corporate and Other		8,573	11,456	4,962

Consolidated total assets	$	69,980	73,362	89,772


Capital Expenditures and Investments
Alaska	$	1,298	815	883
Lower 48		3,184	2,136	1,262
Canada		477	202	698
Europe and North Africa		877	872	1,020
Asia Pacific and Middle East		718	482	838
Other International		6	21	104
Corporate and Other		190	63	64

Consolidated capital expenditures and investments	$	6,750	4,591	4,869


Interest Income and Expense
Interest income
Corporate	$	80	101	47
Lower 48		-	-	-
Europe and North Africa		2	2	2
Asia Pacific and Middle East		15	9	8
Other International		-	-	-

Interest and debt expense Corporate	$	735	1,098	1,245


Sales and Other Operating Revenues by Product
Crude oil	$	19,571	13,260	10,801
Natural gas		10,720	10,773	9,401
Natural gas liquids		1,114	1,102	837
Other*		5,012	3,971	2,654

Consolidated sales and other operating revenues by product	$	36,417	29,106	23,693

*Includes LNG and bitumen.

Geographic Information


		Millions of Dollars

		Sales and Other Operating Revenues(1)			Long-Lived Assets(2)

		2018	2017	2016	2018	2017	2016

United States	$	22,740	17,204	14,400	26,838	23,623	32,949
Australia(3)		1,798	1,448	1,353	9,301	9,657	12,259
Canada		2,024	2,619	1,974	5,333	5,613	16,846
China		836	712	551	1,380	1,275	1,372
Indonesia		886	757	938	669	758	856
Libya(4)		1,142	586	-	679	699	704
Malaysia		1,346	1,103	735	2,327	2,736	3,323
Norway		2,886	2,348	1,645	5,582	6,154	6,228
United Kingdom		2,606	2,248	1,816	1,583	3,335	3,209
Other foreign countries		153	81	281	1,346	1,423	1,530

Worldwide consolidated	$	36,417	29,106	23,693	55,038	55,273	79,276

(1)Sales and other operating revenues are attributable to countries based on the location of the selling operation.

(2)Defined as net PP&E plus investments in and advances to affiliated companies.

(3)Includes amounts related to the joint petroleum development area with shared ownership held by Australia and Timor-Leste.

(4)Included in “Other foreign countries” in prior periods.

Note 26—New Accounting Standards

In February 2016, the FASB issued ASU No. 2016-02, “Leases” (ASU No. 2016-02), which establishes comprehensive accounting and financial reporting requirements for leasing arrangements. This ASU supersedes the existing requirements in FASB ASC Topic 840, “Leases” (FASB ASC Topic 840), and requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheet. The provisions of ASU No. 2016-02 also modify the definition of a lease and outline requirements for recognition, measurement, presentation and disclosure of leasing arrangements by both lessees and lessors. The ASU is effective for interim and annual periods beginning after December 15, 2018, and early adoption of the standard is permitted. Entities are required to adopt the ASU using a modified retrospective approach, subject to certain optional practical expedients, and apply the provisions of ASU No. 2016-02 to leasing arrangements existing at or entered into after the earliest comparative period presented in the financial statements.

ASU No. 2016-02 was amended in January 2018 by the provisions of ASU No. 2018-01, “Land Easement Practical Expedient for Transition to Topic 842” (ASU No. 2018-01), and in July 2018 by the provisions of ASU No. 2018-10, “Codification Improvements to Topic 842, Leases” (ASU No. 2018-10). In addition, ASU No. 2016-02 was further amended in July 2018 by the provisions of ASU No. 2018-11, “Targeted Improvements” (ASU No. 2018-11), and in December 2018 by the provisions of ASU No. 2018-20, “Narrow-Scope Improvements for Lessors” (ASU No. 2018-20).

ASU No. 2018-11 sets forth certain additional practical expedients for lessors and provides entities with an option to apply the provisions of ASU No. 2016-02, as amended, to leasing arrangements existing at or entered into after the ASU’s effective date of adoption (the “Optional Transition Method”). Entities that elect to utilize the Optional Transition Method would not apply the provisions of ASU No. 2016-02, as amended, to comparative periods presented in the financial statements.

We plan to adopt ASU No. 2016-02, as amended, effective January 1, 2019, utilizing the Optional Transition Method. Accordingly, the comparative periods presented in the financial statements prior to January 1, 2019, will be presented pursuant to the existing requirements of FASB ASC Topic 840 and not be adjusted upon the adoption of the ASU. We also expect to utilize the package of optional transition-related practical expedients set forth by ASU No. 2016-02, as amended, which permit entities to not reassess upon the adoption of the ASU

certain historical conclusions regarding lease contract identification and classification, as well as the historical accounting treatment of initial direct costs (the “Package of Optional Practical Expedients”). For lease arrangements containing both lease and non-lease components, we will adopt the optional practical expedient to not separate lease components from non-lease components for all new or modified leases executed on or after the effective date of the ASU, subject to making any elections for leases after the effective date in new asset classes. Furthermore, we do not expect to record assets and liabilities on our consolidated balance sheet for new or existing lease arrangements with terms of 12 months or less.

The expected impact of the adoption of ASU No. 2016-02, as amended, relates primarily to our balance sheet, resulting from the initial recognition of lease liabilities and corresponding right-of-use assets for our existing population of operating leases, as well as enhanced disclosure of our leasing arrangements. We expect to recognize on our consolidated balance sheet approximately $1 billion of operating lease liabilities and corresponding right-of-use assets upon the adoption of ASU No. 2016-02, as amended. We have implemented a third-party lease accounting software solution to facilitate the ongoing accounting and financial reporting requirements of the ASU and also expect the adoption of the ASU to result in certain changes being made to our existing accounting policies and systems, business processes, and internal controls.

While our evaluation of ASU No. 2016-02, as amended, and related implementation activities approach completion, we continue to monitor proposals issued by the FASB to clarify the ASU.

In June 2016, the FASB issued ASU No. 2016-13, “Measurement of Credit Losses on Financial Instruments” (ASU No. 2016-13), which sets forth the current expected credit loss model, a new forward-looking impairment model for certain financial instruments based on expected losses rather than incurred losses. The ASU is effective for interim and annual periods beginning after December 15, 2019, and early adoption of the standard is permitted. Entities are required to adopt ASU No. 2016-13 using a modified retrospective approach, subject to certain limited exceptions. We are currently evaluating the impact of the adoption of this ASU.

Oil and Gas Operations (Unaudited)

In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic 932, “Extractive Activities—Oil and Gas,” and regulations of the U.S. Securities and Exchange Commission (SEC), we are making certain supplemental disclosures about our oil and gas exploration and production operations.

These disclosures include information about our consolidated oil and gas activities and our proportionate share of our equity affiliates’ oil and gas activities in our operating segments. As a result, amounts reported as equity affiliates in Oil and Gas Operations may differ from those shown in the individual segment disclosures reported elsewhere in this report.

As required by current authoritative guidelines, the estimated future date when an asset will be permanently shut down for economic reasons is based on historical 12-month first-of-month average prices and current costs. This estimated date when production will end affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Generally, our proved reserves decrease as prices decline and increase as prices rise.

Our proved reserves include estimated quantities related to production sharing contracts (PSCs), which are reported under the “economic interest” method, as well as variable-royalty regimes, and are subject to fluctuations in commodity prices, recoverable operating expenses and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. For example, if prices increase, then our applicable reserve quantities would decline. At December 31, 2018, approximately 6 percent of our total proved reserves were under PSCs, located in our Asia Pacific/Middle East geographic reporting area, and 5 percent of our total proved reserves were under a variable-royalty regime, located in our Canada geographic reporting area.

Our reserves disclosures by geographic area include the United States, Canada, Europe (Norway and the United Kingdom), Asia Pacific/Middle East, and Africa.

Reserves Governance

The recording and reporting of proved reserves are governed by criteria established by regulations of the SEC and FASB. Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain it will commence the project within a reasonable time.

Proved reserves are further classified as either developed or undeveloped. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared with the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are proved reserves expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

We have a companywide, comprehensive, SEC-compliant internal policy that governs the determination and reporting of proved reserves. This policy is applied by the geoscientists and reservoir engineers in our business units around the world. As part of our internal control process, each business unit’s reserves

processes and controls are reviewed annually by an internal team which is headed by the company’s Manager of Reserves Compliance and Reporting. This team, composed of internal reservoir engineers, geoscientists, finance personnel and a senior representative from DeGolyer and MacNaughton (D&M), a third-party petroleum engineering consulting firm, reviews the business units’ reserves for adherence to SEC guidelines and company policy through on-site visits, teleconferences and review of documentation. In addition to providing independent reviews, this internal team also ensures reserves are calculated using consistent and appropriate standards and procedures. This team is independent of business unit line management and is responsible for reporting its findings to senior management. The team is responsible for communicating our reserves policy and procedures and is available for internal peer reviews and consultation on major projects or technical issues throughout the year. All of our proved reserves held by consolidated companies and our share of equity affiliates have been estimated by ConocoPhillips.

During 2018, our processes and controls used to assess over 90 percent of proved reserves as of December 31, 2018, were reviewed by D&M. The purpose of their review was to assess whether the adequacy and effectiveness of our internal processes and controls used to determine estimates of proved reserves are in accordance with SEC regulations. In such review, ConocoPhillips’ technical staff presented D&M with an overview of the reserves data, as well as the methods and assumptions used in estimating reserves. The data presented included pertinent seismic information, geologic maps, well logs, production tests, material balance calculations, reservoir simulation models, well performance data, operating procedures and relevant economic criteria. Management’s intent in retaining D&M to review its processes and controls was to provide objective third-party input on these processes and controls. D&M’s opinion was the general processes and controls employed by ConocoPhillips in estimating its December 31, 2018, proved reserves for the properties reviewed are in accordance with the SEC reserves definitions. D&M’s report is included as Exhibit 99 of this Annual Report on Form 10-K.

The technical person primarily responsible for overseeing the processes and internal controls used in the preparation of the company’s reserves estimates is the Manager of Reserves Compliance and Reporting. This individual holds a master’s degree in petroleum engineering. He is a member of the Society of Petroleum Engineers with over 25 years of oil and gas industry experience and has held positions of increasing responsibility in reservoir engineering, subsurface and asset management in the United States and several international field locations.

Engineering estimates of the quantities of proved reserves are inherently imprecise. See the “Critical Accounting Estimates” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional discussion of the sensitivities surrounding these estimates.

Proved Reserves


Years Ended	Crude Oil
December 31	Millions of Barrels
	Alaska		Lower 48		Total U.S.		Canada		Europe		Asia Pacific/ Middle East		Africa		Total
Developed and Undeveloped
Consolidated operations
End of 2015	915		588		1,503		14		346		203		204		2,270
Revisions	(57	)	(93	)	(150	)	3		-		6		-		(141	)
Improved recovery	6		3		9		-		-		7		-		16
Purchases	-		-		-		-		-		-		-		-
Extensions and discoveries	33		79		112		-		-		7		-		119
Production	(60	)	(71	)	(131	)	(3	)	(43	)	(35	)	(1	)	(213	)
Sales	-		-		-		(1	)	-		(3	)	-		(4	)

End of 2016	837		506		1,343		13		303		185		203		2,047
Revisions	113		65		178		1		38		32		-		249
Improved recovery	6		-		6		-		-		-		-		6
Purchases	-		-		-		-		-		-		-		-
Extensions and discoveries	41		210		251		-		-		2		-		253
Production	(60	)	(64	)	(124	)	(1	)	(45	)	(34	)	(7	)	(211	)
Sales	-		(10	)	(10	)	(12	)	-		-		-		(22	)

End of 2017	937		707		1,644		1		296		185		196		2,322
Revisions	72		(90	)	(18	)	2		24		6		5		19
Improved recovery	2		-		2		-		-		-		-		2
Purchases	233		1		234		-		-		-		-		234
Extensions and discoveries	48		179		227		2		2		1		-		232
Production	(59	)	(82	)	(141	)	(1	)	(40	)	(33	)	(13	)	(228	)
Sales	-		(12	)	(12	)	-		(36	)	-		-		(48	)

End of 2018	1,233		703		1,936		4		246		159		188		2,533


Equity affiliates
End of 2015	-		-		-		-		-		93		-		93
Revisions	-		-		-		-		-		-		-		-
Improved recovery	-		-		-		-		-		-		-		-
Purchases	-		-		-		-		-		-		-		-
Extensions and discoveries	-		-		-		-		-		-		-		-
Production	-		-		-		-		-		(5	)	-		(5	)
Sales	-		-		-		-		-		-		-		-

End of 2016	-		-		-		-		-		88		-		88
Revisions	-		-		-		-		-		-		-		-
Improved recovery	-		-		-		-		-		-		-		-
Purchases	-		-		-		-		-		-		-		-
Extensions and discoveries	-		-		-		-		-		-		-		-
Production	-		-		-		-		-		(5	)	-		(5	)
Sales	-		-		-		-		-		-		-		-

End of 2017	-		-		-		-		-		83		-		83
Revisions	-		-		-		-		-		-		-		-
Improved recovery	-		-		-		-		-		-		-		-
Purchases	-		-		-		-		-		-		-		-
Extensions and discoveries	-		-		-		-		-		-		-		-
Production	-		-		-		-		-		(5	)	-		(5	)
Sales	-		-		-		-		-		-		-		-

End of 2018	-		-		-		-		-		78		-		78


Total company
End of 2015	915		588		1,503		14		346		296		204		2,363
End of 2016	837		506		1,343		13		303		273		203		2,135
End of 2017	937		707		1,644		1		296		268		196		2,405
End of 2018	1,233		703		1,936		4		246		237		188		2,611


Years Ended	Crude Oil
December 31	Millions of Barrels
	Alaska	Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Total
Developed
Consolidated operations
End of 2015	819	283	1,102	13	200	139	204	1,658
End of 2016	747	256	1,003	13	184	106	203	1,509
End of 2017	828	315	1,143	1	190	121	196	1,651
End of 2018	1,058	346	1,404	2	192	113	185	1,896


Equity affiliates
End of 2015	-	-	-	-	-	93	-	93
End of 2016	-	-	-	-	-	88	-	88
End of 2017	-	-	-	-	-	83	-	83
End of 2018	-	-	-	-	-	78	-	78


Undeveloped
Consolidated operations
End of 2015	96	305	401	1	146	64	-	612
End of 2016	90	250	340	-	119	79	-	538
End of 2017	109	392	501	-	106	64	-	671
End of 2018	175	357	532	2	54	46	3	637


Equity affiliates
End of 2015	-	-	-	-	-	-	-	-
End of 2016	-	-	-	-	-	-	-	-
End of 2017	-	-	-	-	-	-	-	-
End of 2018	-	-	-	-	-	-	-	-

Notable changes in proved crude oil reserves in the three years ended December 31, 2018, included:

	•		Revisions: In 2018, downward revisions in Lower 48 were primarily due to changes in development timing for specific well locations from the unconventional plays and are more than offset by increases in planned well locations in the unconventional plays in the extensions and discoveries category. Downward revisions in Lower 48 due to development timing were partially offset by higher prices. Revisions in Alaska, Europe and Asia Pacific/Middle East were primarily due to higher prices. In 2017, revisions in Alaska, Lower 48, Europe and Asia Pacific/Middle East were primarily due to higher prices. In 2016, revisions in Lower 48 and Alaska were primarily due to lower prices.

	•		Purchases_:_ In 2018, Alaska purchases were due to the Kuparuk Assets and Western North Slope acquisitions.

	•		Extensions and discoveries: In 2018, extensions and discoveries in Lower 48 were primarily due to changes in the development strategy to add specific well locations from the unconventional plays. Extensions and discoveries in Alaska were driven by drilling success in Western North Slope. In 2017, extensions and discoveries in Lower 48 were primarily due to continued drilling success in the Permian Unconventional, Eagle Ford and Bakken. In 2016, extensions and discoveries in Alaska were primarily due to drilling success in the Western North Slope, and extensions and discoveries in Lower 48 were primarily due to continued drilling success in Eagle Ford and Bakken.

	•		Sales: In 2018, Europe sales were due to the disposition of a subsidiary that held a 16.5 percent interest in the Clair Field in the United Kingdom. In 2017, Canada sales were due to the disposition of a majority of our western Canada assets.


Years Ended	Natural Gas Liquids
December 31	Millions of Barrels
	Alaska		Lower 48		Total U.S.		Canada		Europe		Asia Pacific/ Middle East		Total
Developed and Undeveloped
Consolidated operations
End of 2015	114		321		435		45		20		8		508
Revisions	(3	)	(29	)	(32	)	9		2		-		(21	)
Improved recovery	-		-		-		-		-		-		-
Purchases	-		-		-		-		-		-		-
Extensions and discoveries	-		18		18		2		-		-		20
Production	(4	)	(32	)	(36	)	(8	)	(3	)	(3	)	(50	)
Sales	-		-		-		-		-		-		-

End of 2016	107		278		385		48		19		5		457
Revisions	4		29		33		-		2		1		36
Improved recovery	-		-		-		-		-		-		-
Purchases	-		-		-		-		-		-		-
Extensions and discoveries	-		71		71		-		-		1		72
Production	(5	)	(24	)	(29	)	(3	)	(3	)	(2	)	(37	)
Sales	-		(130	)	(130	)	(44	)	-		-		(174	)

End of 2017	106		224		330		1		18		5		354
Revisions	5		(25	)	(20	)	-		1		(1	)	(20	)
Improved recovery	-		-		-		-		-		-		-
Purchases	-		-		-		-		-		-		-
Extensions and discoveries	-		69		69		-		1		-		70
Production	(5	)	(25	)	(30	)	-		(3	)	(1	)	(34	)
Sales	-		(21	)	(21	)	-		-		-		(21	)

End of 2018	106		222		328		1		17		3		349


Equity affiliates
End of 2015	-		-		-		-		-		50		50
Revisions	-		-		-		-		-		-		-
Improved recovery	-		-		-		-		-		-		-
Purchases	-		-		-		-		-		-		-
Extensions and discoveries	-		-		-		-		-		-		-
Production	-		-		-		-		-		(3	)	(3	)
Sales	-		-		-		-		-		-		-

End of 2016	-		-		-		-		-		47		47
Revisions	-		-		-		-		-		-		-
Improved recovery	-		-		-		-		-		-		-
Purchases	-		-		-		-		-		-		-
Extensions and discoveries	-		-		-		-		-		-		-
Production	-		-		-		-		-		(2	)	(2	)
Sales	-		-		-		-		-		-		-

End of 2017	-		-		-		-		-		45		45
Revisions	-		-		-		-		-		-		-
Improved recovery	-		-		-		-		-		-		-
Purchases	-		-		-		-		-		-		-
Extensions and discoveries	-		-		-		-		-		-		-
Production	-		-		-		-		-		(3	)	(3	)
Sales	-		-		-		-		-		-		-

End of 2018	-		-		-		-		-		42		42


Total company
End of 2015	114		321		435		45		20		58		558
End of 2016	107		278		385		48		19		52		504
End of 2017	106		224		330		1		18		50		399
End of 2018	106		222		328		1		17		45		391


Years Ended	Natural Gas Liquids
December 31	Millions of Barrels
		Alaska	Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Total
Developed
Consolidated operations
End of 2015		114	235	349	45	16	8	418
End of 2016		107	209	316	47	15	5	383
End of 2017		106	101	207	1	16	2	226
End of 2018		106	97	203	-	15	3	221

Equity affiliates
End of 2015		-	-	-	-	-	50	50
End of 2016		-	-	-	-	-	47	47
End of 2017		-	-	-	-	-	45	45
End of 2018		-	-	-	-	-	42	42

Undeveloped
Consolidated operations
End of 2015		-	86	86	-	4	-	90
End of 2016		-	69	69	1	4	-	74
End of 2017		-	123	123	-	2	3	128
End of 2018		-	125	125	1	2	-	128

Equity affiliates
End of 2015		-	-	-	-	-	-	-
End of 2016		-	-	-	-	-	-	-
End of 2017		-	-	-	-	-	-	-
End of 2018		-	-	-	-	-	-	-

Notable changes in proved natural gas liquids reserves in the three years ended December 31, 2018, included:

	•		Revisions: In 2018, downward revisions in Lower 48 were primarily due to changes in development timing for specific well locations from the unconventional plays and are more than offset by increases in planned well locations in the unconventional plays in the extensions and discoveries category. In 2017, revisions in Lower 48 were primarily due to higher prices.

	•		Extensions and discoveries: In 2018, extensions and discoveries in Lower 48 were primarily due to changes in the development strategy to add specfic well locations from the unconventional plays. In 2017, extensions and discoveries in Lower 48 were primarily due to continued drilling success in the Permian Unconventional, Eagle Ford and Bakken.

	•		Sales: In 2018, Lower 48 sales were primarily due to the disposition of our interests in the Barnett. In 2017, Lower 48 sales were due to the disposition of our interests in the San Juan Basin and Panhandle assets, while Canada sales were due to the disposition of a majority of our western Canada assets.


Years Ended	Natural Gas

December 31	Billions of Cubic Feet

		Alaska		Lower 48		Total U.S.		Canada		Europe		Asia Pacific/ Middle East		Africa		Total

Developed and Undeveloped
Consolidated operations
End of 2015		2,347		5,171		7,518		1,107		1,359		1,713		227		11,924
Revisions		(105	)	(124	)	(229	)	111		56		18		-		(44)
Improved recovery		-		-		-		-		-		1		-		1
Purchases		-		-		-		1		-		-		-		1
Extensions and discoveries		2		162		164		43		-		124		-		331
Production		(73	)	(494	)	(567	)	(192	)	(177	)	(288	)	-		(1,224)
Sales		(69	)	(1	)	(70	)	(33	)	-		(42	)	-		(145)

End of 2016		2,102		4,714		6,816		1,037		1,238		1,526		227		10,844
Revisions		287		460		747		8		167		16		-		938
Improved recovery		-		-		-		-		-		-		-		-
Purchases		-		-		-		-		-		-		-		-
Extensions and discoveries		2		582		584		3		-		23		-		610
Production		(71	)	(338	)	(409	)	(71	)	(188	)	(267	)	(3	)	(938)
Sales		-		(2,885	)	(2,885	)	(966	)	-		-		-		(3,851)

End of 2017		2,320		2,533		4,853		11		1,217		1,298		224		7,603
Revisions		150		(283	)	(133	)	9		86		4		-		(34)
Improved recovery		-		-		-		-		-		-		-		-
Purchases		335		1		336		-		-		-		-		336
Extensions and discoveries		2		527		529		11		110		23		-		673
Production		(71	)	(237	)	(308	)	(5	)	(188	)	(246	)	(10	)	(757)
Sales		-		(223	)	(223	)	-		(13	)	-		-		(236)

End of 2018		2,736		2,318		5,054		26		1,212		1,079		214		7,585


Equity affiliates
End of 2015		-		-		-		-		-		5,269		-		5,269
Revisions		-		-		-		-		-		(676	)	-		(676	)
Improved recovery		-		-		-		-		-		-		-		-
Purchases		-		-		-		-		-		-		-		-
Extensions and discoveries		-		-		-		-		-		125		-		125
Production		-		-		-		-		-		(337	)	-		(337)
Sales		-		-		-		-		-		-		-		-

End of 2016		-		-		-		-		-		4,381		-		4,381
Revisions		-		-		-		-		-		111		-		111
Improved recovery		-		-		-		-		-		-		-		-
Purchases		-		-		-		-		-		-		-		-
Extensions and discoveries		-		-		-		-		-		185		-		185
Production		-		-		-		-		-		(374	)	-		(374)
Sales		-		-		-		-		-		-		-		-

End of 2017		-		-		-		-		-		4,303		-		4,303
Revisions		-		-		-		-		-		280		-		280
Improved recovery		-		-		-		-		-		-		-		-
Purchases		-		-		-		-		-		-		-		-
Extensions and discoveries		-		-		-		-		-		362		-		362
Production		-		-		-		-		-		(381	)	-		(381)
Sales		-		-		-		-		-		-		-		-

End of 2018		-		-		-		-		-		4,564		-		4,564


Total company
End of 2015		2,347		5,171		7,518		1,107		1,359		6,982		227		17,193
End of 2016		2,102		4,714		6,816		1,037		1,238		5,907		227		15,225
End of 2017		2,320		2,533		4,853		11		1,217		5,601		224		11,906
End of 2018		2,736		2,318		5,054		26		1,212		5,643		214		12,149


Years Ended	Natural Gas
December 31	Billions of Cubic Feet
		Alaska	Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Total
Developed
Consolidated operations
End of 2015		2,313	4,458	6,771	1,101	1,088	1,421	227	10,608
End of 2016		2,094	4,199	6,293	1,031	998	1,188	227	9,737
End of 2017		2,310	1,597	3,907	11	997	945	224	6,084
End of 2018		2,720	1,427	4,147	17	1,052	758	214	6,188

Equity affiliates
End of 2015		-	-	-	-	-	4,482	-	4,482
End of 2016		-	-	-	-	-	4,110	-	4,110
End of 2017		-	-	-	-	-	4,044	-	4,044
End of 2018		-	-	-	-	-	4,059	-	4,059

Undeveloped
Consolidated operations
End of 2015		34	713	747	6	271	292	-	1,316
End of 2016		8	515	523	6	240	338	-	1,107
End of 2017		10	936	946	-	220	353	-	1,519
End of 2018		16	891	907	9	160	321	-	1,397

Equity affiliates
End of 2015		-	-	-	-	-	787	-	787
End of 2016		-	-	-	-	-	271	-	271
End of 2017		-	-	-	-	-	259	-	259
End of 2018		-	-	-	-	-	505	-	505

Natural gas production in the reserves table may differ from gas production (delivered for sale) in our statistics disclosure, primarily because the quantities above include gas consumed in production operations.

Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.

Notable changes in proved natural gas reserves in the three years ended December 31, 2018, included:

	•		Revisions: In 2018, downward revisions in Lower 48 were primarily due to changes in development timing for specific well locations from the unconventional plays and are more than offset by increases in planned well locations in the unconventional plays in the extensions and discoveries category. Downward revisions in Lower 48 due to development timing were partially offset by higher prices. Revisions in Alaska, Canada, Europe and our equity affiliates in Asia Pacific/Middle East were primarily due to higher prices. In 2017, revisions in Alaska, Lower 48 and Europe were primarily due to higher prices. In 2016, revisions in our equity affiliates in Asia Pacific/Middle East were primarily due to lower prices.

	•		Purchases_:_ In 2018, Alaska purchases were due to the Kuparuk Assets and Western North Slope acquisitions.

	•		Extensions and discoveries: In 2018, extensions and discoveries in Lower 48 were primarily due to changes in the development strategy to add specific well locations from the unconventional plays. Extensions and discoveries in Canada, Europe and our equity affiliates in Asia Pacific/Middle East were primarily driven by ongoing drilling successes in Montney, Norway and APLNG, respectively. In 2017, extensions and discoveries in Lower 48 were primarily due to continued drilling success in the Delaware, Eagle Ford and Bakken.

	•		Sales: In 2018, Lower 48 sales were primarily due to the disposition of our interest in Barnett. In 2017, Lower 48 sales were due to the disposition of our interests in the San Juan Basin and Panhandle assets, while Canada sales were due to the disposition of a majority of our western Canada assets.


Years Ended	Bitumen
December 31	Millions of Barrels
	Canada
Developed and Undeveloped
Consolidated operations
End of 2015		687
Revisions		(515)
Improved recovery		-
Purchases		-
Extensions and discoveries		-
Production		(13)
Sales		-

End of 2016		159
Revisions		16
Improved recovery		-
Purchases		-
Extensions and discoveries		96
Production		(21)
Sales		-

End of 2017		250
Revisions		10
Improved recovery		-
Purchases		-
Extensions and discoveries		-
Production		(24)
Sales		-

End of 2018		236


Equity affiliates
End of 2015		1,706
Revisions		(573)
Improved recovery		-
Purchases		-
Extensions and discoveries		10
Production		(54)
Sales		-

End of 2016		1,089
Revisions		-
Improved recovery		-
Purchases		-
Extensions and discoveries		-
Production		(23)
Sales		(1,066)

End of 2017		-
Revisions		-
Improved recovery		-
Purchases		-
Extensions and discoveries		-
Production		-
Sales		-

End of 2018		-


Total company
End of 2015		2,393
End of 2016		1,248
End of 2017		250
End of 2018		236


Years Ended	Bitumen
December 31	Millions of Barrels
	Canada
Developed
Consolidated operations
End of 2015		111
End of 2016		159
End of 2017		154
End of 2018		155


Equity affiliates
End of 2015		311
End of 2016		322
End of 2017		-
End of 2018		-


Undeveloped
Consolidated operations
End of 2015		576
End of 2016		-
End of 2017		96
End of 2018		81


Equity affiliates
End of 2015		1,395
End of 2016		767
End of 2017		-
End of 2018		-

Notable changes in proved bitumen reserves in the three years ended December 31, 2018, included:

	•		Revisions: In 2018, revisions were primarily due to higher prices at Surmont. In 2017, revisions were primarily due to higher prices at Surmont. In 2016, for both our consolidated operations and equity affiliates revisions were primarily related to lower prices which resulted in reserve reductions at Surmont, Foster Creek, Christina Lake and Narrows Lake.

	•		Extensions and discoveries: In 2017, extensions and discoveries were primarily due to higher prices at Surmont, which allowed undeveloped reserves previously de-booked due to low prices to be recognized.

	•		Sales: In 2017, sales were due to the disposition of our 50 percent interest in the FCCL Partnership in Canada.


Years Ended	Total Proved Reserves

December 31	Millions of Barrels of Oil Equivalent

		Alaska		Lower 48		Total U.S.		Canada		Europe		Asia Pacific/ Middle East		Africa		Total

Developed and Undeveloped
Consolidated operations
End of 2015		1,420		1,771		3,191		930		593		497		242		5,453
Revisions		(77	)	(143	)	(220	)	(484	)	11		9		-		(684)
Improved recovery		6		3		9		-		-		7		-		16
Purchases		-		-		-		-		-		-		-		-
Extensions and discoveries		33		124		157		9		-		28		-		194
Production		(76	)	(185	)	(261	)	(55	)	(76	)	(87	)	(1	)	(480)
Sales		(12	)	-		(12	)	(7	)	-		(10	)	-		(29)

End of 2016		1,294		1,570		2,864		393		528		444		241		4,470
Revisions		166		170		336		18		68		36		-		458
Improved recovery		6		-		6		-		-		-		-		6
Purchases		-		-		-		-		-		-		-		-
Extensions and discoveries		41		378		419		97		-		7		-		523
Production		(77	)	(144	)	(221	)	(37	)	(79	)	(81	)	(8	)	(426)
Sales		-		(621	)	(621	)	(217	)	-		-		-		(838)

End of 2017		1,430		1,353		2,783		254		517		406		233		4,193
Revisions		102		(161	)	(59	)	12		40		5		6		4
Improved recovery		2		-		2		-		-		-		-		2
Purchases		289		1		290		-		-		-		-		290
Extensions and discoveries		48		335		383		4		21		6		-		414
Production		(76	)	(146	)	(222	)	(25	)	(75	)	(75	)	(15	)	(412)
Sales		-		(70	)	(70	)	-		(38	)	-		-		(108)

End of 2018		1,795		1,312		3,107		245		465		342		224		4,383


Equity affiliates
End of 2015		-		-		-		1,706		-		1,021		-		2,727
Revisions		-		-		-		(573	)	-		(113	)	-		(686)
Improved recovery		-		-		-		-		-		-		-		-
Purchases		-		-		-		-		-		-		-		-
Extensions and discoveries		-		-		-		10		-		21		-		31
Production		-		-		-		(54	)	-		(64	)	-		(118)
Sales		-		-		-		-		-		-		-		-

End of 2016		-		-		-		1,089		-		865		-		1,954
Revisions		-		-		-		-		-		18		-		18
Improved recovery		-		-		-		-		-		-		-		-
Purchases		-		-		-		-		-		-		-		-
Extensions and discoveries		-		-		-		-		-		31		-		31
Production		-		-		-		(23	)	-		(69	)	-		(92)
Sales		-		-		-		(1,066	)	-		-		-		(1,066)

End of 2017		-		-		-		-		-		845		-		845
Revisions		-		-		-		-		-		46		-		46
Improved recovery		-		-		-		-		-		-		-		-
Purchases		-		-		-		-		-		-		-		-
Extensions and discoveries		-		-		-		-		-		60		-		60
Production		-		-		-		-		-		(71	)	-		(71)
Sales		-		-		-		-		-		-		-		-

End of 2018		-		-		-		-		-		880		-		880


Total company
End of 2015		1,420		1,771		3,191		2,636		593		1,518		242		8,180
End of 2016		1,294		1,570		2,864		1,482		528		1,309		241		6,424
End of 2017		1,430		1,353		2,783		254		517		1,251		233		5,038
End of 2018		1,795		1,312		3,107		245		465		1,222		224		5,263


Years Ended	Total Proved Reserves
December 31	Millions of Barrels of Oil Equivalent
		Alaska	Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Total
Developed
Consolidated operations
End of 2015		1,318	1,261	2,579	352	398	384	242	3,955
End of 2016		1,203	1,165	2,368	391	365	309	241	3,674
End of 2017		1,319	682	2,001	158	372	281	233	3,045
End of 2018		1,617	681	2,298	160	382	244	221	3,305

Equity affiliates
End of 2015		-	-	-	311	-	890	-	1,201
End of 2016		-	-	-	322	-	820	-	1,142
End of 2017		-	-	-	-	-	802	-	802
End of 2018		-	-	-	-	-	796	-	796

Undeveloped
Consolidated operations
End of 2015		102	510	612	578	195	113	-	1,498
End of 2016		91	405	496	2	163	135	-	796
End of 2017		111	671	782	96	145	125	-	1,148
End of 2018		178	631	809	85	83	98	3	1,078

Equity affiliates
End of 2015		-	-	-	1,395	-	131	-	1,526
End of 2016		-	-	-	767	-	45	-	812
End of 2017		-	-	-	-	-	43	-	43
End of 2018		-	-	-	-	-	84	-	84

Natural gas reserves are converted to barrels of oil equivalent (BOE) based on a 6:1 ratio: six thousand cubic feet of natural gas converts to one BOE.

Proved Undeveloped Reserves

We had 1,162 million BOE of proved undeveloped reserves at year-end 2018, compared with 1,191 million BOE at year-end 2017. The following table shows changes in total proved undeveloped reserves for 2018:


	Proved Undeveloped Reserves

	Millions of Barrels of Oil Equivalent

End of 2017		1,191
Transfers to proved developed		(270)
Revisions		(208)
Improved recovery		2
Purchases		43
Extensions and discoveries		445
Sales		(41)

End of 2018		1,162

Downward revisions were primarily in our Lower 48 segment and were mainly due to changes in development timing for specific well locations from the unconventional plays. These revisions were partially offset by higher prices in Lower 48 as well as Alaska, Europe and APME.

Extensions and discoveries were primarily in Lower 48 and were mainly due to changes in the development strategy to add specific well locations from the unconventional plays.

Purchases were due to the Kuparuk Assets and Western North Slope acquisitions in Alaska. Sales were primarily due to the disposition of a subsidiary that held a 16.5 percent interest in the Clair Field in the United Kingdom.

At December 31, 2018, our proved undeveloped reserves represented 22 percent of total proved reserves, compared with 24 percent at December 31, 2017. Costs incurred for the year ended December 31, 2018, relating to the development of proved undeveloped reserves were $4.6 billion. A portion of our costs incurred each year relates to development projects where the proved undeveloped reserves will be converted to proved developed reserves in future years.

At the end of 2018, approximately 90 percent of total proved undeveloped reserves are currently under development or scheduled for development within five years of initial disclosure. The remainder are to be developed as parts of major projects ongoing in our Europe and Asia Pacific/Middle East regions. All major development areas are currently producing and are expected to have proved undeveloped reserves convert to proved developed over time. Approximately 77 percent of our total proved undeveloped reserves at year-end 2018 are in North America, and all these reserve volumes are planned for development within five years of initial disclosure.

Results of Operations

The company’s results of operations from oil and gas activities for the years 2018, 2017 and 2016 are shown in the following tables. Non-oil and gas activities, such as pipeline and marine operations, liquefied natural gas (LNG) operations, crude oil and gas marketing activities, and the profit element of transportation operations in which we have an ownership interest are excluded. Additional information about selected line items within the results of operations tables is shown below:

	•		Sales include sales to unaffiliated entities attributable primarily to the company’s net working interests and royalty interests. Sales are net of fees to transport our produced hydrocarbons beyond the production function to a final delivery point using transportation operations which are not consolidated.

	•		Transportation costs reflect fees to transport our produced hydrocarbons beyond the production function to a final delivery point using transportation operations which are consolidated.

	•		Other revenues include gains and losses from asset sales, certain amounts resulting from the purchase and sale of hydrocarbons, and other miscellaneous income.

	•		Production costs include costs incurred to operate and maintain wells, related equipment and facilities used in the production of petroleum liquids and natural gas.

	•		Taxes other than income taxes include production, property and other non-income taxes.

	•		Depreciation of support equipment is reclassified as applicable.

	•		Other related expenses include inventory fluctuations, foreign currency transaction gains and losses and other miscellaneous expenses.

Results of Operations


Year Ended	Millions of Dollars


December 31, 2018		Alaska		Lower 48	Total U.S.		Canada		Europe		Asia Pacific/ Middle East		Africa		Other Areas		Total

Consolidated operations
Sales	$	4,816		6,573	11,389		582		4,449		3,177		950		-		20,547
Transfers		5		-	5		-		-		545		-		-		550
Transportation costs		(722	)	-	(722	)	-		-		(45	)	-		-		(767	)
Other revenues		335		213	548		164		737		6		110		432		1,997

Total revenues		4,434		6,786	11,220		746		5,186		3,683		1,060		432		22,327
Production costs excluding taxes		964		1,533	2,497		417		856		646		62		2		4,480
Taxes other than income taxes		357		432	789		21		33		95		3		-		941
Exploration expenses		59		176	235		21		57		43		(4	)	20		372
Depreciation, depletion and amortization		616		2,279	2,895		313		1,070		1,186		33		-		5,497
Impairments		1		64	65		9		(78	)	14		-		-		10
Other related expenses		16		63	79		56		(62	)	(19	)	1		(1	)	54
Accretion		56		51	107		7		178		39		-		-		331

		2,365		2,188	4,553		(98	)	3,132		1,679		965		411		10,642
Income tax provision (benefit)		419		466	885		(114	)	1,354		683		926		(8	)	3,726

Results of operations	$	1,946		1,722	3,668		16		1,778		996		39		419		6,916


Equity affiliates
Sales	$	-		-	-		-		-		758		-		-		758
Transfers		-		-	-		-		-		2,018		-		-		2,018
Transportation costs		-		-	-		-		-		-		-		-		-
Other revenues		-		-	-		-		-		(6	)	-		-		(6	)

Total revenues		-		-	-		-		-		2,770		-		-		2,770
Production costs excluding taxes		-		-	-		-		-		321		-		-		321
Taxes other than income taxes		-		-	-		-		-		804		-		-		804
Exploration expenses		-		-	-		-		-		-		-		-		-
Depreciation, depletion and amortization		-		-	-		-		-		640		-		-		640
Impairments		-		-	-		-		-		-		-		-		-
Other related expenses		-		-	-		-		-		(4	)	-		-		(4	)
Accretion		-		-	-		-		-		15		-		-		15

		-		-	-		-		-		994		-		-		994
Income tax provision (benefit)		-		-	-		-		-		103		-		-		103

Results of operations	$	-		-	-		-		-		891		-		-		891


Year Ended	Millions of Dollars


December 31, 2017		Alaska		Lower 48		Total U.S.		Canada		Europe	Asia Pacific/ Middle East		Africa		Other Areas		Total

Consolidated operations
Sales	$	3,542		4,557		8,099		705		3,527	2,752		487		-		15,570
Transfers		4		-		4		-		-	411		-		-		415
Transportation costs		(706	)	-		(706	)	-		-	(80	)	-		-		(786	)
Other revenues		14		28		42		2,158		68	11		48		322		2,649

Total revenues		2,854		4,585		7,439		2,863		3,595	3,094		535		322		17,848
Production costs excluding taxes		947		1,607		2,554		604		770	566		44		(1	)	4,537
Taxes other than income taxes		275		318		593		33		32	39		2		-		699
Exploration expenses		83		584		667		22		45	97		61		45		937
Depreciation, depletion and amortization		730		2,685		3,415		438		1,234	1,283		16		-		6,386
Impairments		179		3,969		4,148		22		46	-		-		-		4,216
Other related expenses		(7	)	62		55		7		57	60		6		-		185
Accretion		52		63		115		16		172	37		-		-		340

		595		(4,703	)	(4,108	)	1,721		1,239	1,012		406		278		548
Income tax provision (benefit)		(669	)	(2,401	)	(3,070	)	(651	)	702	363		428		11		(2,217	)

Results of operations	$	1,264		(2,302	)	(1,038	)	2,372		537	649		(22	)	267		2,765


Equity affiliates
Sales	$	-		-		-		528		-	563		-		-		1,091
Transfers		-		-		-		-		-	1,398		-		-		1,398
Transportation costs		-		-		-		-		-	-		-		-		-
Other revenues		-		-		-		5		-	-		-		-		5

Total revenues		-		-		-		533		-	1,961		-		-		2,494
Production costs excluding taxes		-		-		-		174		-	363		-		-		537
Taxes other than income taxes		-		-		-		7		-	604		-		-		611
Exploration expenses		-		-		-		1		-	1,699		-		-		1,700
Depreciation, depletion and amortization		-		-		-		150		-	617		-		-		767
Impairments		-		-		-		-		-	1,717		-		-		1,717
Other related expenses		-		-		-		4		-	22		-		19		45
Accretion		-		-		-		2		-	11		-		-		13

		-		-		-		195		-	(3,072	)	-		(19	)	(2,896	)
Income tax provision (benefit)		-		-		-		26		-	(998	)	-		13		(959	)

Results of operations	$	-		-		-		169		-	(2,074	)	-		(32	)	(1,937	)

Production costs excluding taxes have been revised to exclude the non-service components of pension related net periodic costs to conform to the current year’s presentation.


Year Ended	Millions of Dollars


December 31, 2016		Alaska		Lower 48		Total U.S.		Canada		Europe		Asia Pacific/ Middle East		Africa		Other Areas		Total

Consolidated operations
Sales	$	2,793		4,117		6,910		661		2,678		2,350		-		-		12,599
Transfers		8		-		8		-		-		347		-		-		355
Transportation costs		(676	)	-		(676	)	-		-		(40	)	-		-		(716	)
Other revenues		375		111		486		48		(34	)	(25	)	147		9		631

Total revenues		2,500		4,228		6,728		709		2,644		2,632		147		9		12,869
Production costs excluding taxes		996		1,852		2,848		781		786		626		23		(2	)	5,062
Taxes other than income taxes		231		308		539		55		31		30		1		-		656
Exploration expenses		45		1,227		1,272		332		90		38		138		41		1,911
Depreciation, depletion and amortization		738		4,167		4,905		881		1,390		1,402		2		-		8,580
Impairments		1		148		149		88		(161	)	44		-		-		120
Other related expenses		52		70		122		(51	)	(77	)	(13	)	4		4		(11	)
Accretion		52		72		124		32		210		35		-		-		401

		385		(3,616	)	(3,231	)	(1,409	)	375		470		(21	)	(34	)	(3,850	)
Income tax provision (benefit)		(7	)	(1,307	)	(1,314	)	(406	)	3		250		(72	)	(13	)	(1,552	)

Results of operations	$	392		(2,309	)	(1,917	)	(1,003	)	372		220		51		(21	)	(2,298	)


Equity affiliates
Sales	$	-		-		-		860		-		449		-		-		1,309
Transfers		-		-		-		-		-		825		-		-		825
Transportation costs		-		-		-		-		-		-		-		-		-
Other revenues		-		-		-		-		-		(2	)	-		-		(2	)

Total revenues		-		-		-		860		-		1,272		-		-		2,132
Production costs excluding taxes		-		-		-		431		-		256		-		-		687
Taxes other than income taxes		-		-		-		15		-		476		-		-		491
Exploration expenses		-		-		-		6		-		-		-		-		6
Depreciation, depletion and amortization		-		-		-		309		-		548		-		-		857
Impairments		-		-		-		9		-		-		-		-		9
Other related expenses		-		-		-		(7	)	-		8		-		24		25
Accretion		-		-		-		8		-		7		-		-		15

		-		-		-		89		-		(23	)	-		(24	)	42
Income tax provision (benefit)		-		-		-		24		-		(201	)	-		-		(177	)

Results of operations	$	-		-		-		65		-		178		-		(24	)	219

Production costs excluding taxes have been revised to exclude the non-service components of pension related net periodic costs to conform to the current year’s presentation.

Statistics


Net Production	2018	2017	2016

	Thousands of Barrels Daily

Crude Oil
Consolidated operations
Alaska	171	167	163
Lower 48	229	180	195

United States	400	347	358
Canada	1	3	7
Europe	113	122	120
Asia Pacific/Middle East	89	93	97
Africa	36	20	2

Total consolidated operations	639	585	584

Equity affiliates
Asia Pacific/Middle East	14	14	14
Other areas	-	-	-

Total equity affiliates	14	14	14

Total company	653	599	598


Natural Gas Liquids
Consolidated operations
Alaska	14	14	12
Lower 48	69	69	88

United States	83	83	100
Canada	1	9	23
Europe	8	8	7
Asia Pacific/Middle East	3	4	7

Total consolidated operations	95	104	137

_Equity affiliates—_Asia Pacific/Middle East	7	7	8

Total company	102	111	145


Bitumen
Consolidated operations—Canada	66	59	35
Equity affiliates—Canada	-	63	148

Total company	66	122	183


Natural Gas	Millions of Cubic Feet Daily

Consolidated operations
Alaska	6	7	25
Lower 48	596	898	1,219

United States	602	905	1,244
Canada	12	187	524
Europe	475	476	459
Asia Pacific/Middle East	626	687	730
Africa	28	8	1

Total consolidated operations	1,743	2,263	2,958

Equity affiliates—Asia Pacific/Middle East	1,031	1,007	899

Total company	2,774	3,270	3,857


Average Sales Prices		2018	2017	2016

Crude Oil Per Barrel
Consolidated operations
Alaska	$	60.23	42.69	31.68
Lower 48		62.99	47.36	37.49
United States		61.75	45.01	34.70
Canada		48.73	43.69	35.25
Europe		70.98	54.04	43.66
Asia Pacific/Middle East		70.93	54.38	42.23
Africa		69.83	55.11	-
Total international		70.67	54.16	42.76
Total consolidated operations		65.01	48.70	37.67
Equity affiliates
Asia Pacific/Middle East		72.49	54.76	44.11
Total equity affiliates		72.49	54.76	44.11
Total operations		65.17	48.84	37.82

Natural Gas Liquids Per Barrel
Consolidated operations
Lower 48	$	27.30	22.20	14.34
United States		27.30	22.20	14.34
Canada		43.70	21.51	14.82
Europe		36.87	34.07	22.62
Asia Pacific/Middle East		47.20	41.37	29.00
Total international		40.00	30.34	19.06
Total consolidated operations		29.03	24.21	15.72
Equity affiliates—Asia Pacific/Middle East		45.69	38.74	31.13
Total operations		30.48	25.22	16.68

Bitumen Per Barrel
_Consolidated operations—_Canada	$	22.29	21.43	12.91
_Equity affiliates—_Canada		-	23.83	15.80

Natural Gas Per Thousand Cubic Feet
Consolidated operations
Alaska	$	2.48	2.72	5.22
Lower 48		2.82	2.73	2.20
United States		2.82	2.73	2.24
Canada		1.00	1.93	1.49
Europe		7.79	5.72	4.71
Asia Pacific/Middle East		5.95	4.66	4.15
Africa		4.84	3.53	-
Total international		6.64	4.64	3.49
Total consolidated operations		5.33	3.87	2.97
Equity affiliates—Asia Pacific/Middle East		6.06	4.27	2.97
Total operations		5.60	4.00	2.97

Average sales prices for Alaska crude oil and Asia Pacific/Middle East natural gas above reflect a reduction for transportation costs in which we have an ownership interest that are incurred subsequent to the terminal point of the production function. Accordingly, the average sales prices differ from those discussed in Item 7 of Management’s Discussion and Analysis of Financial Condition and Results of Operations.


		2018	2017	2016
Average Production Costs Per Barrel of Oil Equivalent*
Consolidated operations
Alaska	$	14.20	14.26	15.20
Lower 48		10.58	11.03	10.41
United States		11.73	12.04	11.70
Canada		16.32	16.22	14.04
Europe		11.73	10.09	10.58
Asia Pacific/Middle East		9.03	7.31	7.57
Africa		4.14	5.74	31.42
Total international		10.72	9.99	10.38
Total consolidated operations		11.26	11.05	11.08
Equity affiliates
Canada		-	7.57	7.96
Asia Pacific/Middle East		4.56	5.26	4.04
Other areas		-	-	-
Total equity affiliates		4.56	5.84	5.85

Average Production Costs Per Barrel—Bitumen
_Consolidated operations—_Canada	$	13.59	14.63	24.59
_Equity affiliates—_Canada		-	18.74	7.96

Taxes Other Than Income Taxes Per Barrel of Oil Equivalent
Consolidated operations
Alaska	$	5.26	4.14	3.53
Lower 48		2.98	2.18	1.73
United States		3.71	2.80	2.21
Canada		0.82	0.89	0.99
Europe		0.45	0.42	0.42
Asia Pacific/Middle East		1.33	0.50	0.36
Africa		0.20	0.26	1.37
Total international		0.82	0.53	0.55
Total consolidated operations		2.37	1.70	1.44
Equity affiliates
Canada		-	0.30	0.28
Asia Pacific/Middle East		11.41	8.76	7.52
Other areas		-	-	-
Total equity affiliates		11.41	6.64	4.18

Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent
Consolidated operations
Alaska	$	9.07	10.99	11.26
Lower 48		15.73	18.44	23.43
United States		13.60	16.10	20.15
Canada		12.25	11.76	15.84
Europe		14.66	16.18	18.71
Asia Pacific/Middle East		16.58	16.58	16.95
Africa		2.21	2.09	2.73
Total international		14.06	14.96	17.22
Total consolidated operations		13.82	15.55	18.78
Equity affiliates
Canada		-	6.52	5.70
Asia Pacific/Middle East		9.09	8.94	8.65
Other areas		-	-	-
Total equity affiliates		9.09	8.34	7.29

*Includes bitumen.

Development and Exploration Activities

The following two tables summarize our net interest in productive and dry exploratory and development wells in the years ended December 31, 2018, 2017 and 2016. A “development well” is a well drilled within the proved area of a reservoir to the depth of a stratigraphic horizon known to be productive. An “exploratory well” is a well drilled to find and produce crude oil or natural gas in an unknown field or a new reservoir within a proven field. Exploratory wells also include wells drilled in areas near or offsetting current production, or in areas where well density or production history have not achieved statistical certainty of results. Excluded from the exploratory well count are stratigraphic-type exploratory wells, primarily relating to oil sands delineation wells located in Canada and coalbed methane test wells located in Asia Pacific/Middle East.


Net Wells Completed	Productive			Dry

	2018	2017	2016	2018	2017	2016

Exploratory
Consolidated operations
Alaska	6	-	2	-	-	1
Lower 48	45	13	8	1	3	1

United States	51	13	10	1	3	2
Canada	2	13	8	-	-	1
Europe	*****	*	*	*****	*	1
Asia Pacific/Middle East	2	1	1	-	1	-
Africa	-	-	1	*****	-	-
Other areas	-	-	-	-	1	-

Total consolidated operations	55	27	20	1	5	4

Equity affiliates
Asia Pacific/Middle East	6	14	20	-	-	-

Total equity affiliates	6	14	20	-	-	-


Development
Consolidated operations
Alaska	11	9	9	-	-	-
Lower 48	254	161	119	-	-	-

United States	265	170	128	-	-	-
Canada	1	13	47	-	-	2
Europe	9	7	7	-	-	-
Asia Pacific/Middle East	12	8	6	-	-	-
Africa	1	-	-	-	-	-
Other areas	-	-	-	-	-	-

Total consolidated operations	288	198	188	-	-	2

Equity affiliates
Canada	-	19	48	-	-	-
Asia Pacific/Middle East	75	84	108	-	-	-
Other areas	-	-	-	-	-	-

Total equity affiliates	75	103	156	-	-	-

*Our total proportionate interest was less than one.

The table below represents the status of our wells drilling at December 31, 2018, and includes wells in the process of drilling or in active completion. It also represents gross and net productive wells, including producing wells and wells capable of production at December 31, 2018.


Wells at December 31, 2018					Productive*

	In Progress				Oil				Gas

	Gross		Net		Gross		Net		Gross		Net

Consolidated operations
Alaska		5		5		1,692		1,012		-		-
Lower 48		330		177		9,749		4,507		4,339		1,647

United States		335		182		11,441		5,519		4,339		1,647
Canada		15		14		183		92		33		29
Europe		15		2		497		86		155		52
Asia Pacific/Middle East		9		4		386		161		58		29
Africa		8		1		830		135		9		2

Total consolidated operations		382		203		13,337		5,993		4,594		1,759

Equity affiliates
Asia Pacific/Middle East		328		79		-		-		3,950		987

Total equity affiliates		328		79		-		-		3,950		987

*Includes 18 gross and 6 net multiple completion wells.


Acreage at December 31, 2018	Thousands of Acres

	Developed				Undeveloped

	Gross		Net		Gross		Net

Consolidated operations
Alaska		675		464		1,408		1,255
Lower 48		2,429		1,962		10,322		8,378

United States		3,104		2,426		11,730		9,633
Canada		200		119		3,267		1,793
Europe		787		231		2,730		807
Asia Pacific/Middle East		1,597		742		12,065		6,806
Africa		358		58		12,545		2,049
Other areas		-		-		560		323

Total consolidated operations		6,046		3,576		42,897		21,411

Equity affiliates
Asia Pacific/Middle East		947		219		4,198		969

Total equity affiliates		947		219		4,198		969

Costs Incurred


Year Ended	Millions of Dollars

December 31		Alaska	Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	*	Africa		Other Areas	Total

2018
Consolidated operations
Unproved property acquisition	$	119	126	245	126	-	-		-		-	371
Proved property acquisition		2,227	16	2,243	6	-	-		-		-	2,249

		2,346	142	2,488	132	-	-		-		-	2,620
Exploration		203	500	703	90	65	82		(6	)	41	975
Development		718	2,715	3,433	301	703	773		16		-	5,226

	$	3,267	3,357	6,624	523	768	855		10		41	8,821


Equity affiliates
Unproved property acquisition	$	-	-	-	-	-	-		-		-	-
Proved property acquisition		-	-	-	-	-	-		-		-	-

		-	-	-	-	-	-		-		-	-
Exploration		-	-	-	-	-	22		-		-	22
Development		-	-	-	-	-	206		-		-	206

	$	-	-	-	-	-	228		-		-	228


2017
Consolidated operations
Unproved property acquisition	$	18	267	285	76	-	15		-		-	376
Proved property acquisition		-	35	35	-	-	-		-		-	35

		18	302	320	76	-	15		-		-	411
Exploration		74	399	473	56	52	139		61		42	823
Development		736	1,559	2,295	102	784	388		10		-	3,579

	$	828	2,260	3,088	234	836	542		71		42	4,813


Equity affiliates
Unproved property acquisition	$	-	-	-	-	-	-		-		-	-
Proved property acquisition		-	-	-	-	-	-		-		-	-

		-	-	-	-	-	-		-		-	-
Exploration		-	-	-	6	-	38		-		-	44
Development		-	-	-	150	-	403		-		-	553

	$	-	-	-	156	-	441		-		-	597


2016
Consolidated operations
Unproved property acquisition	$	-	127	127	59	-	-		-		-	186
Proved property acquisition		-	5	5	19	-	-		-		-	24

		-	132	132	78	-	-		-		-	210
Exploration		110	656	766	286	65	52		215		67	1,451
Development		720	782	1,502	209	62	387		6		-	2,166

	$	830	1,570	2,400	573	127	439		221		67	3,827


Equity affiliates
Unproved property acquisition	$	-	-	-	-	-	2		-		-	2
Proved property acquisition		-	-	-	-	-	-		-		-	-

		-	-	-	-	-	2		-		-	2
Exploration		-	-	-	15	-	19		-		-	34
Development		-	-	-	367	-	320		-		-	687

	$	-	-	-	382	-	341		-		-	723

* Certain amounts in Asia Pacific/Middle East equity affiliates have been revised in 2016 to reflect additional abandonment obligations.

Capitalized Costs


At December 31	Millions of Dollars

		Alaska	Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Other Areas	Total

2018
Consolidated operations
Proved property	$	20,154	35,269	55,423	5,946	23,520	14,866	902	-	100,657
Unproved property		1,184	1,125	2,309	1,083	188	874	119	89	4,662

		21,338	36,394	57,732	7,029	23,708	15,740	1,021	89	105,319
Accumulated depreciation, depletion and amortization		9,055	23,999	33,054	1,692	16,591	9,974	342	9	61,662

	$	12,283	12,395	24,678	5,337	7,117	5,766	679	80	43,657


Equity affiliates
Proved property	$	-	-	-	-	-	9,990	-	-	9,990
Unproved property		-	-	-	-	-	2,162	-	-	2,162

		-	-	-	-	-	12,152	-	-	12,152
Accumulated depreciation, depletion and amortization		-	-	-	-	-	5,960	-	-	5,960

	$	-	-	-	-	-	6,192	-	-	6,192


2017
Consolidated operations
Proved property	$	18,149	35,332	53,481	6,217	27,221	14,236	889	-	102,044
Unproved property		1,068	1,137	2,205	985	290	822	122	67	4,491

		19,217	36,469	55,686	7,202	27,511	15,058	1,011	67	106,535
Accumulated depreciation, depletion and amortization		9,497	24,211	33,708	1,582	18,068	8,916	312	9	62,595

	$	9,720	12,258	21,978	5,620	9,443	6,142	699	58	43,940


Equity affiliates
Proved property	$	-	-	-	-	-	9,750	-	-	9,750
Unproved property		-	-	-	-	-	2,215	-	-	2,215

		-	-	-	-	-	11,965	-	-	11,965
Accumulated depreciation, depletion and amortization		-	-	-	-	-	5,342	-	-	5,342

	$	-	-	-	-	-	6,623	-	-	6,623

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities

In accordance with SEC and FASB requirements, amounts were computed using 12-month average prices (adjusted only for existing contractual terms) and end-of-year costs, appropriate statutory tax rates and a prescribed 10 percent discount factor. Twelve-month average prices are calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. For all years, continuation of year-end economic conditions was assumed. The calculations were based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, were not considered. The calculations also require assumptions as to the timing of future production of proved reserves and the timing and amount of future development costs, including dismantlement, and future production costs, including taxes other than income taxes.

While due care was taken in its preparation, we do not represent that this data is the fair value of our oil and gas properties, or a fair estimate of the present value of cash flows to be obtained from their development and production.

Discounted Future Net Cash Flows


	Millions of Dollars

		Alaska	Lower 48	Total U.S.	Canada	Europe	Asia Pacific/ Middle East	Africa	Total

2018
Consolidated operations
Future cash inflows	$	82,072	56,922	138,994	6,039	26,989	16,368	16,434	204,824
Less:
Future production costs		42,755	21,363	64,118	4,099	8,567	5,705	1,336	83,825
Future development costs		10,053	12,136	22,189	606	7,608	1,995	507	32,905
Future income tax provisions		5,538	4,418	9,956	-	7,102	2,873	13,492	33,423

Future net cash flows		23,726	19,005	42,731	1,334	3,712	5,795	1,099	54,671
10 percent annual discount		10,349	6,461	16,810	426	371	1,132	498	19,237

Discounted future net cash flows	$	13,377	12,544	25,921	908	3,341	4,663	601	35,434


Equity affiliates
Future cash inflows	$	-	-	-	-	-	33,606	-	33,606
Less:
Future production costs		-	-	-	-	-	16,449	-	16,449
Future development costs		-	-	-	-	-	1,228	-	1,228
Future income tax provisions		-	-	-	-	-	3,147	-	3,147

Future net cash flows		-	-	-	-	-	12,782	-	12,782
10 percent annual discount		-	-	-	-	-	4,853	-	4,853

Discounted future net cash flows	$	-	-	-	-	-	7,929	-	7,929


Total company
Discounted future net cash flows	$	13,377	12,544	25,921	908	3,341	12,592	601	43,363


	Millions of Dollars

	Alaska		Lower 48		Total U.S.		Canada		Europe		Asia Pacific/ Middle East		Africa		Total

2017
Consolidated operations
Future cash inflows	$	44,969		44,556		89,525		5,479		23,137		15,207		13,181		146,529
Less:
Future production costs		29,524		18,947		48,471		4,417		8,128		5,398		1,401		67,815
Future development costs		7,255		10,881		18,136		696		8,758		2,511		537		30,638
Future income tax provisions (benefit)		53		2,375		2,428		-		3,333		2,459		10,356		18,576

Future net cash flows		8,137		12,353		20,490		366		2,918		4,839		887		29,500
10 percent annual discount		2,712		4,358		7,070		78		289		1,032		422		8,891

Discounted future net cash flows	$	5,425		7,995		13,420		288		2,629		3,807		465		20,609


Equity affiliates
Future cash inflows	$	-		-		-		-		-		23,222		-		23,222
Less:
Future production costs		-		-		-		-		-		12,984		-		12,984
Future development costs		-		-		-		-		-		1,444		-		1,444
Future income tax provisions		-		-		-		-		-		2,083		-		2,083

Future net cash flows		-		-		-		-		-		6,711		-		6,711
10 percent annual discount		-		-		-		-		-		2,316		-		2,316

Discounted future net cash flows	$	-		-		-		-		-		4,395		-		4,395


Total company
Discounted future net cash flows	$	5,425		7,995		13,420		288		2,629		8,202		465		25,004


	Millions of Dollars

	Alaska			Lower 48		Total U.S.			Canada			Europe			Asia Pacific/ Middle East		Africa		Total

2016
Consolidated operations
Future cash inflows	$	29,697			31,963		61,660			4,739			18,533			12,770		10,715		108,417
Less:
Future production costs		24,965			16,936		41,901			5,103			7,469			5,288		1,420		61,181
Future development costs		7,961			8,932		16,893			1,586			9,949			2,777		537		31,742
Future income tax provisions		-			744		744			-			(325	)		1,563		7,885		9,867

Future net cash flows		(3,229	)		5,351		2,122			(1,950	)		1,440			3,142		873		5,627
10 percent annual discount		(3,143	)		976		(2,167	)		(1,297	)		(2	)		572		370		(2,524	)

Discounted future net cash flows	$	(86	)		4,375		4,289			(653	)		1,442			2,570		503		8,151


Equity affiliates
Future cash inflows	$	-			-		-			15,139			-			17,829		-		32,968
Less:
Future production costs		-			-		-			8,514			-			10,620		-		19,134
Future development costs		-			-		-			4,993			-			980		-		5,973
Future income tax provisions		-			-		-			164			-			1,309		-		1,473

Future net cash flows		-			-		-			1,468			-			4,920		-		6,388
10 percent annual discount		-			-		-			540			-			1,911		-		2,451

Discounted future net cash flows	$	-			-		-			928			-			3,009		-		3,937


Total company
Discounted future net cash flows	$	(86	)		4,375		4,289			275			1,442			5,579		503		12,088

Sources of Change in Discounted Future Net Cash Flows


	Millions of Dollars

	Consolidated Operations							Equity Affiliates							Total Company

		2018		2017		2016			2018		2017		2016			2018		2017		2016


Discounted future net cash flows at the beginning of the year	$	20,609		8,151		16,562			4,395		3,937		9,027			25,004		12,088		25,589

Changes during the year
Revenues less production costs for the year		(14,909	)	(9,844	)	(6,313	)		(1,651	)	(1,341	)	(956	)		(16,560	)	(11,185	)	(7,269	)
Net change in prices and production costs		25,391		19,310		(16,476	)		4,559		2,750		(9,317	)		29,950		22,060		(25,793	)
Extensions, discoveries and improved recovery, less estimated future costs		4,574		1,445		1,358			382		(4	)	(77	)		4,956		1,441		1,281
Development costs for the year		5,197		3,653		3,118			271		426		722			5,468		4,079		3,840
Changes in estimated future development costs		(1,141	)	1,225		6,646			14		(64	)	2,435			(1,127	)	1,161		9,081
Purchases of reserves in place, less estimated future costs		3,033		-		2			-		-		-			3,033		-		2
Sales of reserves in place, less estimated future costs		(1,531	)	(855	)	(123	)		-		(786	)	-			(1,531	)	(1,641	)	(123	)
Revisions of previous quantity estimates		(365	)	2,300		(3,252	)		62		(648	)	(436	)		(303	)	1,652		(3,688	)
Accretion of discount		3,055		1,313		2,540			485		413		1,058			3,540		1,726		3,598
Net change in income taxes		(8,479	)	(6,089	)	4,089			(588	)	(288	)	1,481			(9,067	)	(6,377	)	5,570

Total changes		14,825		12,458		(8,411	)		3,534		458		(5,090	)		18,359		12,916		(13,501	)

Discounted future net cash flows at year end	$	35,434		20,609		8,151			7,929		4,395		3,937			43,363		25,004		12,088

•		The net change in prices and production costs is the beginning-of-year reserve-production forecast multiplied by the net annual change in the per-unit sales price and production cost, discounted at 10 percent.

•		Purchases and sales of reserves in place, along with extensions, discoveries and improved recovery, are calculated using production forecasts of the applicable reserve quantities for the year multiplied by the 12-month average sales prices, less future estimated costs, discounted at 10 percent.

•		Revisions of previous quantity estimates are calculated using production forecast changes for the year, including changes in the timing of production, multiplied by the 12-month average sales prices, less future estimated costs, discounted at 10 percent.

•		The accretion of discount is 10 percent of the prior year’s discounted future cash inflows, less future production and development costs.

•		The net change in income taxes is the annual change in the discounted future income tax provisions.

Selected Quarterly Financial Data (Unaudited)


	Millions of Dollars									Per Share of Common Stock
		Sales and Other Operating Revenues		Income (Loss) Before Income Taxes		Net Income (Loss)		Net Income (Loss) Attributable to ConocoPhillips			Net Income (Loss) Attributable to ConocoPhillips
	Basic		Diluted

2018
First	$	8,798		1,776		900		888			0.75		0.75
Second		8,504		2,619		1,654		1,640			1.40		1.39
Third		9,449		2,906		1,873		1,861			1.60		1.59
Fourth		9,666		2,672		1,878		1,868			1.62		1.61

2017
First	$	7,518		(232	)	599		586			0.47		0.47
Second		6,781		(4,361	)	(3,426	)	(3,440	)		(2.78	)	(2.78	)
Third		6,688		653		436		420			0.35		0.34
Fourth		8,119		1,325		1,598		1,579			1.32		1.32

For additional information on the commodity price environment, see the Business Environment and Executive Overview section of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company and Burlington Resources LLC, with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. Burlington Resources LLC is 100 percent owned by ConocoPhillips Company. ConocoPhillips and/or ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of Burlington Resources LLC, 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 Burlington Resources LLC (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.

In December 2018, ConocoPhillips Canada Funding Company I’s guaranteed, publicly held debt securities were assumed by Burlington Resources LLC. The assumption did not significantly change the nature of the outstanding debt or the terms of the parental guarantees, which remain full and unconditional, as well as joint and several. The assumption did not impact our consolidated financial position, results of operations or cash flows. Financial information for ConocoPhillips Canada Funding Company I is presented in the “All Other Subsidiaries” column of our condensed consolidating financial information. The prior year comparative periods have been restated to reflect the current period condensed consolidating financial information presentation.

In 2016, ConocoPhillips received a $2.3 billion return of capital from ConocoPhillips Company to settle certain accumulated intercompany balances. The transaction had no impact on our consolidated financial statements.

In 2016, ConocoPhillips Canada Funding Company I repaid $1.25 billion of external debt. This transaction was reflected in the full-year 2016 condensed consolidating financial statements.

In 2017, ConocoPhillips Company received a $9.8 billion return of capital and a $1.4 billion loan repayment from nonguarantor subsidiaries to settle certain accumulated intercompany balances. These transactions had no impact on our consolidated financial statements.

In 2017, ConocoPhillips received a $7.8 billion return of capital and a $0.2 billion return of earnings from ConocoPhillips Company to settle certain accumulated intercompany balances. These transactions had no impact on our consolidated financial statements.

In 2018, ConocoPhillips Company received a $4.8 billion return of earnings and a $2.4 billion loan repayment from nonguarantor subsidiaries to settle certain accumulated intercompany balances. These transactions had no impact on our consolidated financial statements.

In 2018, ConocoPhillips received a $3.5 billion return of capital and a $1.0 billion return of earnings from ConocoPhillips Company to settle certain accumulated intercompany balances. These transactions had no impact on our consolidated financial statements.

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


	Millions of Dollars

		Year Ended December 31, 2018

Income Statement		ConocoPhillips	ConocoPhillips Company	Burlington Resources LLC	All Other Subsidiaries	Consolidating Adjustments	Total Consolidated


Revenues and Other Income
Sales and other operating revenues	$	-	16,113	-	20,304	-	36,417
Equity in earnings of affiliates		6,503	8,142	1,953	1,072	(16,596)	1,074
Gain on dispositions		-	239	-	824	-	1,063
Other income (loss)		-	(384)	-	557	-	173
Intercompany revenues		35	162	43	5,627	(5,867)	-

Total Revenues and Other Income		6,538	24,272	1,996	28,384	(22,463)	38,727


Costs and Expenses
Purchased commodities		-	14,591	-	5,131	(5,428)	14,294
Production and operating expenses		-	1,023	4	4,245	(59)	5,213
Selling, general and administrative expenses		8	289	-	109	(5)	401
Exploration expenses		-	170	-	199	-	369
Depreciation, depletion and amortization		-	584	-	5,372	-	5,956
Impairments		-	(10)	-	37	-	27
Taxes other than income taxes		-	143	-	905	-	1,048
Accretion on discounted liabilities		-	17	-	336	-	353
Interest and debt expense		295	613	46	156	(375)	735
Foreign currency transaction (gains) losses		46	(12)	116	(167)	-	(17)
Other expenses		-	349	6	20	-	375

Total Costs and Expenses		349	17,757	172	16,343	(5,867)	28,754

Income before income taxes		6,189	6,515	1,824	12,041	(16,596)	9,973
Income tax provision (benefit)		(68)	12	(41)	3,765	-	3,668

Net income		6,257	6,503	1,865	8,276	(16,596)	6,305
Less: net income attributable to noncontrolling interests		-	-	-	(48)	-	(48)

Net Income Attributable to ConocoPhillips	$	6,257	6,503	1,865	8,228	(16,596)	6,257


Comprehensive Income Attributable to ConocoPhillips	$	5,654	5,900	1,364	7,961	(15,225)	5,654


Income Statement		Year Ended December 31, 2017*


Revenues and Other Income
Sales and other operating revenues	$	-	12,433	-	16,673	-	29,106
Equity in earnings (losses) of affiliates		(454)	2,047	886	770	(2,477)	772
Gain on dispositions		-	916	-	1,261	-	2,177
Other income		2	35	-	492	-	529
Intercompany revenues		48	291	13	3,369	(3,721)	-

Total Revenues and Other Income		(404)	15,722	899	22,565	(6,198)	32,584


Costs and Expenses
Purchased commodities		-	11,145	-	4,580	(3,250)	12,475
Production and operating expenses		-	813	-	4,366	(17)	5,162
Selling, general and administrative expenses		9	342	-	82	(6)	427
Exploration expenses		-	542	-	392	-	934
Depreciation, depletion and amortization		-	855	-	5,990	-	6,845
Impairments		-	1,159	-	5,442	-	6,601
Taxes other than income taxes		-	140	1	668	-	809
Accretion on discounted liabilities		-	32	-	330	-	362
Interest and debt expense		420	664	52	410	(448)	1,098
Foreign currency transaction (gains) losses		(43)	11	(137)	204	-	35
Other expenses		267	190	-	(6)	-	451

Total Costs and Expenses		653	15,893	(84)	22,458	(3,721)	35,199

Income (Loss) before income taxes		(1,057)	(171)	983	107	(2,477)	(2,615)
Income tax provision (benefit)		(202)	283	(337)	(1,566)	-	(1,822)

Net income (loss)		(855)	(454)	1,320	1,673	(2,477)	(793)
Less: net income attributable to noncontrolling interests		-	-	-	(62)	-	(62)

Net Income (Loss) Attributable to ConocoPhillips	$	(855)	(454)	1,320	1,611	(2,477)	(855)


Comprehensive Income (Loss) Attributable to ConocoPhillips	$	(180)	221	1,672	2,275	(4,168)	(180)

See Notes to Consolidated Financial Statements.


	Millions of Dollars

		Year Ended December 31, 2016*

Income Statement		ConocoPhillips		ConocoPhillips Company		Burlington Resources LLC		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated


Revenues and Other Income
Sales and other operating revenues	$	-		10,352		-		13,341		-		23,693
Equity in earnings (losses) of affiliates		(3,351	)	(1,051	)	(2,270	)	61		6,663		52
Gain on dispositions		-		120		-		240		-		360
Other income (loss)		1		(11	)	-		265		-		255
Intercompany revenues		88		277		21		2,995		(3,381	)	-

Total Revenues and Other Income		(3,262	)	9,687		(2,249	)	16,902		3,282		24,360


Costs and Expenses
Purchased commodities		-		9,144		-		3,562		(2,712	)	9,994
Production and operating expenses		-		754		1		5,130		(242	)	5,643
Selling, general and administrative expenses		8		331		-		140		(6	)	473
Exploration expenses		-		1,229		-		683		-		1,912
Depreciation, depletion and amortization		-		1,178		-		7,884		-		9,062
Impairments		-		67		-		72		-		139
Taxes other than income taxes		-		162		-		577		-		739
Accretion on discounted liabilities		-		46		-		379		-		425
Interest and debt expense		506		622		37		501		(421	)	1,245
Foreign currency transaction (gains) losses		(19	)	2		(110	)	108		-		(19	)
Other expenses		-		277		-		-		-		277

Total Costs and Expenses		495		13,812		(72	)	19,036		(3,381	)	29,890

Loss before income taxes		(3,757	)	(4,125	)	(2,177	)	(2,134	)	6,663		(5,530	)
Income tax benefit		(142	)	(774	)	(92	)	(963	)	-		(1,971	)

Net loss		(3,615	)	(3,351	)	(2,085	)	(1,171	)	6,663		(3,559	)
Less: net income attributable to noncontrolling interests		-		-		-		(56	)	-		(56	)

Net Loss Attributable to ConocoPhillips	$	(3,615	)	(3,351	)	(2,085	)	(1,227	)	6,663		(3,615	)


Comprehensive Loss Attributable to ConocoPhillips	$	(3,561	)	(3,297	)	(1,641	)	(1,149	)	6,087		(3,561	)

See Notes to Consolidated Financial Statements.


	Millions of Dollars

		At December 31, 2018

Balance Sheet		ConocoPhillips		ConocoPhillips Company	Burlington Resources LLC		All Other Subsidiaries	Consolidating Adjustments		Total Consolidated


Assets
Cash and cash equivalents	$	-		1,428	-		4,487	-		5,915
Short-term investments		-		-	-		248	-		248
Accounts and notes receivable		28		5,646	78		6,707	(8,392	)	4,067
Investment in Cenovus Energy		-		1,462	-		-	-		1,462
Inventories		-		184	-		823	-		1,007
Prepaid expenses and other current assets		1		267	-		307	-		575

Total Current Assets		29		8,987	78		12,572	(8,392	)	13,274
Investments, loans and long-term receivables*		29,942		47,062	15,199		16,926	(99,465	)	9,664
Net properties, plants and equipment		-		4,367	-		41,796	(465	)	45,698
Other assets		4		642	227		1,269	(798	)	1,344

Total Assets	$	29,975		61,058	15,504		72,563	(109,120	)	69,980


Liabilities and Stockholders’ Equity
Accounts payable	$	-		5,098	76		7,113	(8,392	)	3,895
Short-term debt		(3	)	12	13		99	(9	)	112
Accrued income and other taxes		-		85	-		1,235	-		1,320
Employee benefit obligations		-		638	-		171	-		809
Other accruals		85		587	35		552	-		1,259

Total Current Liabilities		82		6,420	124		9,170	(8,401	)	7,395
Long-term debt		3,791		7,151	2,143		2,249	(478	)	14,856
Asset retirement obligations and accrued environmental costs		-		415	-		7,273	-		7,688
Deferred income taxes		-		-	-		5,819	(798	)	5,021
Employee benefit obligations		-		1,340	-		424	-		1,764
Other liabilities and deferred credits*		725		9,277	839		8,126	(17,775	)	1,192

Total Liabilities		4,598		24,603	3,106		33,061	(27,452	)	37,916
Retained earnings		27,512		18,511	1,113		9,764	(22,890	)	34,010
Other common stockholders’ equity		(2,135	)	17,944	11,285		29,613	(58,778	)	(2,071	)
Noncontrolling interests		-		-	-		125	-		125

Total Liabilities and Stockholders’ Equity	$	29,975		61,058	15,504		72,563	(109,120	)	69,980


Balance Sheet		At December 31, 2017


Assets
Cash and cash equivalents	$	-		234	3		6,088	-		6,325
Short-term investments		-		-	-		1,873	-		1,873
Accounts and notes receivable		24		2,214	294		4,910	(3,122	)	4,320
Investment in Cenovus Energy		-		1,899	-		-	-		1,899
Inventories		-		163	-		897	-		1,060
Prepaid expenses and other current assets		1		277	24		763	(30	)	1,035

Total Current Assets		25		4,787	321		14,531	(3,152	)	16,512
Investments, loans and long-term receivables*		29,400		47,974	12,273		14,547	(94,134	)	10,060
Net properties, plants and equipment		-		4,230	-		41,930	(477	)	45,683
Other assets		15		1,146	672		1,043	(1,769	)	1,107

Total Assets	$	29,440		58,137	13,266		72,051	(99,532	)	73,362


Liabilities and Stockholders’ Equity
Accounts payable	$	-		3,094	264		3,794	(3,122	)	4,030
Short-term debt		(5	)	2,505	7		77	(9	)	2,575
Accrued income and other taxes		-		65	-		973	-		1,038
Employee benefit obligations		-		554	-		171	-		725
Other accruals		85		314	17		642	(29	)	1,029

Total Current Liabilities		80		6,532	288		5,657	(3,160	)	9,397
Long-term debt		3,787		9,321	500		3,998	(478	)	17,128
Asset retirement obligations and accrued environmental costs		-		432	-		7,199	-		7,631
Deferred income taxes		-		-	-		6,490	(1,208	)	5,282
Employee benefit obligations		-		1,335	-		519	-		1,854
Other liabilities and deferred credits*		1,528		5,229	1,446		10,135	(17,069	)	1,269

Total Liabilities		5,395		22,849	2,234		33,998	(21,915	)	42,561
Retained earnings		22,892		13,342	(753	)	7,669	(13,759	)	29,391
Other common stockholders’ equity		1,153		21,946	11,785		30,190	(63,858	)	1,216
Noncontrolling interests		-		-	-		194	-		194

Total Liabilities and Stockholders’ Equity	$	29,440		58,137	13,266		72,051	(99,532	)	73,362

*Includes intercompany loans.


	Millions of Dollars

Statement of Cash Flows		Year Ended December 31, 2018

		ConocoPhillips	ConocoPhillips Company	Burlington Resources LLC	All Other Subsidiaries	Consolidating Adjustments	Total Consolidated

Cash Flows From Operating Activities
Net Cash Provided by Operating Activities	$	4,317	4,183	2,764	14,132	(12,462)	12,934


Cash Flows From Investing Activities
Capital expenditures and investments		-	(980)	(603)	(5,777)	610	(6,750)
Working capital changes associated with investing activities		-	(110)	-	42	-	(68)
Proceeds from asset dispositions		-	502	-	705	(125)	1,082
Net sales of short-term investments		-	-	-	1,620	-	1,620
Long-term advances/loans—related parties		-	(126)	(173)	(10)	309	-
Collection of advances/loans—related parties		589	3,432	212	129	(4,243)	119
Intercompany cash management		(803)	3,504	(2,150)	(551)	-	-
Other		-	151	-	3	-	154

Net Cash Provided by (Used in) Investing Activities		(214)	6,373	(2,714)	(3,839)	(3,449)	(3,843)


Cash Flows From Financing Activities
Issuance of debt		-	10	-	299	(309)	-
Repayment of debt		-	(4,865)	(53)	(4,320)	4,243	(4,995)
Issuance of company common stock		254	-	-	-	(133)	121
Repurchase of company common stock		(2,999)	-	-	-	-	(2,999)
Dividends paid		(1,363)	(1,043)	-	(6,057)	7,100	(1,363)
Other		5	(3,468)	-	(1,670)	5,010	(123)

Net Cash Used in Financing Activities		(4,103)	(9,366)	(53)	(11,748)	15,911	(9,359)


Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Cash		-	4	-	(121)	-	(117)


Net Change in Cash, Cash Equivalents and Restricted Cash		-	1,194	(3)	(1,576)	-	(385)
Cash, cash equivalents and restricted cash at beginning of period*		-	234	3	6,299	-	6,536

Cash, Cash Equivalents and Restricted Cash at End of Period	$	-	1,428	-	4,723	-	6,151


Statement of Cash Flows		Year Ended December 31, 2017


Cash Flows From Operating Activities
Net Cash Provided by Operating Activities	$	71	1,183	2,971	5,904	(3,052)	7,077


Cash Flows From Investing Activities
Capital expenditures and investments		-	(1,663)	(4,351)	(3,795)	5,218	(4,591)
Working capital changes associated with investing activities		-	194	-	(62)	-	132
Proceeds from asset dispositions		7,765	11,146	12,178	12,796	(30,025)	13,860
Net purchases of short-term investments		-	-	-	(1,790)	-	(1,790)
Long-term advances/loans—related parties		-	(214)	(65)	(20)	299	-
Collection of advances/loans—related parties		658	1,527	389	2,196	(4,655)	115
Intercompany cash management		1,151	101	(1,341)	89	-	-
Other		-	(8)	-	44	-	36

Net Cash Provided by Investing Activities		9,574	11,083	6,810	9,458	(29,163)	7,762


Cash Flows From Financing Activities
Issuance of debt		-	20	-	279	(299)	-
Repayment of debt		(5,459)	(4,411)	-	(2,661)	4,655	(7,876)
Issuance of company common stock		115	-	-	-	(178)	(63)
Repurchase of company common stock		(3,000)	-	-	-	-	(3,000)
Dividends paid		(1,305)	(235)	-	(2,995)	3,230	(1,305)
Other		4	(7,765)	(9,781)	(7,377)	24,807	(112)

Net Cash Used in Financing Activities		(9,645)	(12,391)	(9,781)	(12,754)	32,215	(12,356)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		-	1	(2)	233	-	232


Net Change in Cash and Cash Equivalents		-	(124)	(2)	2,841	-	2,715
Cash and cash equivalents at beginning of period		-	358	5	3,247	-	3,610

Cash and Cash Equivalents at End of Period	$	-	234	3	6,088	-	6,325

*Restated to include $211 million of restricted cash at January 1, 2018. See Note 2—Changes in Accounting Principles for additional information relating to the adoption of ASU No. 2016-18.

Restricted cash totaling $236 million is included in the “Other assets” line of our Consolidated Balance Sheet as of December 31, 2018.


	Millions of Dollars

Statement of Cash Flows	Year Ended December 31, 2016

		ConocoPhillips	ConocoPhillips Company	Burlington Resources LLC	All Other Subsidiaries	Consolidating Adjustments	Total Consolidated

Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	(306)	(322)	799	5,902	(1,670)	4,403


Cash Flows From Investing Activities
Capital expenditures and investments		-	(989)	(1,714)	(4,281)	2,115	(4,869)
Working capital changes associated with investing activities		-	(126)	-	(205)	-	(331)
Proceeds from asset dispositions		2,300	266	-	1,114	(2,394)	1,286
Net purchases of short-term investments		-	-	-	(51)	-	(51)
Long-term advances/loans—related parties		-	(812)	-	-	812	-
Collection of advances/loans—related parties		-	391	-	272	(555)	108
Intercompany cash management		(2,214)	1,433	912	(131)	-	-
Other		-	1	-	(3)	-	(2)

Net Cash Provided by (Used in) Investing Activities		86	164	(802)	(3,285)	(22)	(3,859)


Cash Flows From Financing Activities
Issuance of debt		1,600	2,994	-	812	(812)	4,594
Repayment of debt		(150)	(164)	-	(2,492)	555	(2,251)
Issuance of company common stock		148	-	-	-	(211)	(63)
Repurchase of company common stock		(126)	-	-	-	-	(126)
Dividends paid		(1,253)	-	-	(1,881)	1,881	(1,253)
Other		1	(2,315)	-	1,898	279	(137)

Net Cash Provided by (Used in) Financing Activities		220	515	-	(1,663)	1,692	764


Effect of Exchange Rate Changes on Cash and Cash Equivalents		-	(3)	2	(65)	-	(66)


Net Change in Cash and Cash Equivalents		-	354	(1)	889	-	1,242
Cash and cash equivalents at beginning of period		-	4	6	2,358	-	2,368

Cash and Cash Equivalents at End of Period	$	-	358	5	3,247	-	3,610

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