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Notes to Consolidated Financial Statements
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ConocoPhillips
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Note 1Accounting Policies
∎
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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 either classified as available-for-sale if fair value is readily determinable, or the cost method is used if fair value is not readily determinable. 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.
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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 24Segment Disclosures and Related Information. Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements
relates to our continuing operations.
∎
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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. Most of our foreign operations use their local currency as the functional currency.
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∎
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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.
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∎
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Revenue Recognition
Revenues associated with sales of crude oil, bitumen, natural gas, liquefied natural gas (LNG), natural gas liquids and other items are recognized when title passes to the customer, which
is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.
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Revenues associated with producing properties in which we have an interest with other producers are recognized based on the actual volumes we
sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be nonrecoverable through remaining production, are recognized as accounts receivable or accounts payable,
as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant.
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).
∎
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Shipping and Handling Costs
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 recorded as a component of revenue.
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∎
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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.
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∎
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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.
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86
∎
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Inventories
We have several valuation methods for our various types of inventories and consistently use the following methods for each type of inventory. Commodity-related inventories are valued at the lower
of cost or market in the aggregate, primarily on the last-in, first-out (LIFO) basis. 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.
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∎
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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.
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∎
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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.
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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. For derivative instruments that are designated and qualify as a fair value hedge, the gains or losses from
adjusting the derivative to its fair value will be immediately recognized in earnings and, to the extent the hedge is effective, offset the concurrent recognition of changes in the fair value of the hedged item.
∎
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Oil and Gas Exploration and Development
Oil and gas exploration and development costs are accounted for using the successful efforts method of accounting.
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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 managements 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.
87
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 8Suspended 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.
∎
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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.
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∎
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Depreciation and Amortization
Depreciation and amortization of PP&E on producing hydrocarbon properties and certain pipeline 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).
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∎
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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 assetsgenerally 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.
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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.
88
∎
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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.
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∎
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Maintenance and Repairs
Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.
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∎
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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, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.
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∎
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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. For additional
information, see Note 10Asset Retirement Obligations and Accrued Environmental Costs.
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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.
∎
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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.
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∎
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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.
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∎
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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.
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89
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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.
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∎
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Taxes Collected from Customers and Remitted to Governmental Authorities
Sales and value-added taxes are recorded net.
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∎
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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.
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Note 2Change in Accounting Principles
We adopted
the provisions of Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2015-02, Amendments to the Consolidation Analysis, beginning January 1, 2016. The ASU amends existing requirements applicable
to reporting entities that are required to evaluate whether certain legal entities, including variable interest entities (VIEs), should be consolidated. The adoption of this ASU did not have an impact on our consolidated financial statements and
disclosures. See Note 4 Variable Interest Entities, for additional information on our significant VIEs.
Note 3Discontinued Operations
On December 20, 2012, we entered into agreements with affiliates of Oando PLC to sell our Nigeria business, which was previously part of the
Other International operating segment. On July 30, 2014, we completed the sale for $1,359 million, inclusive of $550 million deposits previously received. The deposits had been included in the Other accruals line on our consolidated
balance sheet and in the Other line of cash flows from investing activities on our consolidated statement of cash flows. The deposits received included $435 million in 2012, $15 million in 2013, and $100 million in 2014. We
recognized a before-tax gain of $1,052 million, which is included in the Income from discontinued operations line on our consolidated income statement.
Sales and other operating revenues and income from discontinued operations related to the Nigeria business during 2014 were as follows:
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Millions of Dollars
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|
|
|
|
|
|
|
|
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2014
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|
|
|
|
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Sales and other operating revenues from discontinued operations
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$
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480
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|
|
|
|
|
Income from discontinued operations before-tax
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$
|
1,147
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Income tax expense
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|
|
16
|
|
|
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Income from discontinued operations
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$
|
1,131
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|
|
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90
Note 4Variable 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, 2016, 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 7Investments, Loans and Long-Term Receivables, and Note 12Guarantees, 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. During the year ended December 31, 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, 2016, the book value of our equity method investment in MWCC was $148 million. We have not provided any financial support to MWCC other than amounts previously contractually required. Unless we elect otherwise, we have no
requirement to provide liquidity or purchase the assets of MWCC.
Note 5Inventories
Inventories at December 31 were:
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Millions of Dollars
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|
|
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|
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|
|
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2016
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas
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$
|
418
|
|
|
|
406
|
|
Materials and supplies
|
|
|
600
|
|
|
|
718
|
|
|
|
|
|
$
|
1,018
|
|
|
|
1,124
|
|
|
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Inventories valued on the LIFO basis totaled $269 million and $317 million at December 31, 2016 and 2015,
respectively. The estimated excess of current replacement cost over LIFO cost of inventories was approximately $104 million and $6 million at December 31, 2016 and December 31, 2015, respectively. In 2016, liquidation of LIFO
inventory values increased the net loss from continuing operations by $9 million.
91
Note 6Assets Held for Sale or Sold
Assets Sold
All gains or losses are reported before-tax
and are included net in the Gain on dispositions line on our consolidated income statement.
2016
On April 22, 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 asset retirement obligations (ARO).
On October 13, 2016, we completed an asset exchange
with Bonavista Energy in which we gave up approximately 141,000 net acres of non-core 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 a before-tax 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. In the fourth quarter, a loss on disposition of approximately
$
1 million was recognized upon completion of the transaction. The divested properties were included in the Canada segment.
On October 28, 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.
On November 17, 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. Previously, in the third quarter of 2016, we recognized a before-tax 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.
On December 8, 2016, we completed the sale of certain mineral and non-mineral fee lands in northeastern Minnesota, which was 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 and in November 2016, upon completion of the wind-down period, documents memorializing ConocoPhillips ownership of certain Trust property, including all of the Trusts 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.
92
2015
In November 2015, we sold a portion of our western Canadian properties located in British Columbia, Alberta, and Saskatchewan for $198 million and recognized a
gain on disposition of $66 million. At the time of the disposition, the carrying value of our interest, which was included in the Canada segment, was $132 million, which included primarily $379 million of PP&E and $248 million of ARO.
In December 2015, we sold a portion of our western Canadian properties located in central Alberta for $130 million and recognized a loss on disposition
of $235 million. At the time of the disposition, the carrying value of our interest, which was included in the Canada segment, was approximately $365 million, which included primarily $488 million of PP&E and $126 million of ARO.
Additionally, other December 2015 disposition transactions are summarized below.
We sold producing properties in East Texas and North Louisiana for $412 million and recognized a gain on disposition of $189 million. At the time of the
disposition, the carrying value of our interest, which was included in the Lower 48 segment, was $223 million, which included $351 million of PP&E and $128 million of ARO.
We sold certain gas producing properties in South Texas for $358 million and recognized a gain on disposition of $201 million. At the time of the disposition,
the carrying value of our interest, which was included in the Lower 48 segment, was $157 million, which included $369 million of PP&E and $212 million of ARO.
We sold certain pipeline and gathering assets in South Texas for $201 million and recognized a gain on disposition of $193 million. At the time of the
disposition, the carrying value of our interest, which was included in the Lower 48 segment, was $8 million, which primarily included $24 million of PP&E and $18 million of ARO.
We also sold our 50 percent interest in the Russian joint venture, Polar Lights Company, for $98 million and recognized a gain on disposition of $58
million. At the time of the disposition, the carrying value of our equity method investment in Polar Lights Company, which was included in our Other International segment, was approximately $40 million.
2014
For information on the sale of our Nigeria
business, which is included in the Income from discontinued operations line on our consolidated income statement, see Note 3Discontinued Operations.
Note 7Investments, Loans and Long-Term Receivables
Components of investments, loans and long-term receivables at December 31 were:
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|
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Millions of Dollars
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Equity investments
|
|
$
|
20,364
|
|
|
|
19,850
|
|
Loans and advancesrelated parties
|
|
|
581
|
|
|
|
696
|
|
Long-term receivables
|
|
|
631
|
|
|
|
519
|
|
Other investments
|
|
|
96
|
|
|
|
121
|
|
|
|
|
|
$
|
21,672
|
|
|
|
21,186
|
|
|
|
93
Equity Investments
Affiliated companies in which we had a significant equity investment at December 31, 2016, included:
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APLNG37.5 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.
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FCCL Partnership50 percent owned business venture with Cenovus Energy Inc.produces bitumen in the Athabasca oil sands in northeastern Alberta and sells the bitumen blend.
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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 Qatars North Field, as well as exports LNG.
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Summarized 100 percent earnings information for equity method investments
in affiliated companies, combined, was as follows:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
10,149
|
|
|
|
11,003
|
|
|
|
19,243
|
|
Income before income taxes
|
|
|
660
|
|
|
|
1,866
|
|
|
|
6,746
|
|
Net income
|
|
|
799
|
|
|
|
1,801
|
|
|
|
6,630
|
|
|
|
Summarized 100 percent balance sheet information for equity method investments in affiliated companies, combined, was as
follows:
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|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
3,578
|
|
|
|
2,504
|
|
Noncurrent assets
|
|
|
60,243
|
|
|
|
58,431
|
|
Current liabilities
|
|
|
2,352
|
|
|
|
1,863
|
|
Noncurrent liabilities
|
|
|
23,764
|
|
|
|
24,820
|
|
|
|
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 in our consolidated financial statements.
At December 31, 2016, retained earnings included $1,392 million
related to the undistributed earnings of affiliated companies. Dividends received from affiliates were $398 million, $876 million and $2,648 million in 2016, 2015 and 2014, respectively.
APLNG
APLNG is focused on coalbed methane production
from the Bowen and Surat basins in Queensland, Australia, and 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 APLNGs 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 is 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, 2016, $8.5 billion had been drawn from the facility.
94
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. See Note 12Guarantees, for additional information.
APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support.
See Note 4Variable 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 (losses) of affiliates line of our consolidated income statement.
During the fourth
quarter of 2015, due to the outlook for crude oil and natural gas prices at that time, the estimated fair value of our investment in APLNG declined to an amount below book value. Accordingly, we recorded a noncash $1,502 million before- and
after-tax impairment, in our fourth-quarter 2015 results.
During the third quarter of 2016, the outlook for crude oil prices weakened again, and as a
result, the estimated fair value of our investment in APLNG declined to an amount below book value as of September 30, 2016. Based on a review of the facts and circumstances surrounding this decline in fair value, we concluded the impairment
was not other than temporary under the guidance of FASB Accounting Standards Codification (ASC) Topic 323, Investments Equity Method and Joint Ventures.
During the fourth quarter of 2016, primarily due to the impact of accretion on discounted cash flows from the passage of time and strengthening of the U.S.
dollar, the estimated fair value of our investment increased and is above book value as of December 31, 2016. The expected future cash flows used for the impairment review of our investment in APLNG are based on 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. Unfavorable changes in any of these assumptions could result in a reduction in future cash flows and could indicate impairment in the future. Subsequent to December 31, 2016, the outlook for crude prices
and the U.S. dollar exchange rate relative to the Australian dollar has weakened. If these outlooks remain unchanged, we expect the estimated fair value of our investment in APLNG to be below book value at March 31, 2017.
At December 31, 2016, the book value of our equity method investment in APLNG was $10,089 million. The historical cost basis of our
37.5 percent share of net assets on the books of APLNG under U.S. generally accepted accounting principles was $8,348 million, resulting in a basis difference of $1,741 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 2016, 2015 and 2014 was
after-tax expense of $92 million, $21 million and $24 million, respectively, representing the amortization of this basis difference on currently producing licenses.
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. We account for our investment in FCCL under the equity method of accounting, with the operating results of our
investment in FCCL converted to reflect the use of the successful efforts method of accounting for oil and gas exploration and development activities.
95
At December 31, 2016, the book value of our investment in FCCL was $8,784 million, net of a $1,706 million
reduction due to cumulative foreign currency translation effects. FCCLs operating assets consist of the Foster Creek and Christina Lake steam-assisted gravity drainage bitumen projects, both located in the eastern flank of the Athabasca oil
sands in northeastern Alberta. Cenovus is the operator and managing partner of FCCL.
We were obligated to contribute $7.5 billion, plus accrued interest,
to FCCL over a 10-year period that began in 2007. In December 2013, we repaid the remaining balance of the obligation, which totaled $2,810 million. In the first quarter of 2014, we received a $1.3 billion distribution from FCCL, which is included
in the Undistributed equity earnings line on our consolidated statement of cash flows.
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
$696 million as described below under Loans and Long-Term Receivables. At December 31, 2016, the book value of our equity method investment in QG3, excluding the project financing, was $869 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.
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
agreements stated interest rate. Loans and long-term receivables are assessed for impairment when events indicate the loan balance may not be fully recovered.
Through November 2014, we had an agreement with Freeport LNG Development, L.P. (Freeport LNG) to participate in an LNG receiving terminal in Quintana, Texas.
We had no ownership in Freeport LNG; however, we had a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which serves as the general partner managing the venture. We had entered into a credit agreement with Freeport LNG, whereby we agreed
to provide loan financing for the construction of the terminal. We also entered into a long-term agreement with Freeport LNG to use 0.9 billion cubic feet per day of regasification capacity, which would have expired in 2033. When the terminal became
operational in June 2008, we began making payments under the terminal use agreement. Freeport LNG began making loan repayments in September 2008.
In July
2013, we reached an agreement with Freeport LNG to terminate our long-term agreement at the Freeport LNG Terminal, subject to Freeport LNG obtaining regulatory approval and project financing for an LNG liquefaction and export facility in Texas, in
which we are not a participant. These conditions were satisfied in 2014, and we paid Freeport LNG a termination fee of $522 million. Freeport LNG repaid the outstanding $454 million ConocoPhillips loan used by Freeport LNG to partially fund the
original construction of the terminal. The payment made to Freeport LNG to terminate our long-term agreement is included in the cash flows from operating activities section on our consolidated statement of cash flows, while the receipt of the funds
from Freeport LNG to repay the outstanding loan is included in the cash flows from investing activities section in 2014. These transactions, plus miscellaneous items, including the disposal of our 50 percent interest in Freeport GP, resulted in
a one-time net cash outflow of $63 million for us. In addition, we recognized an after-tax charge to earnings of $540 million in 2014, and our terminal regasification capacity was reduced to zero.
96
At December 31, 2016, significant loans to affiliated companies include $696 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 advancesrelated parties line on our consolidated balance sheet, while the
short-term portion is in Accounts and notes receivablerelated parties.
Note 8Suspended Wells and Other Exploration
Expenses
The following table reflects the net changes in suspended exploratory well costs during 2016, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
Beginning balance at January 1
|
|
$
|
1,260
|
|
|
|
1,299
|
|
|
|
994
|
|
Additions pending the determination of proved reserves
|
|
|
225
|
|
|
|
331
|
|
|
|
478
|
|
Reclassifications to proved properties
|
|
|
(27)
|
|
|
|
(28)
|
|
|
|
(9)
|
|
Sales of suspended well investment
|
|
|
(247)
|
|
|
|
-
|
|
|
|
(57)
|
|
Charged to dry hole expense
|
|
|
(148)
|
|
|
|
(342)
|
|
|
|
(107)
|
|
|
|
Ending balance at December 31
|
|
$
|
1,063
|
|
|
|
1,260
|
|
|
|
1,299
|
|
|
|
The following table provides an aging of suspended well balances at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
Exploratory well costs capitalized for a period of one year or less
|
|
$
|
132
|
|
|
|
235
|
|
|
|
466
|
|
Exploratory well costs capitalized for a period greater than one year
|
|
|
931
|
|
|
|
1,025
|
|
|
|
833
|
|
|
|
Ending balance
|
|
$
|
1,063
|
|
|
|
1,260
|
|
|
|
1,299
|
|
|
|
Number of projects with exploratory well costs capitalized for a period greater than one
year
|
|
|
26
|
|
|
|
28
|
|
|
|
30
|
|
|
|
97
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, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Suspended Since
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
20132015
|
|
|
|
20102012
|
|
|
|
20022009
|
|
|
|
|
|
|
|
|
|
|
|
Greater PoseidonAustralia
(2)
|
|
|
177
|
|
|
|
157
|
|
|
|
15
|
|
|
|
5
|
|
ShenandoahLower 48
(1)
|
|
|
161
|
|
|
|
118
|
|
|
|
-
|
|
|
|
43
|
|
Greater ClairUK
(2)
|
|
|
131
|
|
|
|
120
|
|
|
|
11
|
|
|
|
-
|
|
Surmont 3 and beyondCanada
(1)
|
|
|
107
|
|
|
|
55
|
|
|
|
29
|
|
|
|
23
|
|
NPRAAlaska
(1)
|
|
|
93
|
|
|
|
70
|
|
|
|
-
|
|
|
|
23
|
|
Caldita/BarossaAustralia
(1)
|
|
|
77
|
|
|
|
-
|
|
|
|
-
|
|
|
|
77
|
|
Middle Magdalena
BasinColombia
(1)
|
|
|
31
|
|
|
|
31
|
|
|
|
-
|
|
|
|
-
|
|
LimbayongMalaysia
(1)
|
|
|
23
|
|
|
|
23
|
|
|
|
-
|
|
|
|
-
|
|
Alpine SatelliteAlaska
(2)
|
|
|
22
|
|
|
|
-
|
|
|
|
-
|
|
|
|
22
|
|
BohaiChina
(2)
|
|
|
19
|
|
|
|
19
|
|
|
|
-
|
|
|
|
-
|
|
Kamunsu EastMalaysia
(2)
|
|
|
19
|
|
|
|
19
|
|
|
|
-
|
|
|
|
-
|
|
NC 98Libya
(2)
|
|
|
15
|
|
|
|
11
|
|
|
|
-
|
|
|
|
4
|
|
SunriseAustralia
(2)
|
|
|
13
|
|
|
|
-
|
|
|
|
-
|
|
|
|
13
|
|
Other of $10 million or less
each
(1)(2)
|
|
|
43
|
|
|
|
25
|
|
|
|
3
|
|
|
|
15
|
|
|
|
Total
|
|
$
|
931
|
|
|
|
648
|
|
|
|
58
|
|
|
|
225
|
|
|
|
(1)Additional appraisal wells planned.
(2)Appraisal drilling complete; costs being incurred to assess development.
In line with our July 2015 announcement of plans to reduce future deepwater exploration spending, we recognized before-tax cancellation costs of $335 million
and wrote off $48 million of before-tax capitalized rig costs in relation to the termination of our Gulf of Mexico deepwater drillship contract with Ensco in the Lower 48 segment in the third quarter of 2015. 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. These charges are included in the Exploration expenses line on our consolidated income statement.
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 will recognize a before-tax charge of $43 million net in the first quarter of 2017.
98
Note 9Impairments
During 2016, 2015 and 2014, we recognized the following before-tax impairment charges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
$
|
1
|
|
|
|
10
|
|
|
|
59
|
|
Lower 48
|
|
|
149
|
|
|
|
(2
|
)
|
|
|
208
|
|
Canada
|
|
|
88
|
|
|
|
4
|
|
|
|
38
|
|
Europe and North Africa
|
|
|
(160
|
)
|
|
|
724
|
|
|
|
541
|
|
Asia Pacific and Middle East
|
|
|
44
|
|
|
|
1,508
|
|
|
|
7
|
|
Corporate
|
|
|
17
|
|
|
|
1
|
|
|
|
3
|
|
|
|
|
|
$
|
139
|
|
|
|
2,245
|
|
|
|
856
|
|
|
|
2016
In 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 asset retirement obligation estimates.
In Canada, we recorded impairments of $88 million mainly due to plan of development changes, as well as certain developed properties, which were classified as
held for sale, being written down to fair value less costs to sell.
In Europe, we recorded a credit to impairment of $160 million, primarily in the
United Kingdom, due to decreased asset retirement obligation estimates on fields that are nearing the end of life and 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 the 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, 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 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 further testing of
undeveloped leaseholds.
2015
See the
APLNG section of Note 7Investments, Loans and Long-Term Receivables, for information on the impairment of our APLNG investment included within the Asia Pacific and Middle East segment.
99
In Europe, we recorded impairments of $724 million, primarily in the United Kingdom as a result of lower natural
gas prices and increases to asset retirement obligations.
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 Other International segment, we decided not to
pursue further evaluation of our Block 36 and Block 37 leases in Angola due to lack of commerciality of wells. Accordingly, we recorded impairments of $377 million and $116 million, respectively, for the associated carrying values of
capitalized undeveloped leasehold costs.
In our Lower 48 segment, we decided not to conduct further activity on certain Gulf of Mexico leases, given our
strategic plans to reduce deepwater exploration spending, and accordingly recorded impairments of $399 million for the associated carrying value of certain capitalized undeveloped leasehold costs.
In our Asia Pacific and Middle East segment, we decided to relinquish our Palangkaraya PSC in Indonesia. Accordingly, we recorded an impairment of $105
million for the associated carrying values of capitalized undeveloped leasehold cost.
In our Alaska segment, we recorded an impairment of $575 million
for the associated carrying value of capitalized undeveloped leasehold cost in the Chukchi Sea in Alaska.
In our Canada segment, we recorded an
impairment of $102 million for the Duvernay, Thornbury, Saleski and Crow Lake areas driven primarily by the lack of commerciality of wells.
2014
In Alaska, we recorded impairments of $59
million, primarily due to a cancelled project.
In our Lower 48 segment, we recorded impairments of $208 million, primarily as a result of reduced volume
forecasts for an onshore field, as well as an LNG-related pipeline.
We recorded impairments of $38 million in our Canada segment, primarily due to
reduced volume forecasts and lower natural gas prices.
In Europe, we recorded impairments of $541 million, mainly due to reduced volume forecasts,
increases in the ARO and lower natural gas prices for properties in the United Kingdom which are nearing the end of their useful lives.
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 unproved property impairments of $239 million, primarily due to decisions to discontinue further testing of the
undeveloped leaseholds.
Additionally, we decided not to pursue future development of the Amauligak discovery. Accordingly, we recorded a $145 million
property impairment for the carrying value of capitalized undeveloped leasehold costs associated with our Amauligak, Arctic Islands and other Beaufort properties located offshore Canada.
100
Note 10Asset Retirement Obligations and Accrued Environmental Costs
Asset retirement obligations and accrued environmental costs at December 31 were:
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
$
|
8,405
|
|
|
|
9,911
|
|
Accrued environmental costs
|
|
|
247
|
|
|
|
258
|
|
|
|
Total asset retirement obligations and accrued environmental costs
|
|
|
8,652
|
|
|
|
10,169
|
|
Asset retirement obligations and accrued environmental costs due within one year*
|
|
|
(227
|
)
|
|
|
(589
|
)
|
|
|
Long-term asset retirement obligations and accrued environmental costs
|
|
$
|
8,425
|
|
|
|
9,580
|
|
|
|
*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 asset retirement obligation 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 asset retirement obligations 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 2016 and 2015, our overall asset retirement obligation changed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
$
|
9,911
|
|
|
|
10,939
|
|
Accretion of discount
|
|
|
420
|
|
|
|
480
|
|
New obligations
|
|
|
180
|
|
|
|
135
|
|
Changes in estimates of existing obligations
|
|
|
(1,197
|
)
|
|
|
267
|
|
Spending on existing obligations
|
|
|
(314
|
)
|
|
|
(437
|
)
|
Property dispositions
|
|
|
(150
|
)
|
|
|
(726
|
)
|
Foreign currency translation
|
|
|
(464
|
)
|
|
|
(747
|
)
|
Other
|
|
|
19
|
|
|
|
-
|
|
|
|
Balance at December 31
|
|
$
|
8,405
|
|
|
|
9,911
|
|
|
|
101
Accrued Environmental Costs
Total accrued environmental costs at December 31, 2016 and 2015, were $247 million and $258 million, respectively.
We had accrued environmental costs of $183 million and $184 million at December 31, 2016 and 2015, respectively, related to remediation
activities in the United States and Canada. We had also accrued in Corporate and Other $51 million and $57 million of environmental costs associated with sites no longer in operation at December 31, 2016 and 2015, respectively. In
addition, $13 million and $17 million were included at both December 31, 2016 and 2015, 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 $92 million at
December 31, 2016. The expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are: $9 million in 2017, $12 million in 2018, $8 million in 2019, $5 million in 2020, $4 million in
2021, and $110 million for all future years after 2021.
102
Note 11Debt
Long-term debt at December 31 was:
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
9.125% Debentures due 2021
|
|
$
|
150
|
|
|
|
150
|
|
8.20% Debentures due 2025
|
|
|
150
|
|
|
|
150
|
|
8.125% Notes due 2030
|
|
|
600
|
|
|
|
600
|
|
7.9% Debentures due 2047
|
|
|
100
|
|
|
|
100
|
|
7.8% Debentures due 2027
|
|
|
300
|
|
|
|
300
|
|
7.65% Debentures due 2023
|
|
|
88
|
|
|
|
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
|
|
6.65% Debentures due 2018
|
|
|
297
|
|
|
|
297
|
|
6.50% Notes due 2039
|
|
|
2,750
|
|
|
|
2,750
|
|
6.00% Notes due 2020
|
|
|
1,000
|
|
|
|
1,000
|
|
5.951% Notes due 2037
|
|
|
645
|
|
|
|
645
|
|
5.95% Notes due 2036
|
|
|
500
|
|
|
|
500
|
|
5.95% Notes due 2046
|
|
|
500
|
|
|
|
-
|
|
5.90% Notes due 2032
|
|
|
505
|
|
|
|
505
|
|
5.90% Notes due 2038
|
|
|
600
|
|
|
|
600
|
|
5.75% Notes due 2019
|
|
|
2,250
|
|
|
|
2,250
|
|
5.625% Notes due 2016
|
|
|
-
|
|
|
|
1,250
|
|
5.20% Notes due 2018
|
|
|
500
|
|
|
|
500
|
|
4.95% Notes due 2026
|
|
|
1,250
|
|
|
|
-
|
|
4.30% Notes due 2044
|
|
|
750
|
|
|
|
750
|
|
4.20% Notes due 2021
|
|
|
1,250
|
|
|
|
-
|
|
4.15% Notes due 2034
|
|
|
500
|
|
|
|
500
|
|
3.35% Notes due 2024
|
|
|
1,000
|
|
|
|
1,000
|
|
3.35% Notes due 2025
|
|
|
500
|
|
|
|
500
|
|
2.875% Notes due 2021
|
|
|
750
|
|
|
|
750
|
|
2.4% Notes due 2022
|
|
|
1,000
|
|
|
|
1,000
|
|
2.2% Notes due 2020
|
|
|
500
|
|
|
|
500
|
|
1.5% Notes due 2018
|
|
|
750
|
|
|
|
750
|
|
1.05% Notes due 2017
|
|
|
1,000
|
|
|
|
1,000
|
|
Floating rate term loan due 2019 at 1.94% 2.31% during 2016
|
|
|
1,450
|
|
|
|
-
|
|
Floating rate notes due 2018 at 0.69% 1.24% during 2016 and 0.61% 0.69% during
2015
|
|
|
250
|
|
|
|
250
|
|
Floating rate notes due 2022 at 1.26% 1.81% during 2016 and 1.18% 1.26% during
2015
|
|
|
500
|
|
|
|
500
|
|
Commercial paper at 0.16% 0.80% during 2015
|
|
|
-
|
|
|
|
803
|
|
Industrial Development Bonds due 2016 through 2038 at 0.01% 0.91% during 2016 and 0.01%
0.13% during 2015
|
|
|
18
|
|
|
|
18
|
|
Marine Terminal Revenue Refunding Bonds due 2031 at 0.01% 0.95% during 2016 and 0.01%
0.14% during 2015
|
|
|
265
|
|
|
|
265
|
|
Other
|
|
|
24
|
|
|
|
24
|
|
|
|
|
|
Debt at face value
|
|
|
26,175
|
|
|
|
23,778
|
|
Capitalized leases
|
|
|
852
|
|
|
|
818
|
|
Net unamortized premiums, discounts and debt issuance costs
|
|
|
248
|
|
|
|
284
|
|
|
|
Total debt
|
|
|
27,275
|
|
|
|
24,880
|
|
Short-term debt
|
|
|
(1,089
|
)
|
|
|
(1,427
|
)
|
|
|
Long-term debt
|
|
$
|
26,186
|
|
|
|
23,453
|
|
|
|
103
Maturities of long-term borrowings, inclusive of net unamortized premiums and discounts, in 2017 through 2021
are: $1,089 million, $1,894 million, $3,784 million, $1,593 million and $2,235 million, respectively.
In the first quarter of 2016, we reduced our
revolving credit facility, expiring in June 2019, from $7.0 billion to $6.75 billion. Our revolving credit facility may be used for direct bank borrowings, for the issuance of letters of credit totaling up to $500 million, or as support for our
commercial paper programs. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or credit
ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or any of its consolidated subsidiaries.
Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the London interbank market 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.
We have two commercial paper programs supported by our $6.75
billion revolving credit facility: the ConocoPhillips $6.25 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $500 million program, which is used to fund commitments relating
to QG3. Commercial paper maturities are generally limited to 90 days.
At both December 31, 2016 and 2015, we had no direct outstanding borrowings
under the revolving credit facility, with no letters of credit as of December 31, 2016 and 2015. Under the ConocoPhillips Qatar Funding Ltd. commercial paper program, no commercial paper was outstanding at December 31, 2016, compared with
$803 million at December 31, 2015. Since we had no commercial paper outstanding and had issued no letters of credit, we had access to $6.75 billion in borrowing capacity under our revolving credit facility at December 31, 2016.
In March 2016, we issued notes consisting of:
|
|
|
The $1,250 million of 4.20% Notes due 2021.
|
|
|
|
The $1,250 million of 4.95% Notes due 2026.
|
|
|
|
The $500 million of 5.95% Notes due 2046.
|
In addition, on March 18, 2016, we entered into a $1,600
million three-year senior unsecured term loan facility. In December 2016, an early repayment of $150 million reduced the loan to $1,450 million. We have the right at any time and from time to time to prepay the term loan, in whole or in part,
without premium or penalty upon notice to the Administrative Agent. Borrowings will accrue interest at a base rate or, for certain Eurodollar borrowings, the London Interbank Offered Rate (LIBOR), in each case plus a margin that is set based on our
corporate credit ratings. The applicable margin for loans bearing interest based on the base rate ranges from 0.50% to 1.00% and the applicable margin for loans bearing interest based on LIBOR ranges from 1.50% to 2.00%. Based on our current
corporate credit ratings, the applicable margin for loans accruing interest at the base rate is 0.50% and the applicable margin for loans accruing interest at LIBOR is 1.50%.
The term loan facility contains customary covenants regarding, among other matters, material compliance with laws and restrictions against certain
consolidations, mergers and asset sales and creation of certain liens on our assets and consolidated subsidiaries. The term loan facility also contains financial covenants including a total debt to capitalization ratio, excluding the impacts of
certain noncash impairments and foreign currency translation adjustments as defined in the Term Loan Agreement, which may not exceed 65 percent. At December 31, 2016, we were in compliance with this covenant.
104
The term loan facility includes customary events of default (subject to specified cure periods, materiality
qualifiers and exceptions), including the failure to pay any interest, principal or fees when due, the failure to perform or the violation of any covenant contained in the term loan facility, the making of materially inaccurate or false
representations or warranties, a default on certain material indebtedness, insolvency or bankruptcy, a change of control and the occurrence of material Employee Retirement Income Security Act of 1974 (ERISA) events and certain judgments against us
or our material subsidiaries.
The net proceeds of the notes and term loan will be used for general corporate purposes.
On October 17, 2016, the $1,250 million 5.625% Notes due 2016 were repaid at maturity.
At both December 31, 2016 and 2015, 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. Unitization of the Gumusut development with Brunei was recorded during
the fourth quarter of 2015 and reduced our proportionate interest in the FPS from 33 percent to 29 percent. The net carrying value of the capital lease asset was approximately $540 million and $707 million as of December 31, 2016 and
December 31, 2015, 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, 2016 and December 31, 2015, accumulated depreciation of the capital lease asset amounted to approximately $268 million
and $122 million, respectively.
At December 31, 2016, future minimum payments due under capital leases were:
|
|
|
|
|
|
|
|
Millions
of Dollars
|
|
|
|
|
|
|
2017
|
|
$
|
121
|
|
2018
|
|
|
102
|
|
2019
|
|
|
102
|
|
2020
|
|
|
103
|
|
2021
|
|
|
88
|
|
Remaining years
|
|
|
590
|
|
|
|
Total
|
|
|
1,106
|
|
Less: portion representing imputed interest
|
|
|
(254
|
)
|
|
|
Capital lease obligations
|
|
$
|
852
|
|
|
|
105
Note 12Guarantees
At December 31, 2016, 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, 2016, 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 2016 exchange rates:
|
|
|
We have guaranteed APLNGs performance with regard to a construction contract executed in connection with APLNGs issuance of the Train 1 and Train 2 Notices to Proceed. We estimate the remaining term of this
guarantee is one year. Our maximum potential amount of future payments related to this guarantee is approximately $10 million and would become payable if APLNG cancels the applicable construction contract and does not perform with respect to
the amounts owed to the contractor.
|
|
|
|
We have issued a construction completion guarantee related to the third-party project financing secured by APLNG. Our guarantee of the project financing will be released upon meeting certain completion tests with
milestones which we estimate should occur in 2017. In October 2016, we reached financial completion for Train 1, releasing a portion of our guarantee. Our maximum exposure at December 31, 2016, is $1.3 billion based upon our pro-rata share of
the facility used at that date, which could be payable if completion of the project is not achieved. At December 31, 2016, the carrying value of this guarantee is approximately $46 million.
|
|
|
|
During the third quarter of 2016, we issued a guarantee for our pro-rata portion of the funds in a project finance reserve account. We estimate the remaining term of this guarantee is 13 years. Our maximum exposure
under this guarantee is approximately $60 million and may become payable if an enforcement action is commenced by the project finance lenders against APLNG. At December 31, 2016, the carrying value of this guarantee is approximately $9 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 1 to 25 years. Our maximum potential liability for future payments, or cost of volume delivery, under these guarantees is
estimated to be $1.0 billion ($1.7 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 projects continued development. The guarantees have remaining terms of up to 29 years or the
life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $160 million and would become payable if APLNG does not perform.
|
Other Guarantees
We have other guarantees with maximum
future potential payment amounts totaling approximately $540 million, which consist primarily of a guarantee of the residual value of a leased office building, guarantees of the residual value of leased corporate aircraft, and a guarantee for
our portion of a joint ventures project finance reserve accounts.
106
These guarantees have remaining terms of up to six 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, 2016, was approximately $100 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, 2016, were approximately $40 million
of environmental accruals for known contamination that are included in the Asset retirement obligations and accrued environmental costs line on our consolidated balance sheet. For additional information about environmental liabilities,
see Note 13Contingencies and Commitments.
On April 30, 2012, the separation of our downstream business was completed, creating two independent
energy companies: ConocoPhillips and Phillips 66. In connection with the separation, we entered into an Indemnification and Release Agreement, which provides for cross-indemnities between Phillips 66 and us and established procedures for handling
claims subject to indemnification and related matters. We evaluated the impact of the indemnifications given and the Phillips 66 indemnifications received as of the separation date and concluded those fair values were immaterial.
On March 1, 2015, a supplier to one of the refineries included in Phillips 66 as part of the separation of our downstream business formally registered
Phillips 66 as a party to the supply agreement, thereby triggering a guarantee we provided at the time of separation. Our maximum potential liability for future payments under this guarantee, which would become payable if Phillips 66 does not
perform its contractual obligations under the supply agreement, is approximately $1.4 billion. At December 31, 2016, the carrying value of this guarantee is approximately $98 million and the remaining term is eight years. Because Phillips 66
has indemnified us for losses incurred under this guarantee, we have recorded an indemnification asset from Phillips 66 of approximately $98 million. The recorded indemnification asset amount represents the estimated fair value of the guarantee;
however, if we are required to perform under the guarantee, we would expect to recover from Phillips 66 any amounts in excess of that value, provided Phillips 66 is a going concern.
Note 13Contingencies 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 19Income Taxes, for additional information about income tax-related contingencies.
107
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 managements 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 10Asset 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.
108
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, 2016, we had performance obligations secured by letters of credit of $304 million (issued as direct bank letters of credit) related to various purchase
commitments for materials, supplies, commercial activities and services incident to the ordinary conduct of business.
In 2007, we announced we had been
unable to reach agreement with respect to our migration to an
empresa mixta
structure mandated by the Venezuelan governments Nationalization Decree. As a result, Venezuelas national oil company, Petróleos de Venezuela S.A.
(PDVSA), or its affiliates, directly assumed control over ConocoPhillips interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, we filed a request for
international arbitration on November 2, 2007, with the World Banks International Centre for Settlement of Investment Disputes (ICSID). An arbitration hearing was held before an ICSID tribunal during the summer of 2010. On
September 3, 2013, an ICSID arbitration tribunal held that Venezuela unlawfully expropriated ConocoPhillips significant oil investments in June 2007. 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 Venezuelas actions. Separate arbitrations for contractual compensation against PDVSA are also pending before an
International Chamber of Commerce (ICC) arbitration tribunal. In addition, ConocoPhillips brought fraudulent transfer actions in the U.S. District Court of Delaware, alleging that PDVSA has taken actions to improperly expatriate assets from the
United States to Venezuela in an effort to avoid judgment creditors.
In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips,
initiated arbitration before ICSID against The Republic of Ecuador, as a result of the newly enacted Windfall Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite a restraining order issued by the ICSID
tribunal, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the seized crude oil. In 2009, Ecuador took over operations in Blocks 7 and 21, fully expropriating our assets. In June 2010, the ICSID tribunal
concluded it has jurisdiction to hear the expropriation claim. On April 24, 2012, Ecuador filed supplemental counterclaims asserting environmental damages, which we believe are not material. The ICSID tribunal issued a decision on liability on
December 14, 2012, in favor of Burlington, finding that Ecuadors seizure of Blocks 7 and 21 was an unlawful expropriation in violation of the Ecuador-U.S. Bilateral Investment Treaty. An additional arbitration phase to determine the
damages owed to ConocoPhillips for Ecuadors actions and to address Ecuadors counterclaims is complete. In February 2017, the tribunal unanimously awarded Burlington $380 million for Ecuadors unlawful expropriation and 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 limited environmental and infrastructure impacts associated with the operations of Burlington and its
co-venturer. Ecuador recently filed a request for annulment of this decision with ICSID. The schedule for the annulment process has not yet been set.
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. The arbitration will be conducted under the United Nations Commission on
International Trade Laws (UNCITRAL) rules using a three person tribunal.
109
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 companys business. The aggregate amounts of estimated payments under these various agreements are: 2017$24 million; 2018$20 million; 2019$7 million;
2020$7 million; 2021$7 million; and 2022 and after$75 million. Total payments under the agreements were $42 million in 2016, $27 million in 2015 and $127 million in 2014.
Note 14Derivative 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
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
Prepaid expenses and other current assets
|
|
$
|
268
|
|
|
|
768
|
|
Other assets
|
|
|
44
|
|
|
|
60
|
|
Liabilities
|
|
|
|
|
|
|
|
|
Other accruals
|
|
|
300
|
|
|
|
754
|
|
Other liabilities and deferred credits
|
|
|
34
|
|
|
|
46
|
|
|
|
The gains (losses) from commodity derivatives incurred, and the line items where they appear on our consolidated income
statement were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues
|
|
$
|
(198)
|
|
|
|
231
|
|
|
|
523
|
|
Other income
|
|
|
(1)
|
|
|
|
2
|
|
|
|
1
|
|
Purchased commodities
|
|
|
161
|
|
|
|
(201)
|
|
|
|
(458)
|
|
|
|
110
The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts:
|
|
|
|
|
|
|
|
|
|
|
Open Position
Long/(Short)
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
Commodity
|
|
|
|
|
|
|
|
|
Natural gas and power (billions of cubic feet equivalent)
|
|
|
|
|
|
|
|
|
Fixed price
|
|
|
(31)
|
|
|
|
(14
|
)
|
Basis
|
|
|
2
|
|
|
|
(17
|
)
|
|
|
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 and foreign currency exchange rate exposures, such as firm commitments for capital programs or local currency tax payments, dividends, and cash returns from net investments in foreign affiliates. We do not elect hedge
accounting on our foreign currency exchange derivatives.
The following table presents the gross fair values of our foreign currency exchange derivatives,
excluding collateral, and the line items where they appear on our consolidated balance sheet:
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
Prepaid expenses and other current assets
|
|
$
|
1
|
|
|
|
47
|
|
Liabilities
|
|
|
|
|
|
|
|
|
Other accruals
|
|
|
168
|
|
|
|
8
|
|
|
|
The (gains) losses from foreign currency exchange derivatives incurred, and the line item where they appear on our
consolidated income statement were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
Foreign currency transaction (gains) losses
|
|
$
|
247
|
|
|
|
(33)
|
|
|
|
3
|
|
|
|
We had the following net notional position of outstanding foreign currency exchange derivatives:
|
|
|
|
|
|
|
|
|
|
|
In Millions
Notional Currency
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
|
|
|
Foreign Currency Exchange Derivatives
|
|
|
|
|
|
|
|
|
Sell U.S. dollar, buy other currencies*
|
|
|
USD
13
|
|
|
|
347
|
|
Buy U.S. dollar, sell other currencies**
|
|
|
USD
25
|
|
|
|
20
|
|
Buy British pound, sell other currencies***
|
|
|
GBP
1,069
|
|
|
|
567
|
|
Sell British pound, buy Norwegian krone
|
|
|
GBP
51
|
|
|
|
-
|
|
|
|
*Primarily Canadian dollar, Norwegian krone and British pound.
**Primarily Canadian dollar and British pound.
***Primarily Canadian dollar and Euro.
111
Financial Instruments
We have certain financial instruments on our consolidated balance sheet related to interest-bearing time deposits and commercial paper. These
held-to-maturity financial instruments are included in Cash and cash equivalents on our consolidated balance sheet if the maturities at the time we made the investments were 90 days or less; otherwise, these investments are included
in Short-term investments on our consolidated balance sheet.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
Carrying Amount
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents
|
|
|
|
Short-Term Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
623
|
|
|
|
528
|
|
|
|
-
|
|
|
|
-
|
|
Time deposits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining maturities from 1 to 90 days
|
|
|
2,987
|
|
|
|
1,840
|
|
|
|
39
|
|
|
|
-
|
|
Remaining maturities from 91 to 180 days
|
|
|
-
|
|
|
|
-
|
|
|
|
11
|
|
|
|
-
|
|
|
|
|
|
$
|
3,610
|
|
|
|
2,368
|
|
|
|
50
|
|
|
|
-
|
|
|
|
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, money market funds, government debt securities and time deposits with major international banks and financial institutions.
The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty
exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit
risk because these trades are cleared with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash
calls, as well as for cash deposited to meet initial margin requirements.
Our trade receivables result primarily from our petroleum operations and
reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less, and we continually monitor this exposure and the
creditworthiness of the counterparties. We do not generally require collateral to limit the exposure to loss; however, we will sometimes use letters of credit, prepayments and master netting arrangements to mitigate credit risk with counterparties
that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due 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, 2016 and December 31, 2015, was $42 million and $158 million, respectively. For these instruments, no collateral was posted as of December 31, 2016, and $2 million of collateral was posted as of December 31, 2015.
112
If our credit rating had been downgraded below investment grade on December 31, 2016, we would be required to post $42 million of additional collateral, either with cash or letters of
credit.
Note 15Fair 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. There were no material transfers in or out of Level 1 during 2016 or 2015.
Recurring Fair Value Measurement
Financial assets and liabilities reported at fair value on a recurring basis primarily include 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 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 managements 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, 2016
|
|
|
December 31, 2015
|
|
|
|
|
Level 1
|
|
|
|
Level 2
|
|
|
|
Level 3
|
|
|
|
Total
|
|
|
|
Level 1
|
|
|
|
Level 2
|
|
|
|
Level 3
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
194
|
|
|
|
96
|
|
|
|
22
|
|
|
|
312
|
|
|
|
516
|
|
|
|
242
|
|
|
|
70
|
|
|
|
828
|
|
|
|
Total assets
|
|
$
|
194
|
|
|
|
96
|
|
|
|
22
|
|
|
|
312
|
|
|
|
516
|
|
|
|
242
|
|
|
|
70
|
|
|
|
828
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
207
|
|
|
|
105
|
|
|
|
22
|
|
|
|
334
|
|
|
|
515
|
|
|
|
273
|
|
|
|
12
|
|
|
|
800
|
|
|
|
Total liabilities
|
|
$
|
207
|
|
|
|
105
|
|
|
|
22
|
|
|
|
334
|
|
|
|
515
|
|
|
|
273
|
|
|
|
12
|
|
|
|
800
|
|
|
|
113
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, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
$
|
312
|
|
|
|
221
|
|
|
|
91
|
|
|
|
-
|
|
|
|
5
|
|
|
|
86
|
|
Liabilities
|
|
|
334
|
|
|
|
221
|
|
|
|
113
|
|
|
|
12
|
|
|
|
12
|
|
|
|
89
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
$
|
828
|
|
|
|
600
|
|
|
|
228
|
|
|
|
-
|
|
|
|
8
|
|
|
|
220
|
|
Liabilities
|
|
|
800
|
|
|
|
600
|
|
|
|
200
|
|
|
|
1
|
|
|
|
11
|
|
|
|
188
|
|
|
|
At December 31, 2016 and December 31, 2015, we did not present any amounts gross on our consolidated balance sheet
where we had the right of setoff.
Non-Recurring Fair Value Measurement
The following table summarizes the fair value hierarchy by major category for assets accounted for at fair value on a non-recurring basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
Measurements Using
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
Level 1
Inputs
|
|
|
|
Level 3
Inputs
|
|
|
|
Before-Tax
Loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net PP&E (held for use)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2016
|
|
$
|
217
|
|
|
|
-
|
|
|
|
217
|
|
|
|
129
|
|
June 30, 2016
|
|
|
23
|
|
|
|
-
|
|
|
|
23
|
|
|
|
53
|
|
December 31, 2016
|
|
|
13
|
|
|
|
-
|
|
|
|
13
|
|
|
|
29
|
|
Net PP&E (held for sale)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2016
|
|
|
217
|
|
|
|
217
|
|
|
|
-
|
|
|
|
99
|
|
Cost and equity method investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
|
90
|
|
|
|
4
|
|
|
|
86
|
|
|
|
40
|
|
|
|
|
|
|
|
|
Year ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net PP&E (held for use)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2015
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
9
|
|
June 30, 2015
|
|
|
42
|
|
|
|
-
|
|
|
|
42
|
|
|
|
70
|
|
September 30, 2015
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
7
|
|
December 31, 2015
|
|
|
440
|
|
|
|
-
|
|
|
|
440
|
|
|
|
595
|
|
Net PP&E (unproved property)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2015
|
|
|
104
|
|
|
|
-
|
|
|
|
104
|
|
|
|
240
|
|
Equity method investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
|
|
10,210
|
|
|
|
-
|
|
|
|
10,210
|
|
|
|
1,507
|
|
|
|
114
Net PP&E (held for use)
Net PP&E held for use is comprised of various producing properties impaired to their individual fair values less costs to sell. The fair values were
determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges and pricing service companies, costs, and a discount rate believed to be consistent with those used by principal market
participants.
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.
Net PP&E (unproved property)
Net
PP&E unproved property is comprised of unproved leaseholds impaired to our best estimate of sales value less costs to sell.
Equity Method
Investments
Certain cost and equity method investments were determined to have fair values below their carrying amounts, and the impairments were
considered to be other than temporary under the guidance of FASB ASC Topic 323. An investment using Level 1 inputs was written down to fair value, less costs to sell, determined by its negotiated selling price. Investments using Level 3 inputs had
fair values determined primarily by internal discounted cash flow models using estimates of future production, prices from futures exchanges and pricing service companies, costs, and a discount factor believed to be consistent with those used by
principal market participants. During 2015, this primarily included our investment in APLNG, which was written down to its fair value of $10,185 million, resulting in a charge of $1,502 million before-tax. For additional information on APLNG, see
Note 7Investments, 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 advancesrelated parties.
|
|
|
|
Loans and advancesrelated 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 7Investments, 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.
|
115
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
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
Financial assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives
|
|
$
|
91
|
|
|
|
228
|
|
|
|
91
|
|
|
|
228
|
|
Total loans and advancesrelated parties
|
|
|
701
|
|
|
|
808
|
|
|
|
701
|
|
|
|
808
|
|
Financial liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt, excluding capital leases
|
|
|
26,423
|
|
|
|
24,062
|
|
|
|
29,307
|
|
|
|
24,785
|
|
Commodity derivatives
|
|
|
101
|
|
|
|
199
|
|
|
|
101
|
|
|
|
199
|
|
|
|
Commodity derivatives
At December 31, 2016, commodity derivative assets and liabilities appear net with no obligations to return cash collateral and $12 million of rights to
reclaim cash collateral, respectively. At December 31, 2015, commodity derivative assets and liabilities appear net with no obligations to return cash collateral and $1 million of rights to reclaim cash collateral, respectively.
Note 16Equity
Common Stock
The changes in our shares of common stock, as categorized in the equity section of the balance sheet, were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
|
Issued
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
1,778,226,388
|
|
|
|
1,773,583,368
|
|
|
|
1,768,169,906
|
|
Distributed under benefit plans
|
|
|
3,852,719
|
|
|
|
4,643,020
|
|
|
|
5,413,462
|
|
|
|
End of year
|
|
|
1,782,079,107
|
|
|
|
1,778,226,388
|
|
|
|
1,773,583,368
|
|
|
|
|
|
|
|
Held in Treasury
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year
|
|
|
542,230,673
|
|
|
|
542,230,673
|
|
|
|
542,230,673
|
|
Repurchase of common stock
|
|
|
2,579,098
|
|
|
|
-
|
|
|
|
-
|
|
|
|
End of year
|
|
|
544,809,771
|
|
|
|
542,230,673
|
|
|
|
542,230,673
|
|
|
|
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, 2016 or 2015.
Noncontrolling Interests
At December 31, 2016 and
2015, we had $252 million and $320 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 over the next three years. Repurchase of shares began in
November and totaled 2,579,098 shares at a cost of $126 million, through December 31, 2016.
116
Note 17Non-Mineral Leases
The company primarily leases drilling equipment and office buildings, as well as ocean transport vessels, tugboats, barges, corporate aircraft, computers 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
11Debt.
At December 31, 2016, future minimum rental payments due under noncancelable leases were:
|
|
|
|
|
|
|
Millions
of Dollars
|
|
|
|
2017
|
|
$
|
277
|
|
2018
|
|
|
238
|
|
2019
|
|
|
172
|
|
2020
|
|
|
390
|
|
2021
|
|
|
114
|
|
Remaining years
|
|
|
435
|
|
|
|
Total
|
|
|
1,626
|
|
Less: income from subleases
|
|
|
(15)
|
|
|
|
Net minimum operating lease payments
|
|
$
|
1,611
|
|
|
|
Operating lease rental expense for the years ended December 31 was:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
Total rentals
|
|
$
|
537
|
|
|
|
432
|
|
|
|
474
|
|
Less: sublease rentals
|
|
|
(8)
|
|
|
|
(9)
|
|
|
|
(10)
|
|
|
|
|
|
$
|
529
|
|
|
|
423
|
|
|
|
464
|
|
|
|
117
Note 18Employee 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
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
Intl.
|
|
|
U.S.
|
|
|
Intl.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Benefit Obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at January 1
|
|
$
|
3,772
|
|
|
|
3,321
|
|
|
|
4,387
|
|
|
|
3,984
|
|
|
|
352
|
|
|
|
716
|
|
Service cost
|
|
|
108
|
|
|
|
76
|
|
|
|
138
|
|
|
|
124
|
|
|
|
2
|
|
|
|
4
|
|
Interest cost
|
|
|
133
|
|
|
|
120
|
|
|
|
161
|
|
|
|
135
|
|
|
|
13
|
|
|
|
22
|
|
Plan participant contributions
|
|
|
-
|
|
|
|
3
|
|
|
|
-
|
|
|
|
5
|
|
|
|
24
|
|
|
|
21
|
|
Plan amendments
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(27)
|
|
|
|
(303)
|
|
Actuarial (gain) loss
|
|
|
247
|
|
|
|
466
|
|
|
|
(212)
|
|
|
|
(442)
|
|
|
|
(14)
|
|
|
|
(49)
|
|
Benefits paid
|
|
|
(872)
|
|
|
|
(148)
|
|
|
|
(729)
|
|
|
|
(162)
|
|
|
|
(68)
|
|
|
|
(63)
|
|
Curtailment
|
|
|
14
|
|
|
|
10
|
|
|
|
27
|
|
|
|
(43)
|
|
|
|
3
|
|
|
|
8
|
|
Settlement
|
|
|
-
|
|
|
|
(46)
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Recognition of termination benefits
|
|
|
14
|
|
|
|
1
|
|
|
|
-
|
|
|
|
68
|
|
|
|
-
|
|
|
|
-
|
|
Foreign currency exchange rate change
|
|
|
-
|
|
|
|
(358)
|
|
|
|
-
|
|
|
|
(348)
|
|
|
|
1
|
|
|
|
(4)
|
|
|
|
Benefit obligation at December 31*
|
|
$
|
3,416
|
|
|
|
3,445
|
|
|
|
3,772
|
|
|
|
3,321
|
|
|
|
286
|
|
|
|
352
|
|
|
|
*Accumulated benefit obligation portion of above at December 31:
|
|
$
|
3,246
|
|
|
|
3,067
|
|
|
|
3,573
|
|
|
|
2,953
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Fair Value of Plan Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at January 1
|
|
$
|
2,606
|
|
|
|
3,063
|
|
|
|
3,266
|
|
|
|
3,278
|
|
|
|
-
|
|
|
|
-
|
|
Actual return on plan assets
|
|
|
133
|
|
|
|
397
|
|
|
|
(4)
|
|
|
|
96
|
|
|
|
-
|
|
|
|
-
|
|
Company contributions
|
|
|
214
|
|
|
|
125
|
|
|
|
73
|
|
|
|
120
|
|
|
|
44
|
|
|
|
42
|
|
Plan participant contributions
|
|
|
-
|
|
|
|
3
|
|
|
|
-
|
|
|
|
5
|
|
|
|
24
|
|
|
|
21
|
|
Benefits paid
|
|
|
(872)
|
|
|
|
(148)
|
|
|
|
(729)
|
|
|
|
(162)
|
|
|
|
(68)
|
|
|
|
(63)
|
|
Foreign currency exchange rate change
|
|
|
-
|
|
|
|
(372)
|
|
|
|
-
|
|
|
|
(274)
|
|
|
|
-
|
|
|
|
-
|
|
|
|
Fair value of plan assets at December 31
|
|
$
|
2,081
|
|
|
|
3,068
|
|
|
|
2,606
|
|
|
|
3,063
|
|
|
|
-
|
|
|
|
-
|
|
|
|
Funded Status
|
|
$
|
(1,335)
|
|
|
|
(377)
|
|
|
|
(1,166)
|
|
|
|
(258)
|
|
|
|
(286)
|
|
|
|
(352)
|
|
|
|
118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
Intl.
|
|
|
U.S.
|
|
|
Intl.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts Recognized in the Consolidated Balance Sheet at December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent assets
|
|
$
|
-
|
|
|
|
164
|
|
|
|
-
|
|
|
|
175
|
|
|
|
-
|
|
|
|
-
|
|
Current liabilities
|
|
|
(101)
|
|
|
|
(7)
|
|
|
|
(99)
|
|
|
|
(34)
|
|
|
|
(44)
|
|
|
|
(45)
|
|
Noncurrent liabilities
|
|
|
(1,234)
|
|
|
|
(534)
|
|
|
|
(1,067)
|
|
|
|
(399)
|
|
|
|
(242)
|
|
|
|
(307)
|
|
|
|
Total recognized
|
|
$
|
(1,335)
|
|
|
|
(377)
|
|
|
|
(1,166)
|
|
|
|
(258)
|
|
|
|
(286)
|
|
|
|
(352)
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average Assumptions Used to Determine Benefit Obligations at December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
3.95%
|
|
|
|
3.00
|
|
|
|
4.50
|
|
|
|
3.95
|
|
|
|
3.60
|
|
|
|
3.90
|
|
Rate of compensation increase
|
|
|
4.00
|
|
|
|
3.85
|
|
|
|
4.00
|
|
|
|
4.05
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended
December 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
3.90%
|
|
|
|
3.95
|
|
|
|
4.00
|
|
|
|
3.55
|
|
|
|
3.75
|
|
|
|
4.05
|
|
Expected return on plan assets
|
|
|
7.00
|
|
|
|
5.45
|
|
|
|
7.00
|
|
|
|
5.40
|
|
|
|
-
|
|
|
|
-
|
|
Rate of compensation increase
|
|
|
4.00
|
|
|
|
4.05
|
|
|
|
4.75
|
|
|
|
4.35
|
|
|
|
-
|
|
|
|
-
|
|
|
|
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
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
Intl.
|
|
|
U.S.
|
|
|
Intl.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized net actuarial (gain) loss
|
|
$
|
748
|
|
|
|
479
|
|
|
|
773
|
|
|
|
273
|
|
|
|
(27)
|
|
|
|
(18)
|
|
Unrecognized prior service cost (credit)
|
|
|
4
|
|
|
|
(20)
|
|
|
|
9
|
|
|
|
(30)
|
|
|
|
(285)
|
|
|
|
(292)
|
|
|
|
119
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
Pension Benefits
|
|
|
Other Benefits
|
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
Intl.
|
|
|
U.S.
|
|
|
Intl.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sources of Change in Other Comprehensive Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) arising during the period
|
|
$
|
(263)
|
|
|
|
(232)
|
|
|
|
61
|
|
|
|
490
|
|
|
|
14
|
|
|
|
41
|
|
Amortization of (gain) loss included in net loss*
|
|
|
288
|
|
|
|
26
|
|
|
|
312
|
|
|
|
89
|
|
|
|
(5)
|
|
|
|
2
|
|
|
|
Net change during the period
|
|
$
|
25
|
|
|
|
(206)
|
|
|
|
373
|
|
|
|
579
|
|
|
|
9
|
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
Prior service credit (cost) arising during the period
|
|
$
|
-
|
|
|
|
(4)
|
|
|
|
-
|
|
|
|
(2)
|
|
|
|
27
|
|
|
|
303
|
|
Amortization of prior service cost (credit) included in net loss
|
|
|
5
|
|
|
|
(6)
|
|
|
|
7
|
|
|
|
(11)
|
|
|
|
(34)
|
|
|
|
(15)
|
|
|
|
Net change during the period
|
|
$
|
5
|
|
|
|
(10)
|
|
|
|
7
|
|
|
|
(13)
|
|
|
|
(7)
|
|
|
|
288
|
|
|
|
*Includes settlement losses recognized in 2016 and 2015.
During the year ended December 31, 2016, there was an amendment to the U.S. other postretirement benefit plan. The benefit obligation decreased by $27
million for changes in the plan made to post-65 retiree medical benefits related to updated cost sharing assumption changes for retirees. The $27 million decrease in the benefit obligation resulted in a corresponding increase in other comprehensive
income.
During the year ended December 31, 2015, there were amendments to the U.S. other postretirement benefit plan. The benefit obligation
decreased by $303 million for changes in the plan made to retiree medical benefits. The $303 million decrease consists of $149 million related to the discontinuation of all company premium cost-sharing contributions to the post-65 retiree medical
plan after December 31, 2025, $91 million related to updated cost sharing assumption changes for retirees, $49 million associated with excluding employees and retirees of Phillips 66 who were not enrolled in a ConocoPhillips retiree medical
plan as of July 1, 2015, and $14 million associated with new participants in the post-65 retiree medical plan after December 31, 2015, no longer being eligible for any company premium cost-sharing contributions. The $303 million
decrease in the benefit obligation resulted in a corresponding decrease in other comprehensive loss.
Included in accumulated other comprehensive income
(loss) at December 31, 2016, were the following before-tax amounts that are expected to be amortized into net periodic benefit cost during 2017:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
Pension
Benefits
|
|
|
Other
Benefits
|
|
|
|
U.S.
|
|
|
Intl.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized net actuarial (gain) loss
|
|
$
|
75
|
|
|
|
48
|
|
|
|
(3)
|
|
Unrecognized prior service cost (credit)
|
|
|
4
|
|
|
|
(5)
|
|
|
|
(36)
|
|
|
|
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 $5,498 million, $5,145 million, and $4,208 million, respectively, at December 31, 2016, and $5,720 million, $5,314 million, and $4,759 million, respectively,
at December 31, 2015.
120
For our unfunded nonqualified key employee supplemental pension plans, the projected benefit obligation and the
accumulated benefit obligation were $586 million and $496 million, respectively, at December 31, 2016, and were $639 million and $564 million, respectively, at December 31, 2015.
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
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
Intl.
|
|
|
U.S.
|
|
|
Intl.
|
|
|
U.S.
|
|
|
Intl.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of Net Periodic Benefit Cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
108
|
|
|
|
76
|
|
|
|
138
|
|
|
|
124
|
|
|
|
124
|
|
|
|
109
|
|
|
|
2
|
|
|
|
4
|
|
|
|
3
|
|
Interest cost
|
|
|
133
|
|
|
|
120
|
|
|
|
161
|
|
|
|
135
|
|
|
|
165
|
|
|
|
166
|
|
|
|
13
|
|
|
|
22
|
|
|
|
29
|
|
Expected return on plan assets
|
|
|
(149)
|
|
|
|
(147)
|
|
|
|
(201)
|
|
|
|
(164)
|
|
|
|
(213)
|
|
|
|
(181)
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Amortization of prior service cost (credit)
|
|
|
5
|
|
|
|
(6)
|
|
|
|
6
|
|
|
|
(7)
|
|
|
|
6
|
|
|
|
(8)
|
|
|
|
(34)
|
|
|
|
(17)
|
|
|
|
(4)
|
|
Recognized net actuarial loss (gain)
|
|
|
86
|
|
|
|
26
|
|
|
|
115
|
|
|
|
82
|
|
|
|
77
|
|
|
|
57
|
|
|
|
(2)
|
|
|
|
2
|
|
|
|
(3)
|
|
Settlements
|
|
|
202
|
|
|
|
-
|
|
|
|
197
|
|
|
|
7
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Curtailment (gain) loss
|
|
|
14
|
|
|
|
-
|
|
|
|
35
|
|
|
|
(4)
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
2
|
|
|
|
-
|
|
|
|
Net periodic benefit cost
|
|
$
|
399
|
|
|
|
69
|
|
|
|
451
|
|
|
|
173
|
|
|
|
159
|
|
|
|
143
|
|
|
|
(20)
|
|
|
|
13
|
|
|
|
25
|
|
|
|
We recognized pension settlement losses of $202 million in 2016 and $204 million in 2015 as lump-sum benefit payments from
certain U.S. and international 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 and 2015 restructuring programs, we concluded that actions taken during those years 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 curtailment losses of $15 million and $33 million during the years ended December 31, 2016 and 2015, respectively.
Also as part of the 2016 and 2015 restructuring programs in the U.S. 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 U.S. and $1 million in Europe, and $124 million during the year ended December 31, 2015, consisting of $46 million in the U.S. and $78 million in Europe. Approximately
62 percent of the 2015 Europe amount was recovered from joint venture partners.
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 6.50 percent in 2017 that declines to 5 percent by 2023. The measurement of the U.S. post-65 retiree medical accumulated postretirement benefit obligation assumes a health care cost trend rate of 4 percent in
2017 that increases to 5 percent by 2018. A one-percentage-point change in the assumed health care cost trend rate would be immaterial to ConocoPhillips.
121
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 57 percent equity securities, 37 percent debt securities and 6 percent
real estate. 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, 2016 and 2015.
|
|
|
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.
|
|
|
|
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, 2016, the participating interest in the annuity contract was valued at $121 million and consisted of $288 million in debt securities, less $167 million for the accumulated benefit
obligation covered by the contract. At December 31, 2015, the participating interest in the annuity contract was valued at $125 million and consisted of $305 million in debt securities, less $180 million for the accumulated benefit obligation
covered by the contract. The net change from 2015 to 2016 is due to a decrease in the fair value of the underlying investments of $17 million offset by a decrease in the present value of the contract obligation of $13 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.
|
122
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
$
|
632
|
|
|
|
-
|
|
|
|
14
|
|
|
|
646
|
|
|
|
|
|
|
|
628
|
|
|
|
-
|
|
|
|
-
|
|
|
|
628
|
|
International
|
|
|
342
|
|
|
|
-
|
|
|
|
-
|
|
|
|
342
|
|
|
|
|
|
|
|
428
|
|
|
|
-
|
|
|
|
-
|
|
|
|
428
|
|
Common/collective trusts
|
|
|
62
|
|
|
|
-
|
|
|
|
-
|
|
|
|
62
|
|
|
|
|
|
|
|
-
|
|
|
|
156
|
|
|
|
-
|
|
|
|
156
|
|
Mutual funds
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
268
|
|
|
|
139
|
|
|
|
-
|
|
|
|
407
|
|
Debt Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Government
|
|
|
-
|
|
|
|
38
|
|
|
|
-
|
|
|
|
38
|
|
|
|
|
|
|
|
470
|
|
|
|
-
|
|
|
|
-
|
|
|
|
470
|
|
Corporate
|
|
|
-
|
|
|
|
54
|
|
|
|
3
|
|
|
|
57
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Common/collective trusts
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
385
|
|
|
|
-
|
|
|
|
385
|
|
Mutual funds
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
137
|
|
|
|
-
|
|
|
|
-
|
|
|
|
137
|
|
Cash and cash equivalents
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
48
|
|
|
|
-
|
|
|
|
-
|
|
|
|
48
|
|
Derivatives
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
18
|
|
|
|
-
|
|
|
|
-
|
|
|
|
18
|
|
Real estate
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
111
|
|
|
|
111
|
|
|
|
Total in fair value hierarchy
|
|
$
|
1,036
|
|
|
|
92
|
|
|
|
17
|
|
|
|
1,145
|
|
|
|
|
|
|
|
1,997
|
|
|
|
680
|
|
|
|
111
|
|
|
|
2,788
|
|
|
|
|
|
|
|
|
|
|
|
Investments measured at net asset value*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common/collective trusts
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
410
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Debt Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
155
|
|
Agency and mortgage-backed securities
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
27
|
|
Common/collective trusts
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
312
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Cash and cash equivalents
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
36
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
11
|
|
Real estate
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
69
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
76
|
|
|
|
Total**
|
|
$
|
1,036
|
|
|
|
92
|
|
|
|
17
|
|
|
|
1,972
|
|
|
|
|
|
|
|
1,997
|
|
|
|
680
|
|
|
|
111
|
|
|
|
3,057
|
|
|
|
*In accordance with FASB ASC Topic 715, CompensationRetirement 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 $121 million and net payables related to security transactions of $1 million
.
123
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
$
|
777
|
|
|
|
3
|
|
|
|
2
|
|
|
|
782
|
|
|
|
|
|
|
|
609
|
|
|
|
-
|
|
|
|
-
|
|
|
|
609
|
|
International
|
|
|
485
|
|
|
|
-
|
|
|
|
-
|
|
|
|
485
|
|
|
|
|
|
|
|
450
|
|
|
|
-
|
|
|
|
-
|
|
|
|
450
|
|
Common/collective trusts
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
214
|
|
|
|
-
|
|
|
|
214
|
|
Mutual funds
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
234
|
|
|
|
106
|
|
|
|
-
|
|
|
|
340
|
|
Debt Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Government
|
|
|
85
|
|
|
|
56
|
|
|
|
-
|
|
|
|
141
|
|
|
|
|
|
|
|
493
|
|
|
|
-
|
|
|
|
-
|
|
|
|
493
|
|
Corporate
|
|
|
-
|
|
|
|
331
|
|
|
|
17
|
|
|
|
348
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Agency and mortgage-backed securities
|
|
|
-
|
|
|
|
80
|
|
|
|
-
|
|
|
|
80
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Common/collective trusts
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
406
|
|
|
|
-
|
|
|
|
406
|
|
Mutual funds
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
136
|
|
|
|
-
|
|
|
|
-
|
|
|
|
136
|
|
Cash and cash equivalents
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
46
|
|
|
|
-
|
|
|
|
-
|
|
|
|
46
|
|
Derivatives
|
|
|
-
|
|
|
|
(7
|
)
|
|
|
-
|
|
|
|
(7
|
)
|
|
|
|
|
|
|
(26
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(26
|
)
|
Real estate
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
104
|
|
|
|
104
|
|
|
|
Total in fair value hierarchy
|
|
$
|
1,347
|
|
|
|
463
|
|
|
|
19
|
|
|
|
1,829
|
|
|
|
|
|
|
|
1,942
|
|
|
|
726
|
|
|
|
104
|
|
|
|
2,772
|
|
|
|
|
|
|
|
|
|
|
|
Investments measured at net asset value*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common/collective trusts
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
569
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Debt Securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
172
|
|
Agency and mortgage-backed securities
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
36
|
|
Cash and cash equivalents
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
60
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
10
|
|
Real estate
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
63
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
65
|
|
|
|
Total**
|
|
$
|
1,347
|
|
|
|
463
|
|
|
|
19
|
|
|
|
2,521
|
|
|
|
|
|
|
|
1,942
|
|
|
|
726
|
|
|
|
104
|
|
|
|
3,055
|
|
|
|
*In accordance with FASB ASC Topic 715, CompensationRetirement 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 $125 million and net payables related to security transactions of $32 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 2017, we expect to contribute approximately $320 million to our domestic qualified and nonqualified pension and
postretirement benefit plans and $110 million to our international qualified and nonqualified pension and postretirement benefit plans.
124
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.
|
|
|
Intl.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
|
$ 352
|
|
|
|
116
|
|
|
|
|
|
|
|
42
|
|
2018
|
|
|
290
|
|
|
|
131
|
|
|
|
|
|
|
|
39
|
|
2019
|
|
|
287
|
|
|
|
124
|
|
|
|
|
|
|
|
36
|
|
2020
|
|
|
277
|
|
|
|
129
|
|
|
|
|
|
|
|
34
|
|
2021
|
|
|
292
|
|
|
|
137
|
|
|
|
|
|
|
|
30
|
|
20222026
|
|
|
1,374
|
|
|
|
729
|
|
|
|
|
|
|
|
109
|
|
|
|
Severance Accrual
As a
result of the current business environments impact on our operating and capital plans, a reduction in our overall employee workforce occurred during 2015 and 2016. Severance accruals of $129 million were recorded in 2016. The following table
summarizes our severance accrual activity for the year ended December 31, 2016:
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
Balance at December 31, 2015
|
|
$
|
156
|
|
Accruals
|
|
|
129
|
|
Benefit payments
|
|
|
(206)
|
|
Foreign currency translation adjustments
|
|
|
1
|
|
|
|
Balance at December 31, 2016
|
|
$
|
80
|
|
|
|
Of the remaining balance at December 31, 2016, $52 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 funds. In 2016, 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. Company contributions charged to expense for the CPSP and
predecessor plans were $58 million in 2016, $109 million in 2015, and $116 million in 2014.
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 $44 million in 2016, $55 million in 2015, and $66 million in 2014.
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.
125
Awards may be granted in the form of, but not limited to, stock options, restricted stock units and performance share units to employees and nonemployee directors who contribute to the
companys 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
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
Compensation cost
|
|
$
|
272
|
|
|
|
362
|
|
|
|
358
|
|
Tax benefit
|
|
|
92
|
|
|
|
123
|
|
|
|
125
|
|
|
|
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 market price 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.
The fair market values of the options granted over the past three years were measured on the date of grant using the
Black-Scholes-Merton option-pricing model. The weighted-average assumptions used were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
Assumptions used
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk-free interest rate
|
|
|
1.55
|
%
|
|
|
1.79
|
|
|
|
1.86
|
|
Dividend yield
|
|
|
4.00
|
%
|
|
|
4.00
|
|
|
|
4.00
|
|
Volatility factor
|
|
|
26.80
|
%
|
|
|
23.32
|
|
|
|
25.31
|
|
Expected life (years)
|
|
|
6.37
|
|
|
|
5.79
|
|
|
|
6.12
|
|
|
|
There were no ranges in the assumptions used to determine the fair market values of our options granted over the past three
years.
Due to the separation of our Downstream businesses in 2012, expected volatility for grants of options in 2014 was based on a three-year average
historical stock price volatility of a group of peer companies. We believe our historical volatility for periods prior to the separation of our Downstream businesses is no longer relevant in estimating expected volatility. For 2015 and 2016,
expected volatility was based on the weighted average blend of the companys 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.
126
The following summarizes our stock option activity for the year ended December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
|
|
|
Weighted-
Average
Exercise Price
|
|
|
Weighted-
Average
|
|
|
Millions of Dollars
|
|
|
|
|
|
Grant Date
Fair Value
|
|
|
Aggregate
Intrinsic Value
|
|
|
|
|
|
|
Outstanding at December 31, 2015
|
|
|
20,184,810
|
|
|
$
|
55.88
|
|
|
|
|
|
|
$
|
42
|
|
Granted
|
|
|
4,434,400
|
|
|
|
33.13
|
|
|
$
|
5.39
|
|
|
|
|
|
Exercised
|
|
|
(62,536)
|
|
|
|
48.80
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(272,646)
|
|
|
|
34.51
|
|
|
|
|
|
|
|
|
|
Expired or cancelled
|
|
|
(571,916)
|
|
|
|
45.46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2016
|
|
|
23,712,112
|
|
|
$
|
52.14
|
|
|
|
|
|
|
$
|
128
|
|
|
|
|
|
|
|
Vested at December 31, 2016
|
|
|
20,192,822
|
|
|
$
|
52.85
|
|
|
|
|
|
|
$
|
93
|
|
|
|
|
|
|
|
Exercisable at December 31, 2016
|
|
|
15,932,144
|
|
|
$
|
53.56
|
|
|
|
|
|
|
$
|
55
|
|
|
|
|
|
|
|
The weighted-average remaining contractual term of outstanding options, vested options and exercisable options at
December 31, 2016, was 5.74 years, 5.25 years and 4.40 years, respectively. The weighted-average grant date fair value of stock option awards granted during 2015 and 2014 was $9.54 and $10.17, respectively. The aggregate intrinsic value of
options exercised during 2015 and 2014 was $10 million and $89 million, respectively.
During 2016, we received $3 million in cash and realized a tax
benefit of $4 million from the exercise of options. At December 31, 2016, the remaining unrecognized compensation expense from unvested options was $8 million, which will be recognized over a weighted-average period of 0.91 years, the longest
period being 2.13 years.
Stock Unit Program
Generally, restricted stock units are granted annually under the provisions of the Plan.
Restricted stock units granted prior to 2013 generally vest ratably in three equal annual installments beginning on the third anniversary of the grant date. Beginning in 2013, restricted stock units granted will vest in an aggregate installment on
the third anniversary of the grant date. In addition, beginning in 2012, 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. Upon vesting, the 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.
127
The following summarizes our stock unit activity for the year ended December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Units
|
|
|
Weighted-Average
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant Date Fair Value
|
|
|
Total Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2015
|
|
|
9,178,165
|
|
|
|
$ 59.80
|
|
|
|
|
|
Granted
|
|
|
4,613,469
|
|
|
|
32.15
|
|
|
|
|
|
Forfeited
|
|
|
(169,018
|
)
|
|
|
30.46
|
|
|
|
|
|
Issued
|
|
|
(5,115,112
|
)
|
|
|
|
|
|
|
$ 191
|
|
|
|
|
|
|
|
Outstanding at December 31, 2016
|
|
|
8,507,504
|
|
|
|
$ 48.65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Not Vested at December 31, 2016
|
|
|
5,990,350
|
|
|
|
$ 48.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2016, the remaining unrecognized compensation cost from the unvested units was $105 million, which
will be recognized over a weighted-average period of 1.59 years, the longest period being 2.82 years. The weighted-average grant date fair value of stock unit awards granted during 2015 and 2014 was $65.40 and $62.72, respectively. The total fair
value of stock units issued during 2015 and 2014 was $316 million and $256 million, respectively.
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 employees 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.
128
The following summarizes our stock-settled Performance Share Program activity for the year ended
December 31, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Units
|
|
|
|
Weighted-Average
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
Grant Date Fair Value
|
|
|
|
Total Fair Value
|
|
|
|
|
|
Outstanding at December 31, 2015
|
|
|
4,270,222
|
|
|
|
$ 51.95
|
|
|
|
|
|
Granted
|
|
|
48,065
|
|
|
|
33.13
|
|
|
|
|
|
Issued
|
|
|
(428,763
|
)
|
|
|
|
|
|
|
$ 17
|
|
|
|
|
|
|
|
Outstanding at December 31, 2016
|
|
|
3,889,524
|
|
|
|
$ 51.93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Not Vested at December 31, 2016
|
|
|
606,085
|
|
|
|
$ 53.34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2016, the remaining unrecognized compensation cost from unvested stock-settled performance share awards
was $3 million, which includes $1 million related to unvested stock-settled performance share awards tied to Phillips 66 stock held by ConocoPhillips employees, which will be recognized over a weighted-average period of 1.82 years, the longest
period being 3.98 years. The weighted-average grant date fair value of stock-settled PSUs granted during 2015 and 2014 was $69.25 and $65.46, respectively. The total fair value of stock-settled PSUs issued during 2015 and 2014 was $25 million and
$18 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 on 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. 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.
129
The following summarizes our cash-settled Performance Share Program activity for the year ended December 31,
2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Units
|
|
|
Grant Date Fair Value
|
|
|
Total Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2015
|
|
|
1,459,236
|
|
|
|
$ 46.54
|
|
|
|
|
|
Granted
|
|
|
684,386
|
|
|
|
33.13
|
|
|
|
|
|
Settled
|
|
|
(868,860
|
)
|
|
|
|
|
|
|
$ 31
|
|
|
|
|
|
|
|
Outstanding at December 31, 2016
|
|
|
1,274,762
|
|
|
|
$ 50.39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Not Vested at December 31, 2016
|
|
|
584,789
|
|
|
|
$ 50.39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2016, the remaining unrecognized compensation cost from unvested cash-settled performance share awards
was $7 million, which will be recognized over a weighted-average period of 1.75 years, the longest period being 3.13 years. The weighted-average grant date fair value of cash-settled PSUs granted during 2015 and 2014 was $46.54 and $69.23,
respectively. The total fair value of cash-settled performance share awards settled during 2015 and 2014 was $6 million and zero, 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 will terminate at the end of the three-year performance period and will be replaced with approved PSU awards. For the open performance period beginning in 2013,
the initial target PSU awards will terminate at the end of the three-year performance period and will be settled after the performance period has 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
to replace awards held by employees of companies we acquired or issued as part of a 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, 2016:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Units
|
|
|
Grant Date Fair Value
|
|
|
Total Fair Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2015
|
|
|
1,272,136
|
|
|
|
$ 33.25
|
|
|
|
|
|
Granted
|
|
|
99,300
|
|
|
|
40.36
|
|
|
|
|
|
Cancelled
|
|
|
(15,964
|
)
|
|
|
20.69
|
|
|
|
|
|
Issued
|
|
|
(37,508
|
)
|
|
|
|
|
|
|
$ 2
|
|
|
|
|
|
|
|
Outstanding at December 31, 2016
|
|
|
1,317,964
|
|
|
|
$ 33.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Not Vested at December 31, 2016
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2016, 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 2015 and 2014 was $58.66 and $71.23, respectively. The total fair value of awards issued during 2015 and 2014 was $3 million and $3
million, respectively.
130
Note 19Income Taxes
Income taxes charged to income (loss) from continuing operations were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
$
|
(9
|
)
|
|
|
(718
|
)
|
|
|
188
|
|
Deferred
|
|
|
(1,634
|
)
|
|
|
(1,443
|
)
|
|
|
365
|
|
Foreign
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
393
|
|
|
|
745
|
|
|
|
2,846
|
|
Deferred
|
|
|
(519
|
)
|
|
|
(1,315
|
)
|
|
|
252
|
|
State and local
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
(135
|
)
|
|
|
8
|
|
|
|
46
|
|
Deferred
|
|
|
(67
|
)
|
|
|
(145
|
)
|
|
|
(114
|
)
|
|
|
|
|
$
|
(1,971
|
)
|
|
|
(2,868
|
)
|
|
|
3,583
|
|
|
|
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
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Deferred Tax Liabilities
|
|
|
|
|
|
|
|
|
PP&E and intangibles
|
|
$
|
15,099
|
|
|
|
16,378
|
|
Investment in joint ventures
|
|
|
933
|
|
|
|
866
|
|
Inventory
|
|
|
36
|
|
|
|
25
|
|
Deferred state income tax
|
|
|
203
|
|
|
|
128
|
|
Partnership income deferral
|
|
|
-
|
|
|
|
44
|
|
Other
|
|
|
486
|
|
|
|
453
|
|
|
|
Total deferred tax liabilities
|
|
|
16,757
|
|
|
|
17,894
|
|
|
|
|
|
|
Deferred Tax Assets
|
|
|
|
|
|
|
|
|
Benefit plan accruals
|
|
|
1,280
|
|
|
|
1,160
|
|
Asset retirement obligations and accrued environmental costs
|
|
|
3,514
|
|
|
|
4,426
|
|
Other financial accruals and deferrals
|
|
|
317
|
|
|
|
616
|
|
Loss and credit carryforwards
|
|
|
3,522
|
|
|
|
1,579
|
|
Other
|
|
|
250
|
|
|
|
134
|
|
|
|
Total deferred tax assets
|
|
|
8,883
|
|
|
|
7,915
|
|
Less: valuation allowance
|
|
|
(675
|
)
|
|
|
(734
|
)
|
|
|
Net deferred tax assets
|
|
|
8,208
|
|
|
|
7,181
|
|
|
|
Net deferred tax liabilities
|
|
$
|
8,549
|
|
|
|
10,713
|
|
|
|
At December 31, 2016, noncurrent assets and liabilities include deferred taxes of $400 million and
$8,949 million, respectively. At December 31, 2015, noncurrent assets and liabilities include deferred taxes of $286 million and $10,999 million, respectively.
131
At December 31, 2016, the components of our loss and credit carryforwards before and after consideration of
the applicable valuation allowances are:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Deferred
Tax Asset
|
|
|
Net Deferred
Tax Asset After
Valuation Allowance
|
|
|
Expiration of
Net Deferred
Tax Asset
|
|
|
|
|
|
|
|
|
|
|
U.S. federal net operating loss
|
|
$
|
1,648
|
|
|
$
|
1,648
|
|
|
|
2036
|
|
U.S. foreign tax credits
|
|
|
480
|
|
|
|
296
|
|
|
|
2025-2026
|
|
U.S. general business credits
|
|
|
96
|
|
|
|
96
|
|
|
|
2031
|
|
State net operating losses and tax credits
|
|
|
502
|
|
|
|
49
|
|
|
|
Post 2024
|
|
Foreign net operating losses and tax credits
|
|
|
796
|
|
|
|
783
|
|
|
|
Post 2025
|
|
|
|
|
|
$
|
3,522
|
|
|
$
|
2,872
|
|
|
|
|
|
|
|
|
|
|
|
Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than not, be
realized. During 2016, valuation allowances decreased a total of $59 million. This decrease primarily relates to the expected realization of certain deferred tax assets. Based on our historical taxable income, expectations for the future, and
available tax-planning strategies, management expects remaining net deferred tax assets will primarily be realized as offsets to reversing deferred tax liabilities.
At December 31, 2016, unremitted income considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures
totaled approximately $3,720 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. Due to the nature of our structures within the jurisdictions
in which we operate, as well as the complex nature of the relevant tax laws, it is not practicable to estimate the amount of additional tax, if any, that might be payable on this income if distributed.
The following table shows a reconciliation of the beginning and ending unrecognized tax benefits for 2016, 2015 and 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1
|
|
$
|
459
|
|
|
|
442
|
|
|
|
655
|
|
Additions based on tax positions related to the current year
|
|
|
32
|
|
|
|
54
|
|
|
|
46
|
|
Additions for tax positions of prior years
|
|
|
19
|
|
|
|
4
|
|
|
|
7
|
|
Reductions for tax positions of prior years
|
|
|
(118
|
)
|
|
|
(37
|
)
|
|
|
(228
|
)
|
Settlements
|
|
|
(9
|
)
|
|
|
(4
|
)
|
|
|
(28
|
)
|
Lapse of statute
|
|
|
(2
|
)
|
|
|
-
|
|
|
|
(10
|
)
|
|
|
Balance at December 31
|
|
$
|
381
|
|
|
|
459
|
|
|
|
442
|
|
|
|
Included in the balance of unrecognized tax benefits for 2016, 2015 and 2014 were $359 million, $354 million and $348
million, respectively, which, if recognized, would impact our effective tax rate.
At December 31, 2016, 2015 and 2014, accrued liabilities for
interest and penalties totaled $54 million, $79 million and $65 million, respectively, net of accrued income taxes. Interest and penalties resulted in a benefit to earnings of $18 million in 2016, a reduction to earnings of $11
million in 2015, and a benefit to earnings of $43 million in 2014.
We and our subsidiaries 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 (2014), Canada (2009), United States (2010) and Norway (2015). 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.
132
As a consequence, 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) from continuing operations
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)
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes from continuing operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
(4,410
|
)
|
|
|
(4,150
|
)
|
|
|
2,310
|
|
|
|
79.7
|
%
|
|
|
57.3
|
|
|
|
24.6
|
|
Foreign
|
|
|
(1,120
|
)
|
|
|
(3,089
|
)
|
|
|
7,080
|
|
|
|
20.3
|
|
|
|
42.7
|
|
|
|
75.4
|
|
|
|
|
|
$
|
(5,530
|
)
|
|
|
(7,239
|
)
|
|
|
9,390
|
|
|
|
100.0
|
%
|
|
|
100.0
|
|
|
|
100.0
|
|
|
|
|
|
|
|
|
|
|
Federal statutory income tax
|
|
$
|
(1,936
|
)
|
|
|
(2,534
|
)
|
|
|
3,287
|
|
|
|
35.0
|
%
|
|
|
35.0
|
|
|
|
35.0
|
|
Non-U.S. effective tax rates
|
|
|
365
|
|
|
|
381
|
|
|
|
376
|
|
|
|
(6.6
|
)
|
|
|
(5.3
|
)
|
|
|
4.0
|
|
Foreign tax law change
|
|
|
(161
|
)
|
|
|
(426
|
)
|
|
|
-
|
|
|
|
2.9
|
|
|
|
5.9
|
|
|
|
-
|
|
U.S. fair value election
|
|
|
-
|
|
|
|
(185
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
2.6
|
|
|
|
-
|
|
Enhanced Oil Recovery Credit
|
|
|
(62
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
1.1
|
|
|
|
-
|
|
|
|
-
|
|
State income tax
|
|
|
(131
|
)
|
|
|
(89
|
)
|
|
|
(44
|
)
|
|
|
2.4
|
|
|
|
1.2
|
|
|
|
(0.5
|
)
|
Other
|
|
|
(46
|
)
|
|
|
(15
|
)
|
|
|
(36
|
)
|
|
|
0.8
|
|
|
|
0.2
|
|
|
|
(0.4
|
)
|
|
|
|
|
$
|
(1,971
|
)
|
|
|
(2,868
|
)
|
|
|
3,583
|
|
|
|
35.6
|
%
|
|
|
39.6
|
|
|
|
38.1
|
|
|
|
The decrease in the effective tax rate for 2016 was primarily due to higher income in high tax jurisdictions, lower losses in
low tax jurisdictions, and reduced net tax benefit from tax law changes.
The increase in the effective tax rate for 2015 was primarily due to the U.K.
tax law change and electing the fair market value method of apportioning interest expense for prior years, discussed below; partially offset by lower income in high tax jurisdictions and the Canadian tax law change, discussed below.
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, a $161 million net tax benefit for revaluing the U.K. deferred tax liability is reflected in the Income tax provision (benefit) line on our consolidated income statement.
In the United Kingdom, legislation was enacted on March 26, 2015, to decrease the overall U.K. upstream corporation tax rate from 62 percent to 50
percent effective January 1, 2015. As a result, a $555 million net tax benefit for revaluing the U.K. deferred tax liability is reflected in the Income tax provision (benefit) line on our consolidated income statement.
In Canada, legislation was enacted on June 29, 2015, to increase the overall Canadian corporation tax rate from 25 percent to 27 percent effective
July 1, 2015. As a result, a $129 million net tax expense for revaluing the Canadian deferred tax liability is reflected in the Income tax provision (benefit) line on our consolidated income statement.
In December 2015, we filed refund claims for prior years electing the fair market value method of apportioning interest in the United States. As a result, a
$185 million tax benefit was recorded in the fourth quarter of 2015.
133
Certain operating losses in jurisdictions outside of the U.S. only yield a tax benefit in the U.S. as a worthless
security deduction. For 2016, 2015 and 2014 the amount of the benefit was $60 million, $491 million and $122 million, respectively.
Note
20Accumulated Other Comprehensive Income
Accumulated other comprehensive income (loss) in the equity section of the balance sheet included:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
Defined
Benefit Plans
|
|
|
Foreign
Currency
Translation
|
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
|
$
|
(824)
|
|
|
|
2,826
|
|
|
|
2,002
|
|
Other comprehensive loss
|
|
|
(437)
|
|
|
|
(3,467)
|
|
|
|
(3,904)
|
|
|
|
December 31, 2014
|
|
|
(1,261)
|
|
|
|
(641)
|
|
|
|
(1,902)
|
|
Other comprehensive income (loss)
|
|
|
818
|
|
|
|
(5,163)
|
|
|
|
(4,345)
|
|
|
|
December 31, 2015
|
|
|
(443)
|
|
|
|
(5,804)
|
|
|
|
(6,247)
|
|
Other comprehensive income (loss)
|
|
|
(104)
|
|
|
|
158
|
|
|
|
54
|
|
|
|
December 31, 2016
|
|
$
|
(547)
|
|
|
|
(5,646)
|
|
|
|
(6,193)
|
|
|
|
There were no items within accumulated other comprehensive income (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
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
Defined Benefit Plans
|
|
$
|
179
|
|
|
|
251
|
|
|
|
Above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of:
|
|
$
|
95
|
|
|
|
133
|
|
See Note 18Employee Benefit Plans, for additional information.
134
Note 21Cash Flow Information
Amounts included in continuing operations for the years ended December 31 were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
Noncash Investing and Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in PP&E related to an increase (decrease) in asset retirement
obligations*
|
|
$
|
(1,017
|
)
|
|
|
402
|
|
|
|
1,611
|
|
|
|
|
|
|
|
Cash Payments (Receipts)
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
1,151
|
|
|
|
920
|
|
|
|
669
|
|
Income taxes**
|
|
|
(318
|
)
|
|
|
523
|
|
|
|
4,203
|
|
|
|
|
|
|
|
Net Sales (Purchases) of Short-Term Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments purchased
|
|
$
|
(1,753
|
)
|
|
|
-
|
|
|
|
(876
|
)
|
Short-term investments sold
|
|
|
1,702
|
|
|
|
-
|
|
|
|
1,129
|
|
|
|
|
|
$
|
(51
|
)
|
|
|
-
|
|
|
|
253
|
|
|
|
*Includes $68 million in 2014, primarily related to the impact of U.K. tax law changes on the deductibility
of decommissioning costs.
**Net of $585 million and $642 million in 2016 and 2015, respectively, related to refunds received from the Internal
Revenue Service.
135
Note 22Other Financial Information
Amounts included in continuing operations for the years ended December 31 were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
Interest and Debt Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
Incurred
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt
|
|
$
|
1,279
|
|
|
|
1,130
|
|
|
|
1,063
|
|
Other
|
|
|
123
|
|
|
|
84
|
|
|
|
73
|
|
|
|
|
|
|
1,402
|
|
|
|
1,214
|
|
|
|
1,136
|
|
Capitalized
|
|
|
(157)
|
|
|
|
(294)
|
|
|
|
(488)
|
|
|
|
Expensed
|
|
$
|
1,245
|
|
|
|
920
|
|
|
|
648
|
|
|
|
|
|
|
|
Other Income
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
$
|
57
|
|
|
|
45
|
|
|
|
83
|
|
Other, net
|
|
|
198
|
|
|
|
80
|
|
|
|
283
|
|
|
|
|
|
$
|
255
|
|
|
|
125
|
|
|
|
366
|
|
|
|
|
|
|
|
Research and Development Expenditures
expensed
|
|
$
|
116
|
|
|
|
222
|
|
|
|
263
|
|
|
|
|
|
|
|
Shipping and Handling Costs*
|
|
$
|
1,139
|
|
|
|
1,181
|
|
|
|
1,360
|
|
|
|
*Amounts included in production and operating expenses.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Currency Transaction (Gains) Losses
after-tax
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Lower 48
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Canada
|
|
|
1
|
|
|
|
-
|
|
|
|
(4)
|
|
Europe and North Africa
|
|
|
(7)
|
|
|
|
(22)
|
|
|
|
(56)
|
|
Asia Pacific and Middle East
|
|
|
(9)
|
|
|
|
(78)
|
|
|
|
-
|
|
Other International
|
|
|
7
|
|
|
|
(9)
|
|
|
|
-
|
|
Corporate and Other
|
|
|
(18)
|
|
|
|
45
|
|
|
|
16
|
|
|
|
|
|
$
|
(26)
|
|
|
|
(64)
|
|
|
|
(44)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
Properties, Plants and Equipment
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
119,970
|
|
|
|
122,796
|
|
Unproved properties
|
|
|
5,150
|
|
|
|
7,410
|
|
Other
|
|
|
6,286
|
|
|
|
6,653
|
|
|
|
Gross properties, plants and equipment
|
|
|
131,406
|
|
|
|
136,859
|
|
Less: Accumulated depreciation, depletion and amortization
|
|
|
(73,075)
|
|
|
|
(70,413)
|
|
|
|
Net properties, plants and equipment
|
|
$
|
58,331
|
|
|
|
66,446
|
|
|
|
136
Note 23Related 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
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
Operating revenues and other income
|
|
$
|
133
|
|
|
|
118
|
|
|
|
119
|
|
Purchases
|
|
|
101
|
|
|
|
97
|
|
|
|
190
|
|
Operating expenses and selling, general and administrative expenses
|
|
|
63
|
|
|
|
62
|
|
|
|
70
|
|
Net interest (income) expense*
|
|
|
(12
|
)
|
|
|
(9
|
)
|
|
|
(44
|
)
|
|
|
*We paid interest to, or received interest from, various affiliates. See Note 7Investments, Loans and Long-Term
Receivables, for additional information on loans to affiliated companies.
The table above includes transactions with Freeport LNG through the date of
the termination agreement and excludes the termination fee. See Note 7Investments, Loans and Long-Term Receivables, for additional information.
Note 24Segment 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.
After agreeing to sell our Nigeria business in 2012, we completed the sale in 2014. Results for these operations have been reported as discontinued operations
in the applicable periods presented. For additional information, see Note 3Discontinued Operations.
Corporate and Other represents costs not
directly associated with an operating segment, such as most interest expense, corporate overhead and certain technology activities, including licensing revenues. Corporate assets include all cash and cash equivalents.
We evaluate performance and allocate resources based on net income (loss) attributable to ConocoPhillips. Segment accounting policies are the same as those in
Note 1Accounting Policies. Intersegment sales are at prices that approximate market.
137
Analysis of Results by Operating Segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
|
Sales and Other Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
$
|
3,681
|
|
|
|
4,351
|
|
|
|
8,382
|
|
|
|
Lower 48
|
|
|
10,719
|
|
|
|
11,976
|
|
|
|
21,721
|
|
Intersegment eliminations
|
|
|
(17
|
)
|
|
|
(63
|
)
|
|
|
(107)
|
|
|
|
Lower 48
|
|
|
10,702
|
|
|
|
11,913
|
|
|
|
21,614
|
|
|
|
Canada
|
|
|
2,192
|
|
|
|
2,454
|
|
|
|
5,162
|
|
Intersegment eliminations
|
|
|
(218
|
)
|
|
|
(318
|
)
|
|
|
(753)
|
|
|
|
Canada
|
|
|
1,974
|
|
|
|
2,136
|
|
|
|
4,409
|
|
|
|
Europe and North Africa
|
|
|
3,462
|
|
|
|
6,110
|
|
|
|
10,665
|
|
Intersegment eliminations
|
|
|
-
|
|
|
|
(4
|
)
|
|
|
(49)
|
|
|
|
Europe and North Africa
|
|
|
3,462
|
|
|
|
6,106
|
|
|
|
10,616
|
|
|
|
Asia Pacific and Middle East
|
|
|
3,705
|
|
|
|
4,746
|
|
|
|
7,425
|
|
Intersegment eliminations
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
(1)
|
|
|
|
Asia Pacific and Middle East
|
|
|
3,705
|
|
|
|
4,745
|
|
|
|
7,424
|
|
|
|
Other International
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
Corporate and Other
|
|
|
169
|
|
|
|
312
|
|
|
|
79
|
|
|
|
Consolidated sales and other operating revenues
|
|
$
|
23,693
|
|
|
|
29,564
|
|
|
|
52,524
|
|
|
|
|
|
|
|
Depreciation, Depletion, Amortization and Impairments
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
$
|
868
|
|
|
|
690
|
|
|
|
584
|
|
Lower 48
|
|
|
4,358
|
|
|
|
4,227
|
|
|
|
3,911
|
|
Canada
|
|
|
975
|
|
|
|
788
|
|
|
|
962
|
|
Europe and North Africa
|
|
|
1,253
|
|
|
|
2,565
|
|
|
|
2,345
|
|
Asia Pacific and Middle East
|
|
|
1,606
|
|
|
|
2,981
|
|
|
|
1,275
|
|
Other International
|
|
|
1
|
|
|
|
-
|
|
|
|
1
|
|
Corporate and Other
|
|
|
140
|
|
|
|
107
|
|
|
|
107
|
|
|
|
Consolidated depreciation, depletion, amortization and impairments
|
|
$
|
9,201
|
|
|
|
11,358
|
|
|
|
9,185
|
|
|
|
138
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
|
Equity in Earnings of Affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
$
|
9
|
|
|
|
4
|
|
|
|
9
|
|
Lower 48
|
|
|
(6
|
)
|
|
|
(5
|
)
|
|
|
1
|
|
Canada
|
|
|
89
|
|
|
|
78
|
|
|
|
1,385
|
|
Europe and North Africa
|
|
|
22
|
|
|
|
23
|
|
|
|
37
|
|
Asia Pacific and Middle East
|
|
|
(51
|
)
|
|
|
550
|
|
|
|
1,089
|
|
Other International
|
|
|
-
|
|
|
|
8
|
|
|
|
9
|
|
Corporate and Other
|
|
|
(11
|
)
|
|
|
(3
|
)
|
|
|
(1
|
)
|
|
|
Consolidated equity in earnings of affiliates
|
|
$
|
52
|
|
|
|
655
|
|
|
|
2,529
|
|
|
|
|
|
|
|
Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
$
|
(59
|
)
|
|
|
(71
|
)
|
|
|
1,081
|
|
Lower 48
|
|
|
(1,328
|
)
|
|
|
(1,119
|
)
|
|
|
(92
|
)
|
Canada
|
|
|
(383
|
)
|
|
|
(223
|
)
|
|
|
236
|
|
Europe and North Africa
|
|
|
(46
|
)
|
|
|
(854
|
)
|
|
|
1,590
|
|
Asia Pacific and Middle East
|
|
|
306
|
|
|
|
467
|
|
|
|
1,194
|
|
Other International
|
|
|
(40
|
)
|
|
|
(456
|
)
|
|
|
(102
|
)
|
Corporate and Other
|
|
|
(421
|
)
|
|
|
(612
|
)
|
|
|
(324
|
)
|
|
|
Consolidated income taxes
|
|
$
|
(1,971
|
)
|
|
|
(2,868
|
)
|
|
|
3,583
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to ConocoPhillips
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
$
|
319
|
|
|
|
4
|
|
|
|
2,041
|
|
Lower 48
|
|
|
(2,257
|
)
|
|
|
(1,932
|
)
|
|
|
(22
|
)
|
Canada
|
|
|
(935
|
)
|
|
|
(1,044
|
)
|
|
|
940
|
|
Europe and North Africa
|
|
|
394
|
|
|
|
409
|
|
|
|
814
|
|
Asia Pacific and Middle East
|
|
|
209
|
|
|
|
(463
|
)
|
|
|
2,939
|
|
Other International
|
|
|
(16
|
)
|
|
|
(593
|
)
|
|
|
(100
|
)
|
Corporate and Other
|
|
|
(1,329
|
)
|
|
|
(809
|
)
|
|
|
(874
|
)
|
Discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
1,131
|
|
|
|
Consolidated net income (loss) attributable to ConocoPhillips
|
|
$
|
(3,615
|
)
|
|
|
(4,428
|
)
|
|
|
6,869
|
|
|
|
|
|
|
|
Investments In and Advances To Affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
$
|
58
|
|
|
|
61
|
|
|
|
53
|
|
Lower 48
|
|
|
426
|
|
|
|
455
|
|
|
|
471
|
|
Canada
|
|
|
8,784
|
|
|
|
8,165
|
|
|
|
9,484
|
|
Europe and North Africa
|
|
|
62
|
|
|
|
70
|
|
|
|
126
|
|
Asia Pacific and Middle East
|
|
|
11,611
|
|
|
|
11,780
|
|
|
|
14,022
|
|
Other International
|
|
|
-
|
|
|
|
-
|
|
|
|
59
|
|
Corporate and Other
|
|
|
4
|
|
|
|
15
|
|
|
|
15
|
|
|
|
Consolidated investments in and advances to affiliates
|
|
$
|
20,945
|
|
|
|
20,546
|
|
|
|
24,230
|
|
|
|
139
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
|
Total Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
$
|
12,314
|
|
|
|
12,555
|
|
|
|
12,655
|
|
Lower 48
|
|
|
22,673
|
|
|
|
26,932
|
|
|
|
30,185
|
|
Canada
|
|
|
17,548
|
|
|
|
17,221
|
|
|
|
21,764
|
|
Europe and North Africa
|
|
|
11,727
|
|
|
|
13,703
|
|
|
|
16,970
|
|
Asia Pacific and Middle East
|
|
|
20,451
|
|
|
|
22,318
|
|
|
|
25,976
|
|
Other International
|
|
|
97
|
|
|
|
282
|
|
|
|
1,116
|
|
Corporate and Other
|
|
|
4,962
|
|
|
|
4,473
|
|
|
|
7,815
|
|
Discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
58
|
|
|
|
Consolidated total assets
|
|
$
|
89,772
|
|
|
|
97,484
|
|
|
|
116,539
|
|
|
|
|
|
|
|
Capital Expenditures and Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
$
|
883
|
|
|
|
1,352
|
|
|
|
1,564
|
|
Lower 48
|
|
|
1,262
|
|
|
|
3,765
|
|
|
|
6,054
|
|
Canada
|
|
|
698
|
|
|
|
1,255
|
|
|
|
2,340
|
|
Europe and North Africa
|
|
|
1,020
|
|
|
|
1,573
|
|
|
|
2,540
|
|
Asia Pacific and Middle East
|
|
|
838
|
|
|
|
1,812
|
|
|
|
3,877
|
|
Other International
|
|
|
104
|
|
|
|
173
|
|
|
|
520
|
|
Corporate and Other
|
|
|
64
|
|
|
|
120
|
|
|
|
190
|
|
|
|
Consolidated capital expenditures and investments
|
|
$
|
4,869
|
|
|
|
10,050
|
|
|
|
17,085
|
|
|
|
|
|
|
|
Interest Income and Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
|
|
$
|
47
|
|
|
|
36
|
|
|
|
40
|
|
Lower 48
|
|
|
-
|
|
|
|
-
|
|
|
|
35
|
|
Europe and North Africa
|
|
|
2
|
|
|
|
2
|
|
|
|
2
|
|
Asia Pacific and Middle East
|
|
|
8
|
|
|
|
6
|
|
|
|
6
|
|
Other International
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
Interest and debt expense
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate
|
|
$
|
1,245
|
|
|
|
920
|
|
|
|
648
|
|
|
|
|
|
|
|
Sales and Other Operating Revenues by Product
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
$
|
10,801
|
|
|
|
12,830
|
|
|
|
23,784
|
|
Natural gas
|
|
|
9,401
|
|
|
|
11,888
|
|
|
|
20,717
|
|
Natural gas liquids
|
|
|
837
|
|
|
|
952
|
|
|
|
2,245
|
|
Other*
|
|
|
2,654
|
|
|
|
3,894
|
|
|
|
5,778
|
|
|
|
Consolidated sales and other operating revenues by product
|
|
$
|
23,693
|
|
|
|
29,564
|
|
|
|
52,524
|
|
|
|
*Includes LNG and bitumen.
|
|
|
|
|
|
|
|
|
|
|
|
|
140
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Geographic Information
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
Sales and Other Operating Revenues
(1)
|
|
|
|
|
|
|
|
Long-Lived Assets
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
14,400
|
|
|
|
16,284
|
|
|
|
30,019
|
|
|
|
|
|
|
|
32,949
|
|
|
|
37,445
|
|
|
|
39,641
|
|
Australia
(3)
|
|
|
1,353
|
|
|
|
2,127
|
|
|
|
3,258
|
|
|
|
|
|
|
|
12,259
|
|
|
|
12,788
|
|
|
|
14,969
|
|
Canada
|
|
|
1,974
|
|
|
|
2,136
|
|
|
|
4,409
|
|
|
|
|
|
|
|
16,846
|
|
|
|
16,766
|
|
|
|
20,874
|
|
China
|
|
|
551
|
|
|
|
782
|
|
|
|
1,701
|
|
|
|
|
|
|
|
1,372
|
|
|
|
1,647
|
|
|
|
1,913
|
|
Indonesia
|
|
|
938
|
|
|
|
1,165
|
|
|
|
1,963
|
|
|
|
|
|
|
|
856
|
|
|
|
1,191
|
|
|
|
1,526
|
|
Malaysia
|
|
|
735
|
|
|
|
598
|
|
|
|
403
|
|
|
|
|
|
|
|
3,323
|
|
|
|
3,599
|
|
|
|
3,811
|
|
Norway
|
|
|
1,645
|
|
|
|
2,107
|
|
|
|
3,794
|
|
|
|
|
|
|
|
6,228
|
|
|
|
6,933
|
|
|
|
8,142
|
|
United Kingdom
|
|
|
1,816
|
|
|
|
4,005
|
|
|
|
6,594
|
|
|
|
|
|
|
|
3,209
|
|
|
|
4,154
|
|
|
|
5,327
|
|
Other foreign countries
|
|
|
281
|
|
|
|
360
|
|
|
|
383
|
|
|
|
|
|
|
|
2,234
|
|
|
|
2,469
|
|
|
|
3,471
|
|
|
|
Worldwide consolidated
|
|
$
|
23,693
|
|
|
|
29,564
|
|
|
|
52,524
|
|
|
|
|
|
|
|
79,276
|
|
|
|
86,992
|
|
|
|
99,674
|
|
|
|
(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.
Note 25New Accounting Standards
In May 2014, the
FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (ASU No. 2014-09), which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. This ASU
supersedes the revenue recognition requirements in FASB ASC Topic 605, Revenue Recognition, and most industry-specific guidance. This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model,
an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be
required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts.
In August 2015, the FASB
issued ASU No. 2015-14, Deferral of the Effective Date, which defers the effective date of ASU No. 2014-09. The ASU is now effective for interim and annual periods beginning after December 15, 2017. Early adoption is
permitted for interim and annual periods beginning after December 15, 2016. Entities may choose to adopt the standard using either a full retrospective approach or a modified retrospective approach.
ASU No. 2014-09 was amended in March 2016 by the provisions of ASU No. 2016-08, Principal versus Agent Considerations (Reporting Revenue Gross
versus Net), in April 2016 by the provisions of ASU No. 2016-10, Identifying Performance Obligations and Licensing, in May 2016 by the provisions of ASU No. 2016-12, Narrow-Scope Improvements and Practical
Expedients, and in December 2016 by the provisions of ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue From Contracts With Customers.
We will adopt the provisions of ASU No. 2014-09, as amended, with effect from January 1, 2018, and have elected not to early adopt the standard. We
intend to adopt the new standard using the modified retrospective approach which we will apply only to contracts within the scope of the standard that are not complete at the date of initial application. Under this approach, we will apply the
guidance retrospectively only to the most current period presented in the financial statements. Overall, the impact to our financial statements is expected to be immaterial.
141
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, 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. While we continue to evaluate
the ASU, we expect the adoption of the ASU to have a material impact on our consolidated financial statements and disclosures.
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.
142
Oil and Gas Operations
(Unaudited)
In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic 932, Extractive ActivitiesOil 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, 2016, approximately 7 percent of our total proved reserves were under PSCs, located in our Asia Pacific/Middle East geographic reporting area, and 23 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, Africa and Other Areas. Other Areas primarily consists of Russia, which we exited in 2015.
As part of our
asset disposition program, we sold our interest in the Nigeria business in July 2014. This business was considered held for sale since the fourth quarter of 2012 and has been reported as discontinued operations for the applicable periods presented.
Accordingly, the Results of Operations, Average Sales Prices and Net Production tables included within the supplemental oil and gas disclosures reflect the associated earnings and production as discontinued operations. See Note 3Discontinued
Operations, for additional information.
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 produciblefrom a given date forward, from known reservoirs, and under existing economic conditions, operating
methods, and government regulationsprior 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.
143
We have a companywide, comprehensive, SEC-compliant internal policy that governs the determination and reporting
of proved reserves. This policy is applied by the geologists and reservoir engineers in our business units around the world. As part of our internal control process, each business units reserves processes and controls are reviewed annually by
an internal team which is headed by the companys Manager of Reserves Compliance and Reporting. This team, composed of internal reservoir engineers, geologists, 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 2016, our processes and controls used to
assess over 90 percent of proved reserves as of December 31, 2016, 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. Managements
intent in retaining D&M to review its processes and controls was to provide objective third-party input on these processes and controls. D&Ms opinion was the general processes and controls employed by ConocoPhillips in estimating its
December 31, 2016, proved reserves for the properties reviewed are in accordance with the SEC reserves definitions. D&Ms 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 companys reserves estimates
is the Manager of Reserves Compliance and Reporting. This individual holds a masters 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
Managements Discussion and Analysis of Financial Condition and Results of Operations for additional discussion of the sensitivities surrounding these estimates.
144
Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
Crude Oil
|
|
December 31
|
|
|
Millions of Barrels
|
|
|
|
|
Alaska
|
|
|
|
Lower
48
|
|
|
|
Total
U.S.
|
|
|
|
Canada
|
|
|
|
Europe
|
|
|
|
Asia Pacific/
Middle East
|
|
|
|
Africa
|
|
|
|
Other
Areas
|
|
|
|
Total
|
|
Developed and Undeveloped
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
1,106
|
|
|
|
606
|
|
|
|
1,712
|
|
|
|
22
|
|
|
|
456
|
|
|
|
232
|
|
|
|
237
|
|
|
|
-
|
|
|
|
2,659
|
|
Revisions
|
|
|
(6
|
)
|
|
|
25
|
|
|
|
19
|
|
|
|
3
|
|
|
|
(1
|
)
|
|
|
5
|
|
|
|
-
|
|
|
|
-
|
|
|
|
26
|
|
Improved recovery
|
|
|
8
|
|
|
|
-
|
|
|
|
8
|
|
|
|
2
|
|
|
|
-
|
|
|
|
3
|
|
|
|
-
|
|
|
|
-
|
|
|
|
13
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
16
|
|
|
|
116
|
|
|
|
132
|
|
|
|
2
|
|
|
|
-
|
|
|
|
16
|
|
|
|
-
|
|
|
|
-
|
|
|
|
150
|
|
Production
|
|
|
(61
|
)
|
|
|
(71
|
)
|
|
|
(132
|
)
|
|
|
(5
|
)
|
|
|
(44
|
)
|
|
|
(29
|
)
|
|
|
(5
|
)
|
|
|
-
|
|
|
|
(215
|
)
|
Sales
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(28
|
)
|
|
|
-
|
|
|
|
(28
|
)
|
|
|
|
|
|
End of 2014
|
|
|
1,063
|
|
|
|
676
|
|
|
|
1,739
|
|
|
|
24
|
|
|
|
411
|
|
|
|
227
|
|
|
|
204
|
|
|
|
-
|
|
|
|
2,605
|
|
Revisions
|
|
|
(115
|
)
|
|
|
(69
|
)
|
|
|
(184
|
)
|
|
|
-
|
|
|
|
(21
|
)
|
|
|
(29
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(234
|
)
|
Improved recovery
|
|
|
4
|
|
|
|
4
|
|
|
|
8
|
|
|
|
1
|
|
|
|
-
|
|
|
|
31
|
|
|
|
-
|
|
|
|
-
|
|
|
|
40
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
20
|
|
|
|
57
|
|
|
|
77
|
|
|
|
1
|
|
|
|
-
|
|
|
|
7
|
|
|
|
-
|
|
|
|
-
|
|
|
|
85
|
|
Production
|
|
|
(57
|
)
|
|
|
(78
|
)
|
|
|
(135
|
)
|
|
|
(4
|
)
|
|
|
(44
|
)
|
|
|
(33
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(216
|
)
|
Sales
|
|
|
-
|
|
|
|
(2
|
)
|
|
|
(2
|
)
|
|
|
(8
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(10
|
)
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
86
|
|
|
|
-
|
|
|
|
4
|
|
|
|
90
|
|
Revisions
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
17
|
|
|
|
-
|
|
|
|
3
|
|
|
|
20
|
|
Improved recovery
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Production
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(5
|
)
|
|
|
-
|
|
|
|
(2
|
)
|
|
|
(7
|
)
|
Sales
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
End of 2014
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
98
|
|
|
|
-
|
|
|
|
5
|
|
|
|
103
|
|
Revisions
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Improved recovery
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Production
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(5
|
)
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
(6
|
)
|
Sales
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(4
|
)
|
|
|
(4
|
)
|
|
|
|
|
|
End of 2015
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
93
|
|
|
|
-
|
|
|
|
-
|
|
|
|
93
|
|
Revisions
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Improved recovery
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Production
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(5
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(5
|
)
|
Sales
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
End of 2016
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
88
|
|
|
|
-
|
|
|
|
-
|
|
|
|
88
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
1,106
|
|
|
|
606
|
|
|
|
1,712
|
|
|
|
22
|
|
|
|
456
|
|
|
|
318
|
|
|
|
237
|
|
|
|
4
|
|
|
|
2,749
|
|
End of 2014
|
|
|
1,063
|
|
|
|
676
|
|
|
|
1,739
|
|
|
|
24
|
|
|
|
411
|
|
|
|
325
|
|
|
|
204
|
|
|
|
5
|
|
|
|
2,708
|
|
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
|
|
|
|
|
|
|
145
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
Crude Oil
|
|
December 31
|
|
|
Millions of Barrels
|
|
|
|
|
Alaska
|
|
|
|
Lower
48
|
|
|
|
Total
U.S.
|
|
|
|
Canada
|
|
|
|
Europe
|
|
|
|
Asia Pacific/
Middle East
|
|
|
|
Africa
|
|
|
|
Other
Areas
|
|
|
|
Total
|
|
Developed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
1,003
|
|
|
|
268
|
|
|
|
1,271
|
|
|
|
22
|
|
|
|
247
|
|
|
|
126
|
|
|
|
230
|
|
|
|
-
|
|
|
|
1,896
|
|
End of 2014
|
|
|
950
|
|
|
|
313
|
|
|
|
1,263
|
|
|
|
23
|
|
|
|
237
|
|
|
|
142
|
|
|
|
199
|
|
|
|
-
|
|
|
|
1,864
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
86
|
|
|
|
-
|
|
|
|
4
|
|
|
|
90
|
|
End of 2014
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
98
|
|
|
|
-
|
|
|
|
5
|
|
|
|
103
|
|
End of 2015
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
93
|
|
|
|
-
|
|
|
|
-
|
|
|
|
93
|
|
End of 2016
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
88
|
|
|
|
-
|
|
|
|
-
|
|
|
|
88
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undeveloped
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
103
|
|
|
|
338
|
|
|
|
441
|
|
|
|
-
|
|
|
|
209
|
|
|
|
106
|
|
|
|
7
|
|
|
|
-
|
|
|
|
763
|
|
End of 2014
|
|
|
113
|
|
|
|
363
|
|
|
|
476
|
|
|
|
1
|
|
|
|
174
|
|
|
|
85
|
|
|
|
5
|
|
|
|
-
|
|
|
|
741
|
|
End of 2015
|
|
|
96
|
|
|
|
305
|
|
|
|
401
|
|
|
|
1
|
|
|
|
146
|
|
|
|
64
|
|
|
|
-
|
|
|
|
-
|
|
|
|
612
|
|
End of 2016
|
|
|
90
|
|
|
|
250
|
|
|
|
340
|
|
|
|
-
|
|
|
|
119
|
|
|
|
79
|
|
|
|
-
|
|
|
|
-
|
|
|
|
538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
End of 2014
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
End of 2015
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
End of 2016
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
Notable changes in proved crude oil reserves in the three years ended December 31, 2016, included:
|
|
|
Revisions
: In 2016, revisions in Lower 48 and Alaska were primarily due to lower prices. In 2015, revisions in Alaska, Lower 48 and Asia Pacific/Middle East were primarily due to lower prices.
|
|
|
|
Extensions and discoveries
: In 2016, extensions and discoveries in Alaska were primarily due to drilling success in the Western North Slope. In 2016 and 2014, extensions and discoveries in Lower 48 were
primarily due to continued drilling success in Eagle Ford and Bakken.
|
|
|
|
Sales
: In 2014, sales in Africa reflect the sale of the Nigeria business.
|
146
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
Natural Gas Liquids
|
|
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 2013
|
|
|
125
|
|
|
|
462
|
|
|
|
587
|
|
|
|
56
|
|
|
|
28
|
|
|
|
14
|
|
|
|
14
|
|
|
|
699
|
|
Revisions
|
|
|
-
|
|
|
|
(13
|
)
|
|
|
(13
|
)
|
|
|
15
|
|
|
|
(1
|
)
|
|
|
2
|
|
|
|
-
|
|
|
|
3
|
|
Improved recovery
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
-
|
|
|
|
26
|
|
|
|
26
|
|
|
|
3
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
29
|
|
Production
|
|
|
(5
|
)
|
|
|
(35
|
)
|
|
|
(40
|
)
|
|
|
(8
|
)
|
|
|
(3
|
)
|
|
|
(3
|
)
|
|
|
(1
|
)
|
|
|
(55
|
)
|
Sales
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(13
|
)
|
|
|
(14
|
)
|
|
|
|
|
|
End of 2014
|
|
|
120
|
|
|
|
440
|
|
|
|
560
|
|
|
|
65
|
|
|
|
24
|
|
|
|
13
|
|
|
|
-
|
|
|
|
662
|
|
Revisions
|
|
|
(1
|
)
|
|
|
(84
|
)
|
|
|
(85
|
)
|
|
|
(10
|
)
|
|
|
(1
|
)
|
|
|
(2
|
)
|
|
|
-
|
|
|
|
(98
|
)
|
Improved recovery
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
-
|
|
|
|
10
|
|
|
|
10
|
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
12
|
|
Production
|
|
|
(5
|
)
|
|
|
(36
|
)
|
|
|
(41
|
)
|
|
|
(9
|
)
|
|
|
(3
|
)
|
|
|
(3
|
)
|
|
|
-
|
|
|
|
(56
|
)
|
Sales
|
|
|
-
|
|
|
|
(9
|
)
|
|
|
(9
|
)
|
|
|
(3
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(12
|
)
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
45
|
|
|
|
-
|
|
|
|
45
|
|
Revisions
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
10
|
|
|
|
-
|
|
|
|
10
|
|
Improved recovery
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Production
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2
|
)
|
|
|
-
|
|
|
|
(2
|
)
|
Sales
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
End of 2014
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
53
|
|
|
|
-
|
|
|
|
53
|
|
Revisions
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Improved recovery
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Production
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(3
|
)
|
|
|
-
|
|
|
|
(3
|
)
|
Sales
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
End of 2015
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
50
|
|
|
|
-
|
|
|
|
50
|
|
Revisions
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Improved recovery
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Production
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(3
|
)
|
|
|
-
|
|
|
|
(3
|
)
|
Sales
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
End of 2016
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
47
|
|
|
|
-
|
|
|
|
47
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
125
|
|
|
|
462
|
|
|
|
587
|
|
|
|
56
|
|
|
|
28
|
|
|
|
59
|
|
|
|
14
|
|
|
|
744
|
|
End of 2014
|
|
|
120
|
|
|
|
440
|
|
|
|
560
|
|
|
|
65
|
|
|
|
24
|
|
|
|
66
|
|
|
|
-
|
|
|
|
715
|
|
End of 2015
|
|
|
114
|
|
|
|
321
|
|
|
|
435
|
|
|
|
45
|
|
|
|
20
|
|
|
|
58
|
|
|
|
-
|
|
|
|
558
|
|
End of 2016
|
|
|
107
|
|
|
|
278
|
|
|
|
385
|
|
|
|
48
|
|
|
|
19
|
|
|
|
52
|
|
|
|
-
|
|
|
|
504
|
|
|
|
|
|
|
147
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
Natural Gas Liquids
|
|
December 31
|
|
Millions of Barrels
|
|
|
|
|
Alaska
|
|
|
|
Lower
48
|
|
|
|
Total
U.S.
|
|
|
|
Canada
|
|
|
|
Europe
|
|
|
|
Asia Pacific/
Middle East
|
|
|
|
Africa
|
|
|
|
Total
|
|
Developed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
125
|
|
|
|
362
|
|
|
|
487
|
|
|
|
50
|
|
|
|
19
|
|
|
|
13
|
|
|
|
14
|
|
|
|
583
|
|
End of 2014
|
|
|
120
|
|
|
|
337
|
|
|
|
457
|
|
|
|
57
|
|
|
|
18
|
|
|
|
11
|
|
|
|
-
|
|
|
|
543
|
|
End of 2015
|
|
|
114
|
|
|
|
235
|
|
|
|
349
|
|
|
|
45
|
|
|
|
16
|
|
|
|
8
|
|
|
|
-
|
|
|
|
418
|
|
End of 2016
|
|
|
107
|
|
|
|
209
|
|
|
|
316
|
|
|
|
47
|
|
|
|
15
|
|
|
|
5
|
|
|
|
-
|
|
|
|
383
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
45
|
|
|
|
-
|
|
|
|
45
|
|
End of 2014
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
53
|
|
|
|
-
|
|
|
|
53
|
|
End of 2015
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
50
|
|
|
|
-
|
|
|
|
50
|
|
End of 2016
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
47
|
|
|
|
-
|
|
|
|
47
|
|
|
|
|
|
|
|
|
|
|
Undeveloped
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
-
|
|
|
|
100
|
|
|
|
100
|
|
|
|
6
|
|
|
|
9
|
|
|
|
1
|
|
|
|
-
|
|
|
|
116
|
|
End of 2014
|
|
|
-
|
|
|
|
103
|
|
|
|
103
|
|
|
|
8
|
|
|
|
6
|
|
|
|
2
|
|
|
|
-
|
|
|
|
119
|
|
End of 2015
|
|
|
-
|
|
|
|
86
|
|
|
|
86
|
|
|
|
-
|
|
|
|
4
|
|
|
|
-
|
|
|
|
-
|
|
|
|
90
|
|
End of 2016
|
|
|
-
|
|
|
|
69
|
|
|
|
69
|
|
|
|
1
|
|
|
|
4
|
|
|
|
-
|
|
|
|
-
|
|
|
|
74
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
End of 2014
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
End of 2015
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
End of 2016
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Notable changes in proved natural gas liquids reserves in the three years ended December 31, 2016, included:
|
|
|
Revisions
: In 2015, revisions in Lower 48 and Canada were primarily due to lower prices.
|
|
|
|
Extensions and discoveries
: In 2014, extensions and discoveries in Lower 48 were primarily due to continued drilling success in Eagle Ford and Bakken.
|
148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 2013
|
|
|
2,865
|
|
|
|
6,711
|
|
|
|
9,576
|
|
|
|
1,878
|
|
|
|
1,809
|
|
|
|
2,046
|
|
|
|
950
|
|
|
|
16,259
|
|
Revisions
|
|
|
(75
|
)
|
|
|
581
|
|
|
|
506
|
|
|
|
225
|
|
|
|
(54
|
)
|
|
|
115
|
|
|
|
-
|
|
|
|
792
|
|
Improved recovery
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3
|
|
|
|
-
|
|
|
|
3
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
7
|
|
|
|
256
|
|
|
|
263
|
|
|
|
85
|
|
|
|
-
|
|
|
|
3
|
|
|
|
-
|
|
|
|
351
|
|
Production
|
|
|
(78
|
)
|
|
|
(601
|
)
|
|
|
(679
|
)
|
|
|
(259
|
)
|
|
|
(182
|
)
|
|
|
(289
|
)
|
|
|
(34
|
)
|
|
|
(1,443)
|
|
Sales
|
|
|
-
|
|
|
|
(2
|
)
|
|
|
(2
|
)
|
|
|
(13
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(689
|
)
|
|
|
(704)
|
|
|
|
End of 2014
|
|
|
2,719
|
|
|
|
6,945
|
|
|
|
9,664
|
|
|
|
1,916
|
|
|
|
1,573
|
|
|
|
1,878
|
|
|
|
227
|
|
|
|
15,258
|
|
Revisions
|
|
|
(293
|
)
|
|
|
(884
|
)
|
|
|
(1,177
|
)
|
|
|
(111
|
)
|
|
|
(27
|
)
|
|
|
110
|
|
|
|
-
|
|
|
|
(1,205)
|
|
Improved recovery
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
8
|
|
|
|
-
|
|
|
|
9
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
4
|
|
|
|
103
|
|
|
|
107
|
|
|
|
44
|
|
|
|
-
|
|
|
|
2
|
|
|
|
-
|
|
|
|
153
|
|
Production
|
|
|
(83
|
)
|
|
|
(588
|
)
|
|
|
(671
|
)
|
|
|
(261
|
)
|
|
|
(187
|
)
|
|
|
(285
|
)
|
|
|
-
|
|
|
|
(1,404)
|
|
Sales
|
|
|
-
|
|
|
|
(405
|
)
|
|
|
(405
|
)
|
|
|
(482
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(887)
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4,129
|
|
|
|
-
|
|
|
|
4,129
|
|
Revisions
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
768
|
|
|
|
-
|
|
|
|
768
|
|
Improved recovery
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
531
|
|
|
|
-
|
|
|
|
531
|
|
Production
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(186
|
)
|
|
|
-
|
|
|
|
(186)
|
|
Sales
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
End of 2014
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5,242
|
|
|
|
-
|
|
|
|
5,242
|
|
Revisions
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2
|
)
|
|
|
-
|
|
|
|
(2)
|
|
Improved recovery
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
268
|
|
|
|
-
|
|
|
|
268
|
|
Production
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(239
|
)
|
|
|
-
|
|
|
|
(239)
|
|
Sales
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
Total company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
2,865
|
|
|
|
6,711
|
|
|
|
9,576
|
|
|
|
1,878
|
|
|
|
1,809
|
|
|
|
6,175
|
|
|
|
950
|
|
|
|
20,388
|
|
End of 2014
|
|
|
2,719
|
|
|
|
6,945
|
|
|
|
9,664
|
|
|
|
1,916
|
|
|
|
1,573
|
|
|
|
7,120
|
|
|
|
227
|
|
|
|
20,500
|
|
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
|
|
|
|
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 2013
|
|
|
2,815
|
|
|
|
5,822
|
|
|
|
8,637
|
|
|
|
1,786
|
|
|
|
1,276
|
|
|
|
1,593
|
|
|
|
881
|
|
|
|
14,173
|
|
End of 2014
|
|
|
2,663
|
|
|
|
5,922
|
|
|
|
8,585
|
|
|
|
1,801
|
|
|
|
1,182
|
|
|
|
1,553
|
|
|
|
226
|
|
|
|
13,347
|
|
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
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,606
|
|
|
|
-
|
|
|
|
2,606
|
|
End of 2014
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3,954
|
|
|
|
-
|
|
|
|
3,954
|
|
End of 2015
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4,482
|
|
|
|
-
|
|
|
|
4,482
|
|
End of 2016
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4,110
|
|
|
|
-
|
|
|
|
4,110
|
|
|
|
|
|
|
|
|
|
|
Undeveloped
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
50
|
|
|
|
889
|
|
|
|
939
|
|
|
|
92
|
|
|
|
533
|
|
|
|
453
|
|
|
|
69
|
|
|
|
2,086
|
|
End of 2014
|
|
|
56
|
|
|
|
1,023
|
|
|
|
1,079
|
|
|
|
115
|
|
|
|
391
|
|
|
|
325
|
|
|
|
1
|
|
|
|
1,911
|
|
End of 2015
|
|
|
34
|
|
|
|
713
|
|
|
|
747
|
|
|
|
6
|
|
|
|
271
|
|
|
|
292
|
|
|
|
-
|
|
|
|
1,316
|
|
End of 2016
|
|
|
8
|
|
|
|
515
|
|
|
|
523
|
|
|
|
6
|
|
|
|
240
|
|
|
|
338
|
|
|
|
-
|
|
|
|
1,107
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,523
|
|
|
|
-
|
|
|
|
1,523
|
|
End of 2014
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,288
|
|
|
|
-
|
|
|
|
1,288
|
|
End of 2015
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
787
|
|
|
|
-
|
|
|
|
787
|
|
End of 2016
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
271
|
|
|
|
-
|
|
|
|
271
|
|
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, 2016, included:
|
|
|
Revisions
: In 2016, revisions in our equity affiliates in Asia Pacific/Middle East were primarily due to lower prices. In 2015, revisions in Lower 48, Alaska and Canada were primarily due to lower prices,
partially offset by positive revisions in Asia Pacific/Middle East from Indonesia. In 2014, revisions were primarily due to higher prices, increased development activity and strong well performance in Lower 48 and higher prices and improved well
performance in Canada and our consolidated operations in Asia Pacific/Middle East. This was partially offset by lower prices and higher costs in Alaska. For our equity affiliates in Asia Pacific/Middle East, 2014 revisions were primarily due to
strong field performance.
|
|
|
|
Extensions and discoveries
: In 2015 and 2014, for our equity affiliates in Asia Pacific/Middle East, extensions and discoveries were due to APLNGs ongoing development drilling onshore Australia. In
2014, extensions and discoveries in Lower 48 and Canada were primarily due to continued drilling success in Eagle Ford and Bakken and ongoing development activity in western Canada.
|
|
|
|
Sales
: In 2015, Lower 48 sales were due to the disposition of non-core assets in South Texas, East Texas and North Louisiana and sales of assets in British Columbia, Saskatchewan and Alberta impacted
Canada. In 2014, for our consolidated operations in Africa, sales were due to the disposition of the Nigeria business.
|
150
|
|
|
|
|
Years Ended
|
|
Bitumen
|
|
December 31
|
|
Millions of Barrels
|
|
|
|
Canada
|
|
Developed and Undeveloped
|
|
|
|
|
Consolidated operations
|
|
|
|
|
End of 2013
|
|
|
579
|
|
Revisions
|
|
|
(8)
|
|
Improved recovery
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
Extensions and discoveries
|
|
|
31
|
|
Production
|
|
|
(4)
|
|
Sales
|
|
|
-
|
|
|
|
End of 2014
|
|
|
598
|
|
Revisions
|
|
|
94
|
|
Improved recovery
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
Extensions and discoveries
|
|
|
-
|
|
Production
|
|
|
(5)
|
|
Sales
|
|
|
-
|
|
|
|
End of 2015
|
|
|
687
|
|
Revisions
|
|
|
(515)
|
|
Improved recovery
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
Extensions and discoveries
|
|
|
-
|
|
Production
|
|
|
(13)
|
|
Sales
|
|
|
-
|
|
|
|
End of 2016
|
|
|
159
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
End of 2013
|
|
|
1,451
|
|
Revisions
|
|
|
(14)
|
|
Improved recovery
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
Extensions and discoveries
|
|
|
74
|
|
Production
|
|
|
(43)
|
|
Sales
|
|
|
-
|
|
|
|
End of 2014
|
|
|
1,468
|
|
Revisions
|
|
|
190
|
|
Improved recovery
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
Extensions and discoveries
|
|
|
99
|
|
Production
|
|
|
(51)
|
|
Sales
|
|
|
-
|
|
|
|
End of 2015
|
|
|
1,706
|
|
Revisions
|
|
|
(573)
|
|
Improved recovery
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
Extensions and discoveries
|
|
|
10
|
|
Production
|
|
|
(54)
|
|
Sales
|
|
|
-
|
|
|
|
End of 2016
|
|
|
1,089
|
|
|
|
|
|
Total company
|
|
|
|
|
End of 2013
|
|
|
2,030
|
|
End of 2014
|
|
|
2,066
|
|
End of 2015
|
|
|
2,393
|
|
End of 2016
|
|
|
1,248
|
|
|
|
151
|
|
|
|
|
Years Ended
|
|
Bitumen
|
|
December 31
|
|
Millions of Barrels
|
|
|
|
Canada
|
|
Developed
|
|
|
|
|
Consolidated operations
|
|
|
|
|
End of 2013
|
|
|
16
|
|
End of 2014
|
|
|
13
|
|
End of 2015
|
|
|
111
|
|
End of 2016
|
|
|
159
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
End of 2013
|
|
|
181
|
|
End of 2014
|
|
|
187
|
|
End of 2015
|
|
|
311
|
|
End of 2016
|
|
|
322
|
|
|
|
|
|
Undeveloped
|
|
|
|
|
Consolidated operations
|
|
|
|
|
End of 2013
|
|
|
563
|
|
End of 2014
|
|
|
585
|
|
End of 2015
|
|
|
576
|
|
End of 2016
|
|
|
-
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
End of 2013
|
|
|
1,270
|
|
End of 2014
|
|
|
1,281
|
|
End of 2015
|
|
|
1,395
|
|
End of 2016
|
|
|
767
|
|
|
|
Notable changes in proved bitumen reserves in the three years ended December 31, 2016, included:
|
|
|
Revisions
: 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. In 2015, for both our consolidated operations and equity affiliates revisions were primarily related to reduced royalties from lower prices at Surmont, Foster Creek, Christina Lake and Narrows Lake.
|
|
|
|
Extensions and discoveries
: In 2015, for our equity affiliates extensions and discoveries were related to approval of development at Christina Lake. In 2014, for our consolidated operations extensions and
discoveries were primarily related to delineation activity at Surmont. In 2014, for our equity affiliates extensions and discoveries were primarily related to delineation activity at Foster Creek and Christina Lake, as well as regulatory approval of
a development area at Foster Creek.
|
152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
Other
Areas
|
|
|
|
Total
|
|
|
|
|
|
|
Developed and Undeveloped
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
1,708
|
|
|
|
2,187
|
|
|
|
3,895
|
|
|
|
970
|
|
|
|
785
|
|
|
|
588
|
|
|
|
409
|
|
|
|
-
|
|
|
|
6,647
|
|
Revisions
|
|
|
(19
|
)
|
|
|
109
|
|
|
|
90
|
|
|
|
48
|
|
|
|
(10
|
)
|
|
|
26
|
|
|
|
-
|
|
|
|
-
|
|
|
|
154
|
|
Improved recovery
|
|
|
8
|
|
|
|
-
|
|
|
|
8
|
|
|
|
2
|
|
|
|
-
|
|
|
|
3
|
|
|
|
-
|
|
|
|
-
|
|
|
|
13
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
17
|
|
|
|
184
|
|
|
|
201
|
|
|
|
50
|
|
|
|
-
|
|
|
|
17
|
|
|
|
-
|
|
|
|
-
|
|
|
|
268
|
|
Production
|
|
|
(78
|
)
|
|
|
(206
|
)
|
|
|
(284
|
)
|
|
|
(61
|
)
|
|
|
(78
|
)
|
|
|
(81
|
)
|
|
|
(11
|
)
|
|
|
-
|
|
|
|
(515)
|
|
Sales
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(3
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(156
|
)
|
|
|
-
|
|
|
|
(159)
|
|
|
|
End of 2014
|
|
|
1,636
|
|
|
|
2,274
|
|
|
|
3,910
|
|
|
|
1,006
|
|
|
|
697
|
|
|
|
553
|
|
|
|
242
|
|
|
|
-
|
|
|
|
6,408
|
|
Revisions
|
|
|
(165
|
)
|
|
|
(301
|
)
|
|
|
(466
|
)
|
|
|
66
|
|
|
|
(26
|
)
|
|
|
(12
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(438)
|
|
Improved recovery
|
|
|
4
|
|
|
|
4
|
|
|
|
8
|
|
|
|
2
|
|
|
|
-
|
|
|
|
32
|
|
|
|
-
|
|
|
|
-
|
|
|
|
42
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
20
|
|
|
|
84
|
|
|
|
104
|
|
|
|
10
|
|
|
|
-
|
|
|
|
8
|
|
|
|
-
|
|
|
|
-
|
|
|
|
122
|
|
Production
|
|
|
(75
|
)
|
|
|
(211
|
)
|
|
|
(286
|
)
|
|
|
(62
|
)
|
|
|
(78
|
)
|
|
|
(84
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(510)
|
|
Sales
|
|
|
-
|
|
|
|
(79
|
)
|
|
|
(79
|
)
|
|
|
(92
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(171)
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,451
|
|
|
|
-
|
|
|
|
819
|
|
|
|
-
|
|
|
|
4
|
|
|
|
2,274
|
|
Revisions
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(14
|
)
|
|
|
-
|
|
|
|
155
|
|
|
|
-
|
|
|
|
3
|
|
|
|
144
|
|
Improved recovery
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
74
|
|
|
|
-
|
|
|
|
89
|
|
|
|
-
|
|
|
|
-
|
|
|
|
163
|
|
Production
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(43
|
)
|
|
|
-
|
|
|
|
(38
|
)
|
|
|
-
|
|
|
|
(2
|
)
|
|
|
(83)
|
|
Sales
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
End of 2014
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,468
|
|
|
|
-
|
|
|
|
1,025
|
|
|
|
-
|
|
|
|
5
|
|
|
|
2,498
|
|
Revisions
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
190
|
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
189
|
|
Improved recovery
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Purchases
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
99
|
|
|
|
-
|
|
|
|
45
|
|
|
|
-
|
|
|
|
-
|
|
|
|
144
|
|
Production
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(51
|
)
|
|
|
-
|
|
|
|
(48
|
)
|
|
|
-
|
|
|
|
(1
|
)
|
|
|
(100)
|
|
Sales
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(4
|
)
|
|
|
(4)
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
1,708
|
|
|
|
2,187
|
|
|
|
3,895
|
|
|
|
2,421
|
|
|
|
785
|
|
|
|
1,407
|
|
|
|
409
|
|
|
|
4
|
|
|
|
8,921
|
|
End of 2014
|
|
|
1,636
|
|
|
|
2,274
|
|
|
|
3,910
|
|
|
|
2,474
|
|
|
|
697
|
|
|
|
1,578
|
|
|
|
242
|
|
|
|
5
|
|
|
|
8,906
|
|
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
|
|
|
|
153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
Other
Areas
|
|
|
|
Total
|
|
Developed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
1,597
|
|
|
|
1,600
|
|
|
|
3,197
|
|
|
|
386
|
|
|
|
478
|
|
|
|
405
|
|
|
|
391
|
|
|
|
-
|
|
|
|
4,857
|
|
End of 2014
|
|
|
1,514
|
|
|
|
1,637
|
|
|
|
3,151
|
|
|
|
393
|
|
|
|
452
|
|
|
|
412
|
|
|
|
237
|
|
|
|
-
|
|
|
|
4,645
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
181
|
|
|
|
-
|
|
|
|
565
|
|
|
|
-
|
|
|
|
4
|
|
|
|
750
|
|
End of 2014
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
187
|
|
|
|
-
|
|
|
|
810
|
|
|
|
-
|
|
|
|
5
|
|
|
|
1,002
|
|
End of 2015
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
311
|
|
|
|
-
|
|
|
|
890
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,201
|
|
End of 2016
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
322
|
|
|
|
-
|
|
|
|
820
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,142
|
|
|
|
|
|
|
|
|
|
|
|
Undeveloped
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
111
|
|
|
|
587
|
|
|
|
698
|
|
|
|
584
|
|
|
|
307
|
|
|
|
183
|
|
|
|
18
|
|
|
|
-
|
|
|
|
1,790
|
|
End of 2014
|
|
|
122
|
|
|
|
637
|
|
|
|
759
|
|
|
|
613
|
|
|
|
245
|
|
|
|
141
|
|
|
|
5
|
|
|
|
-
|
|
|
|
1,763
|
|
End of 2015
|
|
|
102
|
|
|
|
510
|
|
|
|
612
|
|
|
|
578
|
|
|
|
195
|
|
|
|
113
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,498
|
|
End of 2016
|
|
|
91
|
|
|
|
405
|
|
|
|
496
|
|
|
|
2
|
|
|
|
163
|
|
|
|
135
|
|
|
|
-
|
|
|
|
-
|
|
|
|
796
|
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of 2013
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,270
|
|
|
|
-
|
|
|
|
254
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,524
|
|
End of 2014
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,281
|
|
|
|
-
|
|
|
|
215
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,496
|
|
End of 2015
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,395
|
|
|
|
-
|
|
|
|
131
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,526
|
|
End of 2016
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
767
|
|
|
|
-
|
|
|
|
45
|
|
|
|
-
|
|
|
|
-
|
|
|
|
812
|
|
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 1,608 million BOE of proved undeveloped reserves at year-end 2016, compared with 3,024 million BOE at year-end 2015. The following table
shows changes in total proved undeveloped reserves for 2016:
|
|
|
|
|
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
Millions of Barrels of
Oil Equivalent
|
|
|
|
|
|
|
End of 2015
|
|
|
3,024
|
|
Transfers to proved developed
|
|
|
(310)
|
|
Revisions
|
|
|
(1,328)
|
|
Improved recovery
|
|
|
13
|
|
Purchases
|
|
|
-
|
|
Extensions and discoveries
|
|
|
212
|
|
Sales
|
|
|
(3)
|
|
|
|
End of 2016
|
|
|
1,608
|
|
|
|
Revisions, primarily in the oil sands, decreased proved undeveloped reserves due to lower prices. This was partially offset by
extensions and discoveries added from ongoing development primarily in the Lower 48, Asia Pacific/Middle East and Alaska.
As a result, at
December 31, 2016, our proved undeveloped reserves represented 25 percent of total proved reserves, compared with 37 percent at December 31, 2015. Costs incurred for the year ended December 31, 2016, relating to the development of
proved undeveloped reserves were $2.9 billion.
154
A portion of our costs incurred each year relate to development projects where the proved undeveloped reserves will be converted to proved developed reserves in future years.
Approximately 70 percent of our proved undeveloped reserves at year-end 2016 were associated with four major development areas. All of the major
development areas are currently producing and are expected to have proved undeveloped reserves convert to proved developed over time, as development activities continue and/or production facilities are expanded or upgraded, and include:
|
|
|
FCCL oil sandsFoster Creek and Christina Lake in Canada.
|
|
|
|
The Eagle Ford and Bakken areas in the Lower 48.
|
At the end of 2016, approximately 46 percent of our total
proved undeveloped reserves are currently scheduled for development five years or more from initial disclosure which are located in the Athabasca oil sands in Canada. The oil sands in Canada consist of the FCCL and Surmont steam-assisted gravity
drainage (SAGD) projects. The majority of our remaining proved undeveloped reserves in this area were recorded beginning in 2007. Our SAGD projects are large, multi-year projects with steady, long-term production at consistent levels. The associated
undeveloped reserves are expected to be developed over the life of the project, as additional well pairs are drilled to maintain throughput at the central processing facilities.
Results of Operations
The companys results
of operations from oil and gas activities for the years 2016, 2015 and 2014 are shown in the following tables. Non-oil and gas activities, such as pipeline and marine operations, liquefied natural gas 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 companys 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.
|
155
Results of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
1,056
|
|
|
|
1,967
|
|
|
|
3,023
|
|
|
|
790
|
|
|
|
795
|
|
|
|
640
|
|
|
|
23
|
|
|
|
(2
|
)
|
|
|
5,269
|
|
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
|
|
|
|
|
|
|
325
|
|
|
|
(3,731
|
)
|
|
|
(3,406
|
)
|
|
|
(1,418
|
)
|
|
|
366
|
|
|
|
456
|
|
|
|
(21
|
)
|
|
|
(34
|
)
|
|
|
(4,057
|
)
|
Income tax provision (benefit)
|
|
|
(29
|
)
|
|
|
(1,349
|
)
|
|
|
(1,378
|
)
|
|
|
(406
|
)
|
|
|
3
|
|
|
|
250
|
|
|
|
(72
|
)
|
|
|
(13
|
)
|
|
|
(1,616
|
)
|
|
|
Results of operations
|
|
$
|
354
|
|
|
|
(2,382
|
)
|
|
|
(2,028
|
)
|
|
|
(1,012
|
)
|
|
|
363
|
|
|
|
206
|
|
|
|
51
|
|
|
|
(21
|
)
|
|
|
(2,441
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
156
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
Millions of Dollars
|
|
|
|
|
|
|
December 31, 2015
|
|
|
Alaska
|
|
|
|
Lower
48
|
|
|
|
Total
U.S.
|
|
|
|
Canada
|
|
|
|
Europe
|
|
|
|
Asia Pacific/
Middle East
|
|
|
|
Africa
|
|
|
|
Other
Areas
|
|
|
|
Total
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
$
|
3,206
|
|
|
|
4,992
|
|
|
|
8,198
|
|
|
|
930
|
|
|
|
3,637
|
|
|
|
2,741
|
|
|
|
-
|
|
|
|
-
|
|
|
|
15,506
|
|
Transfers
|
|
|
15
|
|
|
|
-
|
|
|
|
15
|
|
|
|
-
|
|
|
|
-
|
|
|
|
629
|
|
|
|
-
|
|
|
|
-
|
|
|
|
644
|
|
Transportation costs
|
|
|
(599
|
)
|
|
|
-
|
|
|
|
(599
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(40
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(639
|
)
|
Other revenues
|
|
|
(5
|
)
|
|
|
452
|
|
|
|
447
|
|
|
|
(19
|
)
|
|
|
(28
|
)
|
|
|
6
|
|
|
|
13
|
|
|
|
2
|
|
|
|
421
|
|
|
|
Total revenues
|
|
|
2,617
|
|
|
|
5,444
|
|
|
|
8,061
|
|
|
|
911
|
|
|
|
3,609
|
|
|
|
3,336
|
|
|
|
13
|
|
|
|
2
|
|
|
|
15,932
|
|
Production costs excluding taxes
|
|
|
1,242
|
|
|
|
2,420
|
|
|
|
3,662
|
|
|
|
923
|
|
|
|
1,137
|
|
|
|
815
|
|
|
|
42
|
|
|
|
1
|
|
|
|
6,580
|
|
Taxes other than income taxes
|
|
|
281
|
|
|
|
358
|
|
|
|
639
|
|
|
|
62
|
|
|
|
35
|
|
|
|
33
|
|
|
|
3
|
|
|
|
1
|
|
|
|
773
|
|
Exploration expenses
|
|
|
682
|
|
|
|
1,583
|
|
|
|
2,265
|
|
|
|
457
|
|
|
|
170
|
|
|
|
268
|
|
|
|
990
|
|
|
|
43
|
|
|
|
4,193
|
|
Depreciation, depletion and amortization
|
|
|
548
|
|
|
|
4,192
|
|
|
|
4,740
|
|
|
|
777
|
|
|
|
1,813
|
|
|
|
1,321
|
|
|
|
-
|
|
|
|
-
|
|
|
|
8,651
|
|
Impairments
|
|
|
8
|
|
|
|
(2
|
)
|
|
|
6
|
|
|
|
3
|
|
|
|
724
|
|
|
|
3
|
|
|
|
-
|
|
|
|
-
|
|
|
|
736
|
|
Other related expenses
|
|
|
(30
|
)
|
|
|
78
|
|
|
|
48
|
|
|
|
8
|
|
|
|
9
|
|
|
|
(2
|
)
|
|
|
(8
|
)
|
|
|
5
|
|
|
|
60
|
|
Accretion
|
|
|
52
|
|
|
|
83
|
|
|
|
135
|
|
|
|
49
|
|
|
|
240
|
|
|
|
34
|
|
|
|
-
|
|
|
|
-
|
|
|
|
458
|
|
|
|
|
|
|
(166
|
)
|
|
|
(3,268
|
)
|
|
|
(3,434
|
)
|
|
|
(1,368
|
)
|
|
|
(519
|
)
|
|
|
864
|
|
|
|
(1,014
|
)
|
|
|
(48
|
)
|
|
|
(5,519
|
)
|
Income tax provision (benefit)
|
|
|
(89
|
)
|
|
|
(1,193
|
)
|
|
|
(1,282
|
)
|
|
|
(244
|
)
|
|
|
(816
|
)
|
|
|
430
|
|
|
|
(406
|
)
|
|
|
(27
|
)
|
|
|
(2,345
|
)
|
|
|
Results of operations
|
|
$
|
(77
|
)
|
|
|
(2,075
|
)
|
|
|
(2,152
|
)
|
|
|
(1,124
|
)
|
|
|
297
|
|
|
|
434
|
|
|
|
(608
|
)
|
|
|
(21
|
)
|
|
|
(3,174
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
917
|
|
|
|
-
|
|
|
|
536
|
|
|
|
-
|
|
|
|
50
|
|
|
|
1,503
|
|
Transfers
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
950
|
|
|
|
-
|
|
|
|
-
|
|
|
|
950
|
|
Transportation costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Other revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
34
|
|
|
|
-
|
|
|
|
4
|
|
|
|
-
|
|
|
|
58
|
|
|
|
96
|
|
|
|
Total revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
951
|
|
|
|
-
|
|
|
|
1,490
|
|
|
|
-
|
|
|
|
108
|
|
|
|
2,549
|
|
Production costs excluding taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
474
|
|
|
|
-
|
|
|
|
248
|
|
|
|
-
|
|
|
|
13
|
|
|
|
735
|
|
Taxes other than income taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
15
|
|
|
|
-
|
|
|
|
723
|
|
|
|
-
|
|
|
|
13
|
|
|
|
751
|
|
Exploration expenses
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
12
|
|
|
|
-
|
|
|
|
190
|
|
|
|
-
|
|
|
|
-
|
|
|
|
202
|
|
Depreciation, depletion and amortization
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
367
|
|
|
|
-
|
|
|
|
197
|
|
|
|
-
|
|
|
|
5
|
|
|
|
569
|
|
Impairments
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,396
|
|
|
|
-
|
|
|
|
3
|
|
|
|
1,399
|
|
Other related expenses
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2
|
)
|
|
|
-
|
|
|
|
(13
|
)
|
|
|
-
|
|
|
|
23
|
|
|
|
8
|
|
Accretion
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
7
|
|
|
|
-
|
|
|
|
10
|
|
|
|
-
|
|
|
|
1
|
|
|
|
18
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
78
|
|
|
|
-
|
|
|
|
(1,261
|
)
|
|
|
-
|
|
|
|
50
|
|
|
|
(1,133
|
)
|
Income tax provision (benefit)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
20
|
|
|
|
-
|
|
|
|
(155
|
)
|
|
|
-
|
|
|
|
10
|
|
|
|
(125
|
)
|
|
|
Results of operations
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
58
|
|
|
|
-
|
|
|
|
(1,106
|
)
|
|
|
-
|
|
|
|
40
|
|
|
|
(1,008
|
)
|
|
|
157
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
Millions of Dollars
|
|
|
|
|
|
|
December 31, 2014
|
|
|
Alaska
|
|
|
|
Lower
48
|
|
|
|
Total
U.S.
|
|
|
|
Canada
|
|
|
|
Europe
|
|
|
|
Asia Pacific/
Middle East
|
|
|
|
Africa
|
|
|
|
Other
Areas
|
|
|
|
Disc
Ops
|
|
|
|
Total
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
$
|
6,202
|
|
|
|
9,098
|
|
|
|
15,300
|
|
|
|
2,091
|
|
|
|
6,160
|
|
|
|
4,550
|
|
|
|
185
|
|
|
|
-
|
|
|
|
278
|
|
|
|
28,564
|
|
Transfers
|
|
|
47
|
|
|
|
94
|
|
|
|
141
|
|
|
|
-
|
|
|
|
-
|
|
|
|
938
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,079
|
|
Transportation costs
|
|
|
(659
|
)
|
|
|
-
|
|
|
|
(659
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(43
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(702)
|
|
Other revenues
|
|
|
13
|
|
|
|
29
|
|
|
|
42
|
|
|
|
185
|
|
|
|
(25
|
)
|
|
|
46
|
|
|
|
26
|
|
|
|
154
|
|
|
|
1,052
|
|
|
|
1,480
|
|
|
|
Total revenues
|
|
|
5,603
|
|
|
|
9,221
|
|
|
|
14,824
|
|
|
|
2,276
|
|
|
|
6,135
|
|
|
|
5,491
|
|
|
|
211
|
|
|
|
154
|
|
|
|
1,330
|
|
|
|
30,421
|
|
Production costs excluding taxes
|
|
|
1,205
|
|
|
|
2,482
|
|
|
|
3,687
|
|
|
|
1,106
|
|
|
|
1,410
|
|
|
|
994
|
|
|
|
83
|
|
|
|
1
|
|
|
|
128
|
|
|
|
7,409
|
|
Taxes other than income taxes
|
|
|
842
|
|
|
|
700
|
|
|
|
1,542
|
|
|
|
62
|
|
|
|
44
|
|
|
|
299
|
|
|
|
5
|
|
|
|
1
|
|
|
|
8
|
|
|
|
1,961
|
|
Exploration expenses
|
|
|
46
|
|
|
|
1,042
|
|
|
|
1,088
|
|
|
|
317
|
|
|
|
148
|
|
|
|
123
|
|
|
|
303
|
|
|
|
40
|
|
|
|
4
|
|
|
|
2,023
|
|
Depreciation, depletion and amortization
|
|
|
423
|
|
|
|
3,662
|
|
|
|
4,085
|
|
|
|
919
|
|
|
|
1,777
|
|
|
|
1,125
|
|
|
|
6
|
|
|
|
-
|
|
|
|
-
|
|
|
|
7,912
|
|
Impairments
|
|
|
56
|
|
|
|
107
|
|
|
|
163
|
|
|
|
38
|
|
|
|
529
|
|
|
|
7
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
737
|
|
Other related expenses
|
|
|
2
|
|
|
|
96
|
|
|
|
98
|
|
|
|
7
|
|
|
|
(233
|
)
|
|
|
(6
|
)
|
|
|
(1
|
)
|
|
|
9
|
|
|
|
(9
|
)
|
|
|
(135)
|
|
Accretion
|
|
|
52
|
|
|
|
80
|
|
|
|
132
|
|
|
|
57
|
|
|
|
245
|
|
|
|
26
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
460
|
|
|
|
|
|
|
2,977
|
|
|
|
1,052
|
|
|
|
4,029
|
|
|
|
(230
|
)
|
|
|
2,215
|
|
|
|
2,923
|
|
|
|
(185
|
)
|
|
|
103
|
|
|
|
1,199
|
|
|
|
10,054
|
|
Income tax provision (benefit)
|
|
|
1,043
|
|
|
|
322
|
|
|
|
1,365
|
|
|
|
(101
|
)
|
|
|
1,452
|
|
|
|
1,216
|
|
|
|
4
|
|
|
|
(13
|
)
|
|
|
79
|
|
|
|
4,002
|
|
|
|
Results of operations
|
|
$
|
1,934
|
|
|
|
730
|
|
|
|
2,664
|
|
|
|
(129
|
)
|
|
|
763
|
|
|
|
1,707
|
|
|
|
(189
|
)
|
|
|
116
|
|
|
|
1,120
|
|
|
|
6,052
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,307
|
|
|
|
-
|
|
|
|
851
|
|
|
|
-
|
|
|
|
96
|
|
|
|
-
|
|
|
|
3,254
|
|
Transfers
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,663
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,663
|
|
Transportation costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Other revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
33
|
|
|
|
-
|
|
|
|
3
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
36
|
|
|
|
Total revenues
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,340
|
|
|
|
-
|
|
|
|
2,517
|
|
|
|
-
|
|
|
|
96
|
|
|
|
-
|
|
|
|
4,953
|
|
Production costs excluding taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
651
|
|
|
|
-
|
|
|
|
221
|
|
|
|
-
|
|
|
|
18
|
|
|
|
-
|
|
|
|
890
|
|
Taxes other than income taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
14
|
|
|
|
-
|
|
|
|
1,214
|
|
|
|
-
|
|
|
|
51
|
|
|
|
-
|
|
|
|
1,279
|
|
Exploration expenses
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
13
|
|
|
|
7
|
|
|
|
8
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
28
|
|
Depreciation, depletion and amortization
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
337
|
|
|
|
-
|
|
|
|
171
|
|
|
|
-
|
|
|
|
7
|
|
|
|
-
|
|
|
|
515
|
|
Impairments
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
27
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
27
|
|
Other related expenses
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(65
|
)
|
|
|
1
|
|
|
|
(2
|
)
|
|
|
-
|
|
|
|
27
|
|
|
|
-
|
|
|
|
(39)
|
|
Accretion
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
6
|
|
|
|
-
|
|
|
|
8
|
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
15
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,384
|
|
|
|
(8
|
)
|
|
|
870
|
|
|
|
-
|
|
|
|
(8
|
)
|
|
|
-
|
|
|
|
2,238
|
|
Income tax provision (benefit)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
331
|
|
|
|
-
|
|
|
|
(62
|
)
|
|
|
-
|
|
|
|
2
|
|
|
|
-
|
|
|
|
271
|
|
|
|
Results of operations
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,053
|
|
|
|
(8
|
)
|
|
|
932
|
|
|
|
-
|
|
|
|
(10
|
)
|
|
|
-
|
|
|
|
1,967
|
|
|
|
158
Statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Production
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
Thousands of Barrels Daily
|
|
|
|
|
|
|
Crude Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
|
163
|
|
|
|
158
|
|
|
|
162
|
|
Lower 48
|
|
|
195
|
|
|
|
206
|
|
|
|
188
|
|
|
|
United States
|
|
|
358
|
|
|
|
364
|
|
|
|
350
|
|
Canada
|
|
|
7
|
|
|
|
12
|
|
|
|
13
|
|
Europe
|
|
|
120
|
|
|
|
120
|
|
|
|
126
|
|
Asia Pacific/Middle East
|
|
|
97
|
|
|
|
91
|
|
|
|
79
|
|
Africa
|
|
|
2
|
|
|
|
-
|
|
|
|
8
|
|
|
|
Total consolidated operations
|
|
|
584
|
|
|
|
587
|
|
|
|
576
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
Asia Pacific/Middle East
|
|
|
14
|
|
|
|
14
|
|
|
|
15
|
|
Other areas
|
|
|
-
|
|
|
|
4
|
|
|
|
4
|
|
|
|
Total equity affiliates
|
|
|
14
|
|
|
|
18
|
|
|
|
19
|
|
|
|
Total continuing operations
|
|
|
598
|
|
|
|
605
|
|
|
|
595
|
|
Discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
5
|
|
|
|
Total company
|
|
|
598
|
|
|
|
605
|
|
|
|
600
|
|
|
|
|
|
|
|
Natural Gas Liquids
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
|
12
|
|
|
|
13
|
|
|
|
13
|
|
Lower 48
|
|
|
88
|
|
|
|
94
|
|
|
|
97
|
|
|
|
United States
|
|
|
100
|
|
|
|
107
|
|
|
|
110
|
|
Canada
|
|
|
23
|
|
|
|
26
|
|
|
|
23
|
|
Europe
|
|
|
7
|
|
|
|
7
|
|
|
|
8
|
|
Asia Pacific/Middle East
|
|
|
7
|
|
|
|
9
|
|
|
|
10
|
|
|
|
Total consolidated operations
|
|
|
137
|
|
|
|
149
|
|
|
|
151
|
|
|
|
Equity affiliates
Asia Pacific/Middle East
|
|
|
8
|
|
|
|
7
|
|
|
|
8
|
|
|
|
Total continuing operations
|
|
|
145
|
|
|
|
156
|
|
|
|
159
|
|
Discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
Total company
|
|
|
145
|
|
|
|
156
|
|
|
|
160
|
|
|
|
|
|
|
|
Bitumen
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
Canada
|
|
|
35
|
|
|
|
13
|
|
|
|
12
|
|
Equity affiliates
Canada
|
|
|
148
|
|
|
|
138
|
|
|
|
117
|
|
|
|
Total company
|
|
|
183
|
|
|
|
151
|
|
|
|
129
|
|
|
|
|
|
Natural Gas
|
|
|
Millions of Cubic Feet Daily
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
|
25
|
|
|
|
42
|
|
|
|
49
|
|
Lower 48
|
|
|
1,219
|
|
|
|
1,472
|
|
|
|
1,491
|
|
|
|
United States
|
|
|
1,244
|
|
|
|
1,514
|
|
|
|
1,540
|
|
Canada
|
|
|
524
|
|
|
|
715
|
|
|
|
711
|
|
Europe
|
|
|
459
|
|
|
|
475
|
|
|
|
461
|
|
Asia Pacific/Middle East
|
|
|
730
|
|
|
|
717
|
|
|
|
723
|
|
Africa
|
|
|
1
|
|
|
|
1
|
|
|
|
3
|
|
|
|
Total consolidated operations
|
|
|
2,958
|
|
|
|
3,422
|
|
|
|
3,438
|
|
|
|
Equity affiliates
Asia Pacific/Middle East
|
|
|
899
|
|
|
|
638
|
|
|
|
505
|
|
|
|
Total continuing operations
|
|
|
3,857
|
|
|
|
4,060
|
|
|
|
3,943
|
|
Discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
88
|
|
|
|
Total company
|
|
|
3,857
|
|
|
|
4,060
|
|
|
|
4,031
|
|
|
|
159
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Prices
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
Crude Oil Per Barrel
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
$
|
31.68
|
|
|
|
41.84
|
|
|
|
87.21
|
|
Lower 48
|
|
|
37.49
|
|
|
|
42.62
|
|
|
|
84.18
|
|
United States
|
|
|
34.70
|
|
|
|
42.27
|
|
|
|
85.63
|
|
Canada
|
|
|
35.25
|
|
|
|
39.52
|
|
|
|
77.87
|
|
Europe
|
|
|
43.66
|
|
|
|
52.75
|
|
|
|
99.56
|
|
Asia Pacific/Middle East
|
|
|
42.23
|
|
|
|
49.70
|
|
|
|
95.32
|
|
Africa
|
|
|
-
|
|
|
|
60.79
|
|
|
|
86.71
|
|
Total international
|
|
|
42.76
|
|
|
|
50.79
|
|
|
|
96.48
|
|
Total consolidated operations
|
|
|
37.67
|
|
|
|
45.48
|
|
|
|
89.72
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
Asia Pacific/Middle East
|
|
|
44.11
|
|
|
|
53.12
|
|
|
|
99.01
|
|
Other areas
|
|
|
-
|
|
|
|
37.21
|
|
|
|
64.14
|
|
Total equity affiliates
|
|
|
44.11
|
|
|
|
49.92
|
|
|
|
91.48
|
|
Total continuing operations
|
|
|
37.82
|
|
|
|
45.61
|
|
|
|
89.77
|
|
Discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
110.61
|
|
|
|
|
|
Natural Gas Liquids Per Barrel
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Lower 48
|
|
$
|
14.34
|
|
|
|
14.01
|
|
|
|
30.74
|
|
United States
|
|
|
14.34
|
|
|
|
14.01
|
|
|
|
30.74
|
|
Canada
|
|
|
14.82
|
|
|
|
17.02
|
|
|
|
46.23
|
|
Europe
|
|
|
22.62
|
|
|
|
27.56
|
|
|
|
52.65
|
|
Asia Pacific/Middle East
|
|
|
29.00
|
|
|
|
37.78
|
|
|
|
69.36
|
|
Total international
|
|
|
19.06
|
|
|
|
23.21
|
|
|
|
53.26
|
|
Total consolidated operations
|
|
|
15.72
|
|
|
|
16.83
|
|
|
|
37.45
|
|
Equity affiliates
Asia Pacific/Middle
East
|
|
|
31.13
|
|
|
|
35.79
|
|
|
|
67.20
|
|
Total continuing operations
|
|
|
16.68
|
|
|
|
17.79
|
|
|
|
38.99
|
|
Discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
13.41
|
|
|
|
|
|
Bitumen Per Barrel
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
Canada
|
|
$
|
12.91
|
|
|
|
20.13
|
|
|
|
60.03
|
|
Equity affiliates
Canada
|
|
|
15.80
|
|
|
|
18.58
|
|
|
|
54.62
|
|
|
|
|
|
Natural Gas Per Thousand Cubic Feet
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
$
|
5.22
|
|
|
|
4.33
|
|
|
|
5.42
|
|
Lower 48
|
|
|
2.20
|
|
|
|
2.43
|
|
|
|
4.29
|
|
United States
|
|
|
2.24
|
|
|
|
2.47
|
|
|
|
4.32
|
|
Canada
|
|
|
1.49
|
|
|
|
1.91
|
|
|
|
4.13
|
|
Europe
|
|
|
4.71
|
|
|
|
7.14
|
|
|
|
9.29
|
|
Asia Pacific/Middle East
|
|
|
4.15
|
|
|
|
6.08
|
|
|
|
9.64
|
|
Africa
|
|
|
-
|
|
|
|
-
|
|
|
|
3.40
|
|
Total international
|
|
|
3.49
|
|
|
|
4.78
|
|
|
|
7.48
|
|
Total consolidated operations
|
|
|
2.97
|
|
|
|
3.77
|
|
|
|
6.07
|
|
Equity affiliates
Asia Pacific/Middle
East
|
|
|
2.97
|
|
|
|
4.83
|
|
|
|
9.79
|
|
Total continuing operations
|
|
|
2.97
|
|
|
|
3.93
|
|
|
|
6.54
|
|
Discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
2.53
|
|
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 Managements
Discussion and Analysis of Financial Condition and Results of Operations.
160
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
Average Production Costs Per Barrel of Oil Equivalent*
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
$
|
16.12
|
|
|
|
19.12
|
|
|
|
18.04
|
|
Lower 48
|
|
|
11.06
|
|
|
|
12.17
|
|
|
|
12.76
|
|
United States
|
|
|
12.42
|
|
|
|
13.88
|
|
|
|
14.11
|
|
Canada
|
|
|
14.20
|
|
|
|
14.88
|
|
|
|
18.14
|
|
Europe
|
|
|
10.70
|
|
|
|
15.05
|
|
|
|
18.31
|
|
Asia Pacific/Middle East
|
|
|
7.74
|
|
|
|
10.20
|
|
|
|
12.97
|
|
Africa
|
|
|
31.42
|
|
|
|
-
|
|
|
|
28.42
|
|
Total international
|
|
|
10.53
|
|
|
|
13.41
|
|
|
|
16.52
|
|
Total consolidated continuing operations
|
|
|
11.54
|
|
|
|
13.67
|
|
|
|
15.20
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
7.96
|
|
|
|
9.41
|
|
|
|
15.24
|
|
Asia Pacific/Middle East
|
|
|
4.04
|
|
|
|
5.31
|
|
|
|
5.66
|
|
Other areas
|
|
|
-
|
|
|
|
8.90
|
|
|
|
12.33
|
|
Total equity affiliates
|
|
|
5.85
|
|
|
|
7.46
|
|
|
|
10.69
|
|
Discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
16.70
|
|
|
|
|
|
Average Production Costs Per BarrelBitumen
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
Canada**
|
|
$
|
24.59
|
|
|
|
61.87
|
|
|
|
66.89
|
|
Equity affiliates
Canada
|
|
|
7.96
|
|
|
|
9.41
|
|
|
|
15.24
|
|
|
|
|
|
Taxes Other Than Income Taxes Per Barrel of Oil Equivalent
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
$
|
3.53
|
|
|
|
4.33
|
|
|
|
12.61
|
|
Lower 48
|
|
|
1.73
|
|
|
|
1.80
|
|
|
|
3.60
|
|
United States
|
|
|
2.21
|
|
|
|
2.42
|
|
|
|
5.90
|
|
Canada
|
|
|
0.99
|
|
|
|
1.00
|
|
|
|
1.02
|
|
Europe
|
|
|
0.42
|
|
|
|
0.46
|
|
|
|
0.57
|
|
Asia Pacific/Middle East
|
|
|
0.36
|
|
|
|
0.41
|
|
|
|
3.90
|
|
Africa
|
|
|
1.37
|
|
|
|
-
|
|
|
|
1.71
|
|
Total international
|
|
|
0.55
|
|
|
|
0.62
|
|
|
|
1.89
|
|
Total consolidated continuing operations
|
|
|
1.44
|
|
|
|
1.61
|
|
|
|
4.08
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
0.28
|
|
|
|
0.30
|
|
|
|
0.33
|
|
Asia Pacific/Middle East
|
|
|
7.52
|
|
|
|
15.48
|
|
|
|
31.08
|
|
Other areas
|
|
|
-
|
|
|
|
8.90
|
|
|
|
34.93
|
|
Total equity affiliates
|
|
|
4.18
|
|
|
|
7.62
|
|
|
|
15.37
|
|
Discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
1.04
|
|
|
|
|
|
Depreciation, Depletion and Amortization Per Barrel of Oil Equivalent
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
$
|
11.26
|
|
|
|
8.43
|
|
|
|
6.33
|
|
Lower 48
|
|
|
23.43
|
|
|
|
21.07
|
|
|
|
18.82
|
|
United States
|
|
|
20.15
|
|
|
|
17.96
|
|
|
|
15.63
|
|
Canada
|
|
|
15.84
|
|
|
|
12.52
|
|
|
|
15.08
|
|
Europe
|
|
|
18.71
|
|
|
|
24.00
|
|
|
|
23.07
|
|
Asia Pacific/Middle East
|
|
|
16.95
|
|
|
|
16.53
|
|
|
|
14.68
|
|
Africa
|
|
|
2.73
|
|
|
|
-
|
|
|
|
2.05
|
|
Total international
|
|
|
17.22
|
|
|
|
17.98
|
|
|
|
17.59
|
|
Total consolidated continuing operations
|
|
|
18.78
|
|
|
|
17.97
|
|
|
|
16.52
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
5.70
|
|
|
|
7.29
|
|
|
|
7.89
|
|
Asia Pacific/Middle East
|
|
|
8.65
|
|
|
|
4.22
|
|
|
|
4.38
|
|
Other areas
|
|
|
-
|
|
|
|
3.42
|
|
|
|
4.79
|
|
Total equity affiliates
|
|
|
7.29
|
|
|
|
5.77
|
|
|
|
6.19
|
|
*Includes bitumen.
**2015 revised to conform to current period presentation.
161
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, 2016, 2015
and 2014. 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
|
2
|
|
|
|
-
|
|
|
|
*
|
|
|
|
|
|
|
|
1
|
|
|
|
-
|
|
|
|
*
|
|
Lower 48
|
|
|
8
|
|
|
|
47
|
|
|
|
30
|
|
|
|
|
|
|
|
1
|
|
|
|
4
|
|
|
|
3
|
|
|
|
United States
|
|
|
10
|
|
|
|
47
|
|
|
|
30
|
|
|
|
|
|
|
|
2
|
|
|
|
4
|
|
|
|
3
|
|
Canada
|
|
|
8
|
|
|
|
16
|
|
|
|
9
|
|
|
|
|
|
|
|
1
|
|
|
|
3
|
|
|
|
*
|
|
Europe
|
|
|
*
|
|
|
|
*
|
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
|
|
*
|
|
|
|
1
|
|
Asia Pacific/Middle East
|
|
|
1
|
|
|
|
1
|
|
|
|
2
|
|
|
|
|
|
|
|
-
|
|
|
|
2
|
|
|
|
*
|
|
Africa
|
|
|
1
|
|
|
|
*
|
|
|
|
*
|
|
|
|
|
|
|
|
-
|
|
|
|
*
|
|
|
|
*
|
|
Other areas
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
Total consolidated operations
|
|
|
20
|
|
|
|
64
|
|
|
|
42
|
|
|
|
|
|
|
|
4
|
|
|
|
9
|
|
|
|
4
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asia Pacific/Middle East
|
|
|
20
|
|
|
|
19
|
|
|
|
36
|
|
|
|
|
|
|
|
-
|
|
|
|
*
|
|
|
|
2
|
|
|
|
Total equity affiliates
|
|
|
20
|
|
|
|
19
|
|
|
|
36
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
|
9
|
|
|
|
18
|
|
|
|
8
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Lower 48
|
|
|
119
|
|
|
|
347
|
|
|
|
450
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
United States
|
|
|
128
|
|
|
|
365
|
|
|
|
458
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
Canada
|
|
|
47
|
|
|
|
47
|
|
|
|
98
|
|
|
|
|
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
Europe
|
|
|
7
|
|
|
|
10
|
|
|
|
7
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Asia Pacific/Middle East
|
|
|
6
|
|
|
|
3
|
|
|
|
14
|
|
|
|
|
|
|
|
-
|
|
|
|
*
|
|
|
|
-
|
|
Africa
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Other areas
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
Total consolidated operations
|
|
|
188
|
|
|
|
425
|
|
|
|
578
|
|
|
|
|
|
|
|
2
|
|
|
|
-
|
|
|
|
1
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
48
|
|
|
|
22
|
|
|
|
38
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Asia Pacific/Middle East
|
|
|
108
|
|
|
|
166
|
|
|
|
294
|
|
|
|
|
|
|
|
-
|
|
|
|
2
|
|
|
|
1
|
|
Other areas
|
|
|
-
|
|
|
|
*
|
|
|
|
1
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
Total equity affiliates
|
|
|
156
|
|
|
|
188
|
|
|
|
333
|
|
|
|
|
|
|
|
-
|
|
|
|
2
|
|
|
|
1
|
|
|
|
*
|
Our total proportionate interest was less than one.
|
162
The table below represents the status of our wells drilling at December 31, 2016, 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, 2016.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wells at December 31, 2016
|
|
|
Productive
*
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In Progress
|
|
|
|
|
|
Oil
|
|
|
|
|
|
Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
|
2
|
|
|
|
1
|
|
|
|
|
|
|
|
1,749
|
|
|
|
781
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
Lower 48
|
|
|
208
|
|
|
|
94
|
|
|
|
|
|
|
|
10,142
|
|
|
|
5,107
|
|
|
|
|
|
|
|
20,076
|
|
|
|
13,134
|
|
|
|
United States
|
|
|
210
|
|
|
|
95
|
|
|
|
|
|
|
|
11,891
|
|
|
|
5,888
|
|
|
|
|
|
|
|
20,076
|
|
|
|
13,134
|
|
Canada
|
|
|
41
|
|
|
|
24
|
|
|
|
|
|
|
|
987
|
|
|
|
538
|
|
|
|
|
|
|
|
4,320
|
|
|
|
2,966
|
|
Europe
|
|
|
20
|
|
|
|
3
|
|
|
|
|
|
|
|
471
|
|
|
|
86
|
|
|
|
|
|
|
|
174
|
|
|
|
67
|
|
Asia Pacific/Middle East
|
|
|
13
|
|
|
|
5
|
|
|
|
|
|
|
|
356
|
|
|
|
148
|
|
|
|
|
|
|
|
55
|
|
|
|
28
|
|
Africa
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
825
|
|
|
|
135
|
|
|
|
|
|
|
|
9
|
|
|
|
1
|
|
Other areas
|
|
|
3
|
|
|
|
2
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
Total consolidated operations
|
|
|
287
|
|
|
|
129
|
|
|
|
|
|
|
|
14,530
|
|
|
|
6,795
|
|
|
|
|
|
|
|
24,634
|
|
|
|
16,196
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
125
|
|
|
|
62
|
|
|
|
|
|
|
|
457
|
|
|
|
228
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
Asia Pacific/Middle East
|
|
|
187
|
|
|
|
64
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
3,520
|
|
|
|
827
|
|
|
|
Total equity affiliates
|
|
|
312
|
|
|
|
126
|
|
|
|
|
|
|
|
457
|
|
|
|
228
|
|
|
|
|
|
|
|
3,520
|
|
|
|
827
|
|
|
|
*Includes 151 gross and 122 net multiple completion wells.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acreage at December 31, 2016
|
|
Thousands of
Acres
|
|
|
|
|
|
|
|
|
Developed
|
|
|
|
|
|
Undeveloped
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
|
608
|
|
|
|
298
|
|
|
|
|
|
|
|
683
|
|
|
|
469
|
|
Lower 48
|
|
|
4,903
|
|
|
|
3,918
|
|
|
|
|
|
|
|
10,479
|
|
|
|
8,475
|
|
|
|
United States
|
|
|
5,511
|
|
|
|
4,216
|
|
|
|
|
|
|
|
11,162
|
|
|
|
8,944
|
|
Canada
|
|
|
3,038
|
|
|
|
2,099
|
|
|
|
|
|
|
|
9,471
|
|
|
|
4,165
|
|
Europe
|
|
|
834
|
|
|
|
257
|
|
|
|
|
|
|
|
2,219
|
|
|
|
610
|
|
Asia Pacific/Middle East
|
|
|
1,593
|
|
|
|
741
|
|
|
|
|
|
|
|
10,483
|
|
|
|
5,422
|
|
Africa
|
|
|
358
|
|
|
|
58
|
|
|
|
|
|
|
|
12,545
|
|
|
|
2,049
|
|
Other areas
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
487
|
|
|
|
264
|
|
|
|
Total consolidated operations
|
|
|
11,334
|
|
|
|
7,371
|
|
|
|
|
|
|
|
46,367
|
|
|
|
21,454
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
53
|
|
|
|
22
|
|
|
|
|
|
|
|
651
|
|
|
|
273
|
|
Asia Pacific/Middle East
|
|
|
818
|
|
|
|
183
|
|
|
|
|
|
|
|
6,365
|
|
|
|
1,794
|
|
|
|
Total equity affiliates
|
|
|
871
|
|
|
|
205
|
|
|
|
|
|
|
|
7,016
|
|
|
|
2,067
|
|
|
|
163
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
|
|
|
|
|
|
|
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
|
|
|
|
-
|
|
|
|
312
|
|
|
|
-
|
|
|
|
-
|
|
|
|
679
|
|
|
|
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
382
|
|
|
|
-
|
|
|
|
333
|
|
|
|
-
|
|
|
|
-
|
|
|
|
715
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved property acquisition
|
|
$
|
-
|
|
|
|
168
|
|
|
|
168
|
|
|
|
52
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
220
|
|
Proved property acquisition
|
|
|
-
|
|
|
|
5
|
|
|
|
5
|
|
|
|
1
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
6
|
|
|
|
|
|
|
-
|
|
|
|
173
|
|
|
|
173
|
|
|
|
53
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
226
|
|
Exploration
|
|
|
87
|
|
|
|
1,369
|
|
|
|
1,456
|
|
|
|
298
|
|
|
|
107
|
|
|
|
118
|
|
|
|
394
|
|
|
|
47
|
|
|
|
2,420
|
|
Development
|
|
|
1,217
|
|
|
|
2,875
|
|
|
|
4,092
|
|
|
|
827
|
|
|
|
1,742
|
|
|
|
587
|
|
|
|
4
|
|
|
|
-
|
|
|
|
7,252
|
|
|
|
|
|
$
|
1,304
|
|
|
|
4,417
|
|
|
|
5,721
|
|
|
|
1,178
|
|
|
|
1,849
|
|
|
|
705
|
|
|
|
398
|
|
|
|
47
|
|
|
|
9,898
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved property acquisition
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Proved property acquisition
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Exploration
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
17
|
|
|
|
-
|
|
|
|
60
|
|
|
|
-
|
|
|
|
-
|
|
|
|
77
|
|
Development
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
847
|
|
|
|
-
|
|
|
|
655
|
|
|
|
-
|
|
|
|
3
|
|
|
|
1,505
|
|
|
|
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
864
|
|
|
|
-
|
|
|
|
715
|
|
|
|
-
|
|
|
|
3
|
|
|
|
1,582
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved property acquisition
|
|
$
|
-
|
|
|
|
159
|
|
|
|
159
|
|
|
|
61
|
|
|
|
90
|
|
|
|
-
|
|
|
|
6
|
|
|
|
-
|
|
|
|
316
|
|
Proved property acquisition
|
|
|
-
|
|
|
|
10
|
|
|
|
10
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
10
|
|
|
|
|
|
|
-
|
|
|
|
169
|
|
|
|
169
|
|
|
|
61
|
|
|
|
90
|
|
|
|
-
|
|
|
|
6
|
|
|
|
-
|
|
|
|
326
|
|
Exploration
|
|
|
130
|
|
|
|
1,347
|
|
|
|
1,477
|
|
|
|
332
|
|
|
|
243
|
|
|
|
166
|
|
|
|
556
|
|
|
|
58
|
|
|
|
2,832
|
|
Development
|
|
|
1,263
|
|
|
|
4,881
|
|
|
|
6,144
|
|
|
|
2,185
|
|
|
|
3,618
|
|
|
|
1,353
|
|
|
|
71
|
|
|
|
-
|
|
|
|
13,371
|
|
|
|
|
|
$
|
1,393
|
|
|
|
6,397
|
|
|
|
7,790
|
|
|
|
2,578
|
|
|
|
3,951
|
|
|
|
1,519
|
|
|
|
633
|
|
|
|
58
|
|
|
|
16,529
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved property acquisition
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
Proved property acquisition
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
Exploration
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
23
|
|
|
|
36
|
|
|
|
117
|
|
|
|
-
|
|
|
|
-
|
|
|
|
176
|
|
Development
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,627
|
|
|
|
-
|
|
|
|
1,965
|
|
|
|
-
|
|
|
|
9
|
|
|
|
3,601
|
|
|
|
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,650
|
|
|
|
36
|
|
|
|
2,084
|
|
|
|
-
|
|
|
|
9
|
|
|
|
3,779
|
|
|
|
*Certain amounts in Asia Pacific/Middle East equity affiliates have been restated in 2015 and 2014 to remove amounts
considered to be non-oil and gas producing activities.
164
Capitalized Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
Alaska
|
|
|
|
Lower
48
|
|
|
|
Total
U.S.
|
|
|
|
Canada
|
|
|
|
Europe
|
|
|
|
Asia Pacific/
Middle East*
|
|
|
|
Africa
|
|
|
|
Other
Areas
|
|
|
|
Total
|
|
|
|
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved property
|
|
$
|
17,376
|
|
|
|
46,050
|
|
|
|
63,426
|
|
|
|
16,970
|
|
|
|
24,858
|
|
|
|
13,837
|
|
|
|
879
|
|
|
|
-
|
|
|
|
119,970
|
|
Unproved property
|
|
|
1,099
|
|
|
|
1,376
|
|
|
|
2,475
|
|
|
|
1,435
|
|
|
|
269
|
|
|
|
787
|
|
|
|
123
|
|
|
|
61
|
|
|
|
5,150
|
|
|
|
|
|
|
18,475
|
|
|
|
47,426
|
|
|
|
65,901
|
|
|
|
18,405
|
|
|
|
25,127
|
|
|
|
14,624
|
|
|
|
1,002
|
|
|
|
61
|
|
|
|
125,120
|
|
Accumulated depreciation, depletion and amortization
|
|
|
8,548
|
|
|
|
26,858
|
|
|
|
35,406
|
|
|
|
10,344
|
|
|
|
15,754
|
|
|
|
7,635
|
|
|
|
297
|
|
|
|
1
|
|
|
|
69,437
|
|
|
|
|
|
$
|
9,927
|
|
|
|
20,568
|
|
|
|
30,495
|
|
|
|
8,061
|
|
|
|
9,373
|
|
|
|
6,989
|
|
|
|
705
|
|
|
|
60
|
|
|
|
55,683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved property
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
9,459
|
|
|
|
-
|
|
|
|
8,501
|
|
|
|
-
|
|
|
|
-
|
|
|
|
17,960
|
|
Unproved property
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
891
|
|
|
|
-
|
|
|
|
2,756
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3,647
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
10,350
|
|
|
|
-
|
|
|
|
11,257
|
|
|
|
-
|
|
|
|
-
|
|
|
|
21,607
|
|
Accumulated depreciation, depletion and amortization
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,906
|
|
|
|
-
|
|
|
|
1,369
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3,275
|
|
|
|
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
8,444
|
|
|
|
-
|
|
|
|
9,888
|
|
|
|
-
|
|
|
|
-
|
|
|
|
18,332
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved property
|
|
$
|
17,007
|
|
|
|
45,256
|
|
|
|
62,263
|
|
|
|
16,552
|
|
|
|
26,851
|
|
|
|
16,254
|
|
|
|
873
|
|
|
|
3
|
|
|
|
122,796
|
|
Unproved property
|
|
|
1,609
|
|
|
|
2,414
|
|
|
|
4,023
|
|
|
|
1,418
|
|
|
|
330
|
|
|
|
781
|
|
|
|
823
|
|
|
|
35
|
|
|
|
7,410
|
|
|
|
|
|
|
18,616
|
|
|
|
47,670
|
|
|
|
66,286
|
|
|
|
17,970
|
|
|
|
27,181
|
|
|
|
17,035
|
|
|
|
1,696
|
|
|
|
38
|
|
|
|
130,206
|
|
Accumulated depreciation, depletion and amortization
|
|
|
8,688
|
|
|
|
22,993
|
|
|
|
31,681
|
|
|
|
9,371
|
|
|
|
16,166
|
|
|
|
8,853
|
|
|
|
788
|
|
|
|
4
|
|
|
|
66,863
|
|
|
|
|
|
$
|
9,928
|
|
|
|
24,677
|
|
|
|
34,605
|
|
|
|
8,599
|
|
|
|
11,015
|
|
|
|
8,182
|
|
|
|
908
|
|
|
|
34
|
|
|
|
63,343
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved property
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
8,763
|
|
|
|
-
|
|
|
|
8,086
|
|
|
|
-
|
|
|
|
-
|
|
|
|
16,849
|
|
Unproved property
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
906
|
|
|
|
-
|
|
|
|
3,040
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3,946
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
9,669
|
|
|
|
-
|
|
|
|
11,126
|
|
|
|
-
|
|
|
|
-
|
|
|
|
20,795
|
|
Accumulated depreciation, depletion and amortization
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,537
|
|
|
|
-
|
|
|
|
1,017
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,554
|
|
|
|
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
8,132
|
|
|
|
-
|
|
|
|
10,109
|
|
|
|
-
|
|
|
|
-
|
|
|
|
18,241
|
|
|
|
*Certain amounts in Asia Pacific/Middle East equity affiliates have been restated in 2015 to remove amounts considered to be
non-oil and gas producing activities.
165
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
|
|
|
|
|
|
|
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 (benefit)
|
|
|
-
|
|
|
|
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
|
|
|
|
166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
Alaska
|
|
|
Lower
48
|
|
|
Total
U.S.
|
|
|
Canada
|
|
|
Europe
|
|
|
Asia Pacific/
Middle East
|
|
|
Africa
|
|
|
Total
|
|
|
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
44,054
|
|
|
|
42,575
|
|
|
|
86,629
|
|
|
|
22,317
|
|
|
|
27,782
|
|
|
|
19,368
|
|
|
|
13,875
|
|
|
|
169,971
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future production costs
|
|
|
32,732
|
|
|
|
21,638
|
|
|
|
54,370
|
|
|
|
13,103
|
|
|
|
10,574
|
|
|
|
7,529
|
|
|
|
1,422
|
|
|
|
86,998
|
|
Future development costs
|
|
|
9,885
|
|
|
|
12,967
|
|
|
|
22,852
|
|
|
|
6,471
|
|
|
|
12,793
|
|
|
|
2,884
|
|
|
|
437
|
|
|
|
45,437
|
|
Future income tax provisions
|
|
|
-
|
|
|
|
844
|
|
|
|
844
|
|
|
|
-
|
|
|
|
1,506
|
|
|
|
2,708
|
|
|
|
10,998
|
|
|
|
16,056
|
|
|
|
Future net cash flows
|
|
|
1,437
|
|
|
|
7,126
|
|
|
|
8,563
|
|
|
|
2,743
|
|
|
|
2,909
|
|
|
|
6,247
|
|
|
|
1,018
|
|
|
|
21,480
|
|
10 percent annual discount
|
|
|
(502
|
)
|
|
|
1,573
|
|
|
|
1,071
|
|
|
|
1,265
|
|
|
|
733
|
|
|
|
1,349
|
|
|
|
500
|
|
|
|
4,918
|
|
|
|
Discounted future net cash flows
|
|
$
|
1,939
|
|
|
|
5,553
|
|
|
|
7,492
|
|
|
|
1,478
|
|
|
|
2,176
|
|
|
|
4,898
|
|
|
|
518
|
|
|
|
16,562
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
36,211
|
|
|
|
-
|
|
|
|
34,257
|
|
|
|
-
|
|
|
|
70,468
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future production costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
16,417
|
|
|
|
-
|
|
|
|
17,874
|
|
|
|
-
|
|
|
|
34,291
|
|
Future development costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
11,869
|
|
|
|
-
|
|
|
|
2,391
|
|
|
|
-
|
|
|
|
14,260
|
|
Future income tax provisions
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,648
|
|
|
|
-
|
|
|
|
3,117
|
|
|
|
-
|
|
|
|
4,765
|
|
|
|
Future net cash flows
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
6,277
|
|
|
|
-
|
|
|
|
10,875
|
|
|
|
-
|
|
|
|
17,152
|
|
10 percent annual discount
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3,827
|
|
|
|
-
|
|
|
|
4,298
|
|
|
|
-
|
|
|
|
8,125
|
|
|
|
Discounted future net cash flows
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,450
|
|
|
|
-
|
|
|
|
6,577
|
|
|
|
-
|
|
|
|
9,027
|
|
|
|
|
|
|
|
|
|
|
|
|
Total company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted future net cash flows
|
|
$
|
1,939
|
|
|
|
5,553
|
|
|
|
7,492
|
|
|
|
3,928
|
|
|
|
2,176
|
|
|
|
11,475
|
|
|
|
518
|
|
|
|
25,589
|
|
|
|
167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
Alaska
|
|
|
Lower
48
|
|
|
Total
U.S.
|
|
|
Canada
|
|
|
Europe
|
|
|
Asia Pacific/
Middle East
|
|
|
Africa
|
|
|
Other
Areas
|
|
|
Total
|
|
|
|
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
106,506
|
|
|
|
100,322
|
|
|
|
206,828
|
|
|
|
50,209
|
|
|
|
55,878
|
|
|
|
39,492
|
|
|
|
25,997
|
|
|
|
-
|
|
|
|
378,404
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future production costs
|
|
|
57,924
|
|
|
|
37,872
|
|
|
|
95,796
|
|
|
|
21,342
|
|
|
|
16,372
|
|
|
|
12,555
|
|
|
|
1,338
|
|
|
|
-
|
|
|
|
147,403
|
|
Future development costs
|
|
|
10,815
|
|
|
|
19,666
|
|
|
|
30,481
|
|
|
|
10,400
|
|
|
|
14,194
|
|
|
|
2,985
|
|
|
|
437
|
|
|
|
-
|
|
|
|
58,497
|
|
Future income tax provisions
|
|
|
12,483
|
|
|
|
14,800
|
|
|
|
27,283
|
|
|
|
3,159
|
|
|
|
15,757
|
|
|
|
7,728
|
|
|
|
22,526
|
|
|
|
-
|
|
|
|
76,453
|
|
|
|
Future net cash flows
|
|
|
25,284
|
|
|
|
27,984
|
|
|
|
53,268
|
|
|
|
15,308
|
|
|
|
9,555
|
|
|
|
16,224
|
|
|
|
1,696
|
|
|
|
-
|
|
|
|
96,051
|
|
10 percent annual discount
|
|
|
12,499
|
|
|
|
10,150
|
|
|
|
22,649
|
|
|
|
8,915
|
|
|
|
2,741
|
|
|
|
4,607
|
|
|
|
791
|
|
|
|
-
|
|
|
|
39,703
|
|
|
|
Discounted future net cash flows
|
|
$
|
12,785
|
|
|
|
17,834
|
|
|
|
30,619
|
|
|
|
6,393
|
|
|
|
6,814
|
|
|
|
11,617
|
|
|
|
905
|
|
|
|
-
|
|
|
|
56,348
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
88,716
|
|
|
|
-
|
|
|
|
61,480
|
|
|
|
-
|
|
|
|
357
|
|
|
|
150,553
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future production costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
25,455
|
|
|
|
-
|
|
|
|
27,274
|
|
|
|
-
|
|
|
|
276
|
|
|
|
53,005
|
|
Future development costs
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
11,595
|
|
|
|
-
|
|
|
|
3,007
|
|
|
|
-
|
|
|
|
16
|
|
|
|
14,618
|
|
Future income tax provisions
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
12,322
|
|
|
|
-
|
|
|
|
7,225
|
|
|
|
-
|
|
|
|
10
|
|
|
|
19,557
|
|
|
|
Future net cash flows
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
39,344
|
|
|
|
-
|
|
|
|
23,974
|
|
|
|
-
|
|
|
|
55
|
|
|
|
63,373
|
|
10 percent annual discount
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
25,601
|
|
|
|
-
|
|
|
|
10,897
|
|
|
|
-
|
|
|
|
6
|
|
|
|
36,504
|
|
|
|
Discounted future net cash flows
|
|
$
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
13,743
|
|
|
|
-
|
|
|
|
13,077
|
|
|
|
-
|
|
|
|
49
|
|
|
|
26,869
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted future net cash flows
|
|
$
|
12,785
|
|
|
|
17,834
|
|
|
|
30,619
|
|
|
|
20,136
|
|
|
|
6,814
|
|
|
|
24,694
|
|
|
|
905
|
|
|
|
49
|
|
|
|
83,217
|
|
|
|
168
Sources of Change in Discounted Future Net Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
Consolidated Operations
|
|
|
|
|
|
Equity Affiliates
|
|
|
|
|
|
Total Company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015*
|
|
|
|
2014*
|
|
|
|
|
|
|
|
2016
|
|
|
|
2015*
|
|
|
|
2014*
|
|
|
|
|
|
|
Discounted future net cash flows at the beginning of the year
|
|
$
|
16,562
|
|
|
|
56,348
|
|
|
|
56,003
|
|
|
|
|
|
|
|
9,027
|
|
|
|
26,869
|
|
|
|
21,509
|
|
|
|
|
|
|
|
25,589
|
|
|
|
83,217
|
|
|
|
77,512
|
|
|
|
Changes during the year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues less production costs for the year
|
|
|
(6,313
|
)
|
|
|
(8,158
|
)
|
|
|
(19,571
|
)
|
|
|
|
|
|
|
(956
|
)
|
|
|
(966
|
)
|
|
|
(2,748
|
)
|
|
|
|
|
|
|
(7,269
|
)
|
|
|
(9,124
|
)
|
|
|
(22,319
|
)
|
Net change in prices and production costs
|
|
|
(16,476
|
)
|
|
|
(82,923
|
)
|
|
|
(9,243
|
)
|
|
|
|
|
|
|
(9,317
|
)
|
|
|
(27,670
|
)
|
|
|
4,517
|
|
|
|
|
|
|
|
(25,793
|
)
|
|
|
(110,593
|
)
|
|
|
(4,726
|
)
|
Extensions, discoveries and improved recovery, less estimated future costs
|
|
|
1,358
|
|
|
|
1,791
|
|
|
|
7,033
|
|
|
|
|
|
|
|
(77
|
)
|
|
|
319
|
|
|
|
1,822
|
|
|
|
|
|
|
|
1,281
|
|
|
|
2,110
|
|
|
|
8,855
|
|
Development costs for the year
|
|
|
3,118
|
|
|
|
6,854
|
|
|
|
11,785
|
|
|
|
|
|
|
|
722
|
|
|
|
1,493
|
|
|
|
3,453
|
|
|
|
|
|
|
|
3,840
|
|
|
|
8,347
|
|
|
|
15,238
|
|
Changes in estimated future development costs
|
|
|
6,646
|
|
|
|
2,073
|
|
|
|
(7,771
|
)
|
|
|
|
|
|
|
2,435
|
|
|
|
(227
|
)
|
|
|
(1,613
|
)
|
|
|
|
|
|
|
9,081
|
|
|
|
1,846
|
|
|
|
(9,384
|
)
|
Purchases of reserves in place, less estimated future costs
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5
|
|
|
|
|
|
|
|
2
|
|
|
|
-
|
|
|
|
5
|
|
Sales of reserves in place, less estimated future costs
|
|
|
(123
|
)
|
|
|
(424
|
)
|
|
|
(1,280
|
)
|
|
|
|
|
|
|
-
|
|
|
|
(38
|
)
|
|
|
-
|
|
|
|
|
|
|
|
(123
|
)
|
|
|
(462
|
)
|
|
|
(1,280
|
)
|
Revisions of previous quantity estimates
|
|
|
(3,252
|
)
|
|
|
(1,790
|
)
|
|
|
1,348
|
|
|
|
|
|
|
|
(436
|
)
|
|
|
938
|
|
|
|
(1,166
|
)
|
|
|
|
|
|
|
(3,688
|
)
|
|
|
(852
|
)
|
|
|
182
|
|
Accretion of discount
|
|
|
2,540
|
|
|
|
9,342
|
|
|
|
10,045
|
|
|
|
|
|
|
|
1,058
|
|
|
|
3,297
|
|
|
|
2,648
|
|
|
|
|
|
|
|
3,598
|
|
|
|
12,639
|
|
|
|
12,693
|
|
Net change in income taxes
|
|
|
4,089
|
|
|
|
33,449
|
|
|
|
7,999
|
|
|
|
|
|
|
|
1,481
|
|
|
|
5,012
|
|
|
|
(1,558
|
)
|
|
|
|
|
|
|
5,570
|
|
|
|
38,461
|
|
|
|
6,441
|
|
|
|
Total changes
|
|
|
(8,411
|
)
|
|
|
(39,786
|
)
|
|
|
345
|
|
|
|
|
|
|
|
(5,090
|
)
|
|
|
(17,842
|
)
|
|
|
5,360
|
|
|
|
|
|
|
|
(13,501
|
)
|
|
|
(57,628
|
)
|
|
|
5,705
|
|
|
|
Discounted future net cash flows at year end
|
|
$
|
8,151
|
|
|
|
16,562
|
|
|
|
56,348
|
|
|
|
|
|
|
|
3,937
|
|
|
|
9,027
|
|
|
|
26,869
|
|
|
|
|
|
|
|
12,088
|
|
|
|
25,589
|
|
|
|
83,217
|
|
|
|
*
|
Certain amounts in equity affiliates were restated to reclassify amounts between Development costs for the year and Changes in estimated future development costs.
|
|
|
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 years 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.
|
169
Selected Quarterly Financial Data
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
Per Share of Common Stock
|
|
|
|
|
Sales and
Other
Operating
Revenues
|
|
|
|
Income (Loss)
From Continuing
Operations Before
Income Taxes
|
|
|
|
Net
Income
(Loss)
|
|
|
|
Net Income
(Loss)
Attributable to
ConocoPhillips
|
|
|
|
Net Income (Loss)
Attributable
to ConocoPhillips
|
|
|
|
|
|
|
|
Basic
|
|
|
|
Diluted
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
$
|
5,121
|
|
|
|
(2,224)
|
|
|
|
(1,456)
|
|
|
|
(1,469)
|
|
|
|
(1.18)
|
|
|
|
(1.18)
|
|
Second
|
|
|
5,348
|
|
|
|
(1,644)
|
|
|
|
(1,058)
|
|
|
|
(1,071)
|
|
|
|
(0.86)
|
|
|
|
(0.86)
|
|
Third
|
|
|
6,415
|
|
|
|
(1,654)
|
|
|
|
(1,026)
|
|
|
|
(1,040)
|
|
|
|
(0.84)
|
|
|
|
(0.84)
|
|
Fourth
|
|
|
6,809
|
|
|
|
(8)
|
|
|
|
(19)
|
|
|
|
(35)
|
|
|
|
(0.03)
|
|
|
|
(0.03)
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First
|
|
$
|
7,716
|
|
|
|
(356)
|
|
|
|
286
|
|
|
|
272
|
|
|
|
0.22
|
|
|
|
0.22
|
|
Second
|
|
|
8,293
|
|
|
|
(91)
|
|
|
|
(164)
|
|
|
|
(179)
|
|
|
|
(0.15)
|
|
|
|
(0.15)
|
|
Third
|
|
|
7,262
|
|
|
|
(1,741)
|
|
|
|
(1,056)
|
|
|
|
(1,071)
|
|
|
|
(0.87)
|
|
|
|
(0.87)
|
|
Fourth
|
|
|
6,293
|
|
|
|
(5,051)
|
|
|
|
(3,437)
|
|
|
|
(3,450)
|
|
|
|
(2.78)
|
|
|
|
(2.78)
|
|
|
|
For additional information on the commodity price environment, see the Business Environment and Executive Overview section of
Managements Discussion and Analysis of Financial Condition and Results of Operations.
170
Supplementary InformationCondensed Consolidating Financial Information
We have various cross guarantees among ConocoPhillips, ConocoPhillips Company and ConocoPhillips Canada Funding Company I, with respect to publicly held debt
securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. ConocoPhillips Canada Funding Company I is an indirect, 100 percent owned subsidiary of ConocoPhillips Company. ConocoPhillips and ConocoPhillips Company have fully and
unconditionally guaranteed the payment obligations of ConocoPhillips Canada Funding Company I, with respect to their publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of
ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All
guarantees are joint and several. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:
|
|
|
ConocoPhillips, ConocoPhillips Company and ConocoPhillips Canada Funding Company I (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).
|
|
|
|
All other nonguarantor subsidiaries of ConocoPhillips.
|
|
|
|
The consolidating adjustments necessary to present ConocoPhillips results on a consolidated basis.
|
In
May 2014, we filed a universal shelf registration statement with the SEC under which ConocoPhillips, as a well-known seasoned issuer, has the ability to issue and sell an indeterminate amount of various types of debt and equity securities, with
certain debt securities guaranteed by ConocoPhillips Company. Also as part of that registration statement, ConocoPhillips Trust I and ConocoPhillips Trust II have the ability to issue and sell preferred trust securities, guaranteed by
ConocoPhillips. ConocoPhillips Trust I and ConocoPhillips Trust II have not issued any trust-preferred securities under this registration statement, and thus have no assets or liabilities. Accordingly, columns for these two trusts are not included
in the condensed consolidating financial information.
In 2014, ConocoPhillips received $34.5 billion in dividends from ConocoPhillips Company to settle
certain accumulated intercompany balances. This consisted of a $17.5 billion distribution of earnings and a $17 billion return of capital. These transactions had no impact on our consolidated financial statements.
In 2015, ConocoPhillips received a $3.5 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 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 is reflected in our consolidated financial statements.
This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.
171
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
Income Statement
|
|
|
ConocoPhillips
|
|
|
|
ConocoPhillips
Company
|
|
|
|
ConocoPhillips
Canada Funding
Company I
|
|
|
|
All Other
Subsidiaries
|
|
|
|
Consolidating
Adjustments
|
|
|
|
Total
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and Other Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues
|
|
$
|
-
|
|
|
|
10,352
|
|
|
|
-
|
|
|
|
13,341
|
|
|
|
-
|
|
|
|
23,693
|
|
Equity in earnings (losses) of affiliates
|
|
|
(3,351)
|
|
|
|
(1,051)
|
|
|
|
-
|
|
|
|
(91)
|
|
|
|
4,545
|
|
|
|
52
|
|
Gain on dispositions
|
|
|
-
|
|
|
|
120
|
|
|
|
-
|
|
|
|
240
|
|
|
|
-
|
|
|
|
360
|
|
Other income (loss)
|
|
|
1
|
|
|
|
(11)
|
|
|
|
-
|
|
|
|
265
|
|
|
|
-
|
|
|
|
255
|
|
Intercompany revenues
|
|
|
88
|
|
|
|
277
|
|
|
|
220
|
|
|
|
3,036
|
|
|
|
(3,621)
|
|
|
|
-
|
|
|
|
Total Revenues and Other Income
|
|
|
(3,262)
|
|
|
|
9,687
|
|
|
|
220
|
|
|
|
16,791
|
|
|
|
924
|
|
|
|
24,360
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased commodities
|
|
|
-
|
|
|
|
9,144
|
|
|
|
-
|
|
|
|
3,562
|
|
|
|
(2,712)
|
|
|
|
9,994
|
|
Production and operating expenses
|
|
|
-
|
|
|
|
779
|
|
|
|
-
|
|
|
|
5,131
|
|
|
|
(243)
|
|
|
|
5,667
|
|
Selling, general and administrative expenses
|
|
|
8
|
|
|
|
581
|
|
|
|
-
|
|
|
|
140
|
|
|
|
(6)
|
|
|
|
723
|
|
Exploration expenses
|
|
|
-
|
|
|
|
1,231
|
|
|
|
-
|
|
|
|
684
|
|
|
|
-
|
|
|
|
1,915
|
|
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
|
|
|
|
207
|
|
|
|
570
|
|
|
|
(660)
|
|
|
|
1,245
|
|
Foreign currency transaction (gains) losses
|
|
|
(19)
|
|
|
|
2
|
|
|
|
174
|
|
|
|
(176)
|
|
|
|
-
|
|
|
|
(19)
|
|
|
|
Total Costs and Expenses
|
|
|
495
|
|
|
|
13,812
|
|
|
|
381
|
|
|
|
18,823
|
|
|
|
(3,621)
|
|
|
|
29,890
|
|
|
|
Loss from continuing operations before income taxes
|
|
|
(3,757)
|
|
|
|
(4,125)
|
|
|
|
(161)
|
|
|
|
(2,032)
|
|
|
|
4,545
|
|
|
|
(5,530)
|
|
Income tax benefit
|
|
|
(142)
|
|
|
|
(774)
|
|
|
|
(9)
|
|
|
|
(1,046)
|
|
|
|
-
|
|
|
|
(1,971)
|
|
|
|
Net loss
|
|
|
(3,615)
|
|
|
|
(3,351)
|
|
|
|
(152)
|
|
|
|
(986)
|
|
|
|
4,545
|
|
|
|
(3,559)
|
|
Less: net income attributable to noncontrolling interests
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(56)
|
|
|
|
-
|
|
|
|
(56)
|
|
|
|
Loss Attributable to ConocoPhillips
|
|
$
|
(3,615)
|
|
|
|
(3,351)
|
|
|
|
(152)
|
|
|
|
(1,042)
|
|
|
|
4,545
|
|
|
|
(3,615)
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Loss Attributable to ConocoPhillips
|
|
$
|
(3,561)
|
|
|
|
(3,297)
|
|
|
|
(27)
|
|
|
|
(952)
|
|
|
|
4,276
|
|
|
|
(3,561)
|
|
|
|
|
|
Income Statement
|
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
Revenues and Other Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues
|
|
$
|
-
|
|
|
|
11,473
|
|
|
|
-
|
|
|
|
18,091
|
|
|
|
-
|
|
|
|
29,564
|
|
Equity in earnings (losses) of affiliates
|
|
|
(4,081)
|
|
|
|
(1,950)
|
|
|
|
-
|
|
|
|
1,364
|
|
|
|
5,322
|
|
|
|
655
|
|
Gain on dispositions
|
|
|
-
|
|
|
|
332
|
|
|
|
-
|
|
|
|
259
|
|
|
|
-
|
|
|
|
591
|
|
Other income
|
|
|
-
|
|
|
|
12
|
|
|
|
-
|
|
|
|
113
|
|
|
|
-
|
|
|
|
125
|
|
Intercompany revenues
|
|
|
74
|
|
|
|
341
|
|
|
|
246
|
|
|
|
3,365
|
|
|
|
(4,026)
|
|
|
|
-
|
|
|
|
Total Revenues and Other Income
|
|
|
(4,007)
|
|
|
|
10,208
|
|
|
|
246
|
|
|
|
23,192
|
|
|
|
1,296
|
|
|
|
30,935
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased commodities
|
|
|
-
|
|
|
|
9,905
|
|
|
|
-
|
|
|
|
5,838
|
|
|
|
(3,317)
|
|
|
|
12,426
|
|
Production and operating expenses
|
|
|
-
|
|
|
|
1,469
|
|
|
|
-
|
|
|
|
5,585
|
|
|
|
(38)
|
|
|
|
7,016
|
|
Selling, general and administrative expenses
|
|
|
9
|
|
|
|
744
|
|
|
|
1
|
|
|
|
209
|
|
|
|
(10)
|
|
|
|
953
|
|
Exploration expenses
|
|
|
-
|
|
|
|
2,093
|
|
|
|
-
|
|
|
|
2,099
|
|
|
|
-
|
|
|
|
4,192
|
|
Depreciation, depletion and amortization
|
|
|
-
|
|
|
|
1,201
|
|
|
|
-
|
|
|
|
7,912
|
|
|
|
-
|
|
|
|
9,113
|
|
Impairments
|
|
|
-
|
|
|
|
15
|
|
|
|
-
|
|
|
|
2,230
|
|
|
|
-
|
|
|
|
2,245
|
|
Taxes other than income taxes
|
|
|
-
|
|
|
|
173
|
|
|
|
-
|
|
|
|
728
|
|
|
|
-
|
|
|
|
901
|
|
Accretion on discounted liabilities
|
|
|
-
|
|
|
|
58
|
|
|
|
-
|
|
|
|
425
|
|
|
|
-
|
|
|
|
483
|
|
Interest and debt expense
|
|
|
485
|
|
|
|
423
|
|
|
|
226
|
|
|
|
447
|
|
|
|
(661)
|
|
|
|
920
|
|
Foreign currency transaction (gains) losses
|
|
|
114
|
|
|
|
1
|
|
|
|
(708)
|
|
|
|
518
|
|
|
|
-
|
|
|
|
(75)
|
|
|
|
Total Costs and Expenses
|
|
|
608
|
|
|
|
16,082
|
|
|
|
(481)
|
|
|
|
25,991
|
|
|
|
(4,026)
|
|
|
|
38,174
|
|
|
|
Income (loss) from continuing operations before income taxes
|
|
|
(4,615)
|
|
|
|
(5,874)
|
|
|
|
727
|
|
|
|
(2,799)
|
|
|
|
5,322
|
|
|
|
(7,239)
|
|
Income tax provision (benefit)
|
|
|
(187)
|
|
|
|
(1,793)
|
|
|
|
21
|
|
|
|
(909)
|
|
|
|
-
|
|
|
|
(2,868)
|
|
|
|
Net income (loss)
|
|
|
(4,428)
|
|
|
|
(4,081)
|
|
|
|
706
|
|
|
|
(1,890)
|
|
|
|
5,322
|
|
|
|
(4,371)
|
|
Less: net income attributable to noncontrolling interests
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(57)
|
|
|
|
-
|
|
|
|
(57)
|
|
|
|
Net Income (Loss) Attributable to ConocoPhillips
|
|
$
|
(4,428)
|
|
|
|
(4,081)
|
|
|
|
706
|
|
|
|
(1,947)
|
|
|
|
5,322
|
|
|
|
(4,428)
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income (Loss) Attributable to ConocoPhillips
|
|
$
|
(8,773)
|
|
|
|
(8,426)
|
|
|
|
71
|
|
|
|
(6,705)
|
|
|
|
15,060
|
|
|
|
(8,773)
|
|
|
|
172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
Income Statement
|
|
|
ConocoPhillips
|
|
|
|
ConocoPhillips
Company
|
|
|
|
ConocoPhillips
Canada Funding
Company I
|
|
|
|
All Other
Subsidiaries
|
|
|
|
Consolidating
Adjustments
|
|
|
|
Total
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues and Other Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and other operating revenues
|
|
$
|
-
|
|
|
|
20,083
|
|
|
|
-
|
|
|
|
32,441
|
|
|
|
-
|
|
|
|
52,524
|
|
Equity in earnings of affiliates
|
|
|
6,108
|
|
|
|
8,090
|
|
|
|
-
|
|
|
|
2,932
|
|
|
|
(14,601
|
)
|
|
|
2,529
|
|
Gain on dispositions
|
|
|
-
|
|
|
|
9
|
|
|
|
-
|
|
|
|
89
|
|
|
|
-
|
|
|
|
98
|
|
Other income (loss)
|
|
|
(6
|
)
|
|
|
67
|
|
|
|
-
|
|
|
|
305
|
|
|
|
-
|
|
|
|
366
|
|
Intercompany revenues
|
|
|
79
|
|
|
|
465
|
|
|
|
283
|
|
|
|
5,883
|
|
|
|
(6,710
|
)
|
|
|
-
|
|
|
|
Total Revenues and Other Income
|
|
|
6,181
|
|
|
|
28,714
|
|
|
|
283
|
|
|
|
41,650
|
|
|
|
(21,311
|
)
|
|
|
55,517
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased commodities
|
|
|
-
|
|
|
|
17,591
|
|
|
|
-
|
|
|
|
10,415
|
|
|
|
(5,907
|
)
|
|
|
22,099
|
|
Production and operating expenses
|
|
|
-
|
|
|
|
2,600
|
|
|
|
-
|
|
|
|
6,368
|
|
|
|
(59
|
)
|
|
|
8,909
|
|
Selling, general and administrative expenses
|
|
|
9
|
|
|
|
575
|
|
|
|
1
|
|
|
|
166
|
|
|
|
(16
|
)
|
|
|
735
|
|
Exploration expenses
|
|
|
-
|
|
|
|
1,036
|
|
|
|
-
|
|
|
|
1,009
|
|
|
|
-
|
|
|
|
2,045
|
|
Depreciation, depletion and amortization
|
|
|
-
|
|
|
|
1,059
|
|
|
|
-
|
|
|
|
7,270
|
|
|
|
-
|
|
|
|
8,329
|
|
Impairments
|
|
|
-
|
|
|
|
127
|
|
|
|
-
|
|
|
|
729
|
|
|
|
-
|
|
|
|
856
|
|
Taxes other than income taxes
|
|
|
-
|
|
|
|
285
|
|
|
|
-
|
|
|
|
1,803
|
|
|
|
-
|
|
|
|
2,088
|
|
Accretion on discounted liabilities
|
|
|
-
|
|
|
|
58
|
|
|
|
-
|
|
|
|
426
|
|
|
|
-
|
|
|
|
484
|
|
Interest and debt expense
|
|
|
571
|
|
|
|
299
|
|
|
|
231
|
|
|
|
275
|
|
|
|
(728
|
)
|
|
|
648
|
|
Foreign currency transaction (gains) losses
|
|
|
62
|
|
|
|
10
|
|
|
|
(372
|
)
|
|
|
234
|
|
|
|
-
|
|
|
|
(66
|
)
|
|
|
Total Costs and Expenses
|
|
|
642
|
|
|
|
23,640
|
|
|
|
(140
|
)
|
|
|
28,695
|
|
|
|
(6,710
|
)
|
|
|
46,127
|
|
|
|
Income from continuing operations before income taxes
|
|
|
5,539
|
|
|
|
5,074
|
|
|
|
423
|
|
|
|
12,955
|
|
|
|
(14,601
|
)
|
|
|
9,390
|
|
Income tax provision (benefit)
|
|
|
(199
|
)
|
|
|
(1,034
|
)
|
|
|
19
|
|
|
|
4,797
|
|
|
|
-
|
|
|
|
3,583
|
|
|
|
Income From Continuing Operations
|
|
|
5,738
|
|
|
|
6,108
|
|
|
|
404
|
|
|
|
8,158
|
|
|
|
(14,601
|
)
|
|
|
5,807
|
|
Income from discontinued operations
|
|
|
1,131
|
|
|
|
1,131
|
|
|
|
-
|
|
|
|
113
|
|
|
|
(1,244
|
)
|
|
|
1,131
|
|
|
|
Net income
|
|
|
6,869
|
|
|
|
7,239
|
|
|
|
404
|
|
|
|
8,271
|
|
|
|
(15,845
|
)
|
|
|
6,938
|
|
Less: net income attributable to noncontrolling interests
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(69
|
)
|
|
|
-
|
|
|
|
(69
|
)
|
|
|
Net Income Attributable to ConocoPhillips
|
|
$
|
6,869
|
|
|
|
7,239
|
|
|
|
404
|
|
|
|
8,202
|
|
|
|
(15,845
|
)
|
|
|
6,869
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income Attributable to ConocoPhillips
|
|
$
|
2,965
|
|
|
|
3,335
|
|
|
|
58
|
|
|
|
4,589
|
|
|
|
(7,982
|
)
|
|
|
2,965
|
|
|
|
173
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
|
|
|
At December 31, 2016
|
|
|
|
|
|
|
Balance Sheet
|
|
|
ConocoPhillips
|
|
|
|
ConocoPhillips
Company
|
|
|
|
ConocoPhillips
Canada Funding
Company I
|
|
|
|
All Other
Subsidiaries
|
|
|
|
Consolidating
Adjustments
|
|
|
|
Total
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
-
|
|
|
|
358
|
|
|
|
13
|
|
|
|
3,239
|
|
|
|
-
|
|
|
|
3,610
|
|
Short-term investments
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
50
|
|
|
|
-
|
|
|
|
50
|
|
Accounts and notes receivable
|
|
|
22
|
|
|
|
1,968
|
|
|
|
23
|
|
|
|
6,103
|
|
|
|
(4,702
|
)
|
|
|
3,414
|
|
Inventories
|
|
|
-
|
|
|
|
84
|
|
|
|
-
|
|
|
|
934
|
|
|
|
-
|
|
|
|
1,018
|
|
Prepaid expenses and other current assets
|
|
|
2
|
|
|
|
116
|
|
|
|
8
|
|
|
|
415
|
|
|
|
(24
|
)
|
|
|
517
|
|
|
|
Total Current Assets
|
|
|
24
|
|
|
|
2,526
|
|
|
|
44
|
|
|
|
10,741
|
|
|
|
(4,726
|
)
|
|
|
8,609
|
|
Investments, loans and long-term receivables*
|
|
|
37,901
|
|
|
|
64,434
|
|
|
|
2,296
|
|
|
|
31,643
|
|
|
|
(114,602
|
)
|
|
|
21,672
|
|
Net properties, plants and equipment
|
|
|
-
|
|
|
|
6,301
|
|
|
|
-
|
|
|
|
52,030
|
|
|
|
-
|
|
|
|
58,331
|
|
Other assets
|
|
|
40
|
|
|
|
2,194
|
|
|
|
220
|
|
|
|
1,240
|
|
|
|
(2,534
|
)
|
|
|
1,160
|
|
|
|
Total Assets
|
|
$
|
37,965
|
|
|
|
75,455
|
|
|
|
2,560
|
|
|
|
95,654
|
|
|
|
(121,862
|
)
|
|
|
89,772
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
-
|
|
|
|
4,683
|
|
|
|
1
|
|
|
|
3,671
|
|
|
|
(4,702
|
)
|
|
|
3,653
|
|
Short-term debt
|
|
|
(10
|
)
|
|
|
999
|
|
|
|
6
|
|
|
|
94
|
|
|
|
-
|
|
|
|
1,089
|
|
Accrued income and other taxes
|
|
|
-
|
|
|
|
85
|
|
|
|
-
|
|
|
|
399
|
|
|
|
-
|
|
|
|
484
|
|
Employee benefit obligations
|
|
|
-
|
|
|
|
489
|
|
|
|
-
|
|
|
|
200
|
|
|
|
-
|
|
|
|
689
|
|
Other accruals
|
|
|
171
|
|
|
|
271
|
|
|
|
40
|
|
|
|
536
|
|
|
|
(24
|
)
|
|
|
994
|
|
|
|
Total Current Liabilities
|
|
|
161
|
|
|
|
6,527
|
|
|
|
47
|
|
|
|
4,900
|
|
|
|
(4,726
|
)
|
|
|
6,909
|
|
Long-term debt
|
|
|
8,975
|
|
|
|
12,635
|
|
|
|
1,710
|
|
|
|
2,866
|
|
|
|
-
|
|
|
|
26,186
|
|
Asset retirement obligations and accrued environmental costs
|
|
|
-
|
|
|
|
925
|
|
|
|
-
|
|
|
|
7,500
|
|
|
|
-
|
|
|
|
8,425
|
|
Deferred income taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
10,972
|
|
|
|
(2,023
|
)
|
|
|
8,949
|
|
Employee benefit obligations
|
|
|
-
|
|
|
|
1,901
|
|
|
|
-
|
|
|
|
651
|
|
|
|
-
|
|
|
|
2,552
|
|
Other liabilities and deferred credits*
|
|
|
417
|
|
|
|
10,391
|
|
|
|
748
|
|
|
|
17,832
|
|
|
|
(27,863
|
)
|
|
|
1,525
|
|
|
|
Total Liabilities
|
|
|
9,553
|
|
|
|
32,379
|
|
|
|
2,505
|
|
|
|
44,721
|
|
|
|
(34,612
|
)
|
|
|
54,546
|
|
Retained earnings
|
|
|
25,025
|
|
|
|
14,015
|
|
|
|
(541
|
)
|
|
|
12,883
|
|
|
|
(19,834
|
)
|
|
|
31,548
|
|
Other common stockholders equity
|
|
|
3,387
|
|
|
|
29,061
|
|
|
|
596
|
|
|
|
37,798
|
|
|
|
(67,416
|
)
|
|
|
3,426
|
|
Noncontrolling interests
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
252
|
|
|
|
-
|
|
|
|
252
|
|
|
|
Total Liabilities and Stockholders Equity
|
|
$
|
37,965
|
|
|
|
75,455
|
|
|
|
2,560
|
|
|
|
95,654
|
|
|
|
(121,862
|
)
|
|
|
89,772
|
|
|
|
|
|
Balance Sheet
|
|
|
At December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
-
|
|
|
|
4
|
|
|
|
15
|
|
|
|
2,349
|
|
|
|
-
|
|
|
|
2,368
|
|
Accounts and notes receivable
|
|
|
21
|
|
|
|
2,905
|
|
|
|
21
|
|
|
|
7,228
|
|
|
|
(5,661
|
)
|
|
|
4,514
|
|
Inventories
|
|
|
-
|
|
|
|
142
|
|
|
|
-
|
|
|
|
982
|
|
|
|
-
|
|
|
|
1,124
|
|
Prepaid expenses and other current assets
|
|
|
2
|
|
|
|
206
|
|
|
|
252
|
|
|
|
589
|
|
|
|
(266
|
)
|
|
|
783
|
|
|
|
Total Current Assets
|
|
|
23
|
|
|
|
3,257
|
|
|
|
288
|
|
|
|
11,148
|
|
|
|
(5,927
|
)
|
|
|
8,789
|
|
Investments, loans and long-term receivables*
|
|
|
43,532
|
|
|
|
64,015
|
|
|
|
3,264
|
|
|
|
27,839
|
|
|
|
(117,464
|
)
|
|
|
21,186
|
|
Net properties, plants and equipment
|
|
|
-
|
|
|
|
8,110
|
|
|
|
-
|
|
|
|
58,336
|
|
|
|
-
|
|
|
|
66,446
|
|
Other assets
|
|
|
7
|
|
|
|
950
|
|
|
|
233
|
|
|
|
1,158
|
|
|
|
(1,285
|
)
|
|
|
1,063
|
|
|
|
Total Assets
|
|
$
|
43,562
|
|
|
|
76,332
|
|
|
|
3,785
|
|
|
|
98,481
|
|
|
|
(124,676
|
)
|
|
|
97,484
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Stockholders Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
-
|
|
|
|
5,684
|
|
|
|
13
|
|
|
|
4,897
|
|
|
|
(5,661
|
)
|
|
|
4,933
|
|
Short-term debt
|
|
|
(9
|
)
|
|
|
1
|
|
|
|
1,255
|
|
|
|
180
|
|
|
|
-
|
|
|
|
1,427
|
|
Accrued income and other taxes
|
|
|
-
|
|
|
|
62
|
|
|
|
-
|
|
|
|
437
|
|
|
|
-
|
|
|
|
499
|
|
Employee benefit obligations
|
|
|
-
|
|
|
|
629
|
|
|
|
-
|
|
|
|
258
|
|
|
|
-
|
|
|
|
887
|
|
Other accruals
|
|
|
170
|
|
|
|
465
|
|
|
|
52
|
|
|
|
1,087
|
|
|
|
(264
|
)
|
|
|
1,510
|
|
|
|
Total Current Liabilities
|
|
|
161
|
|
|
|
6,841
|
|
|
|
1,320
|
|
|
|
6,859
|
|
|
|
(5,925
|
)
|
|
|
9,256
|
|
Long-term debt
|
|
|
7,518
|
|
|
|
10,660
|
|
|
|
1,716
|
|
|
|
3,559
|
|
|
|
-
|
|
|
|
23,453
|
|
Asset retirement obligations and accrued environmental costs
|
|
|
-
|
|
|
|
1,107
|
|
|
|
-
|
|
|
|
8,473
|
|
|
|
-
|
|
|
|
9,580
|
|
Deferred income taxes
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
11,814
|
|
|
|
(815
|
)
|
|
|
10,999
|
|
Employee benefit obligations
|
|
|
-
|
|
|
|
1,760
|
|
|
|
-
|
|
|
|
526
|
|
|
|
-
|
|
|
|
2,286
|
|
Other liabilities and deferred credits*
|
|
|
2,681
|
|
|
|
7,291
|
|
|
|
667
|
|
|
|
15,181
|
|
|
|
(23,992
|
)
|
|
|
1,828
|
|
|
|
Total Liabilities
|
|
|
10,360
|
|
|
|
27,659
|
|
|
|
3,703
|
|
|
|
46,412
|
|
|
|
(30,732
|
)
|
|
|
57,402
|
|
Retained earnings
|
|
|
29,892
|
|
|
|
17,366
|
|
|
|
(389
|
)
|
|
|
15,177
|
|
|
|
(25,632
|
)
|
|
|
36,414
|
|
Other common stockholders equity
|
|
|
3,310
|
|
|
|
31,307
|
|
|
|
471
|
|
|
|
36,572
|
|
|
|
(68,312
|
)
|
|
|
3,348
|
|
Noncontrolling interests
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
320
|
|
|
|
-
|
|
|
|
320
|
|
|
|
Total Liabilities and Stockholders Equity
|
|
$
|
43,562
|
|
|
|
76,332
|
|
|
|
3,785
|
|
|
|
98,481
|
|
|
|
(124,676
|
)
|
|
|
97,484
|
|
|
|
*Includes intercompany loans.
174
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
Statement of Cash Flows
|
|
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
|
|
ConocoPhillips
|
|
|
|
ConocoPhillips
Company
|
|
|
|
ConocoPhillips
Canada Funding
Company I
|
|
|
|
All Other
Subsidiaries
|
|
|
|
Consolidating
Adjustments
|
|
|
|
Total
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by (Used in) Operating Activities
|
|
$
|
(306)
|
|
|
|
(322)
|
|
|
|
(2)
|
|
|
|
5,903
|
|
|
|
(870)
|
|
|
|
4,403
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures and investments
|
|
|
-
|
|
|
|
(989)
|
|
|
|
-
|
|
|
|
(4,281)
|
|
|
|
401
|
|
|
|
(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 sales of short-term investments
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(51)
|
|
|
|
-
|
|
|
|
(51)
|
|
Long-term advances/loansrelated parties
|
|
|
-
|
|
|
|
(812)
|
|
|
|
-
|
|
|
|
-
|
|
|
|
812
|
|
|
|
-
|
|
Collection of advances/loansrelated parties
|
|
|
-
|
|
|
|
391
|
|
|
|
1,250
|
|
|
|
272
|
|
|
|
(1,805)
|
|
|
|
108
|
|
Intercompany cash management
|
|
|
(2,214)
|
|
|
|
1,433
|
|
|
|
-
|
|
|
|
781
|
|
|
|
-
|
|
|
|
-
|
|
Other
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
(3)
|
|
|
|
-
|
|
|
|
(2)
|
|
|
|
Net Cash Provided by (Used in) Investing Activities
|
|
|
86
|
|
|
|
164
|
|
|
|
1,250
|
|
|
|
(2,373)
|
|
|
|
(2,986)
|
|
|
|
(3,859)
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of debt
|
|
|
1,600
|
|
|
|
2,994
|
|
|
|
-
|
|
|
|
812
|
|
|
|
(812)
|
|
|
|
4,594
|
|
Repayment of debt
|
|
|
(150)
|
|
|
|
(164)
|
|
|
|
(1,250)
|
|
|
|
(2,492)
|
|
|
|
1,805
|
|
|
|
(2,251)
|
|
Issuance of company common stock
|
|
|
148
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(211)
|
|
|
|
(63)
|
|
Repurchase of company common stock
|
|
|
(126)
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(126)
|
|
Dividends paid
|
|
|
(1,253)
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,081)
|
|
|
|
1,081
|
|
|
|
(1,253)
|
|
Other
|
|
|
1
|
|
|
|
(2,315)
|
|
|
|
-
|
|
|
|
184
|
|
|
|
1,993
|
|
|
|
(137)
|
|
|
|
Net Cash Provided by (Used in) Financing Activities
|
|
|
220
|
|
|
|
515
|
|
|
|
(1,250)
|
|
|
|
(2,577)
|
|
|
|
3,856
|
|
|
|
764
|
|
|
|
|
|
|
|
|
|
|
Effect of Exchange Rate Changes on Cash and Cash Equivalents
|
|
|
-
|
|
|
|
(3)
|
|
|
|
-
|
|
|
|
(63)
|
|
|
|
-
|
|
|
|
(66)
|
|
|
|
|
|
|
|
|
|
|
Net Change in Cash and Cash Equivalents
|
|
|
-
|
|
|
|
354
|
|
|
|
(2)
|
|
|
|
890
|
|
|
|
-
|
|
|
|
1,242
|
|
Cash and cash equivalents at beginning of period
|
|
|
-
|
|
|
|
4
|
|
|
|
15
|
|
|
|
2,349
|
|
|
|
-
|
|
|
|
2,368
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
-
|
|
|
|
358
|
|
|
|
13
|
|
|
|
3,239
|
|
|
|
-
|
|
|
|
3,610
|
|
|
|
|
|
Statement of Cash Flows
|
|
|
Year Ended December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by (Used in) Operating Activities
|
|
|
(225)
|
|
|
|
245
|
|
|
|
9
|
|
|
|
7,519
|
|
|
|
24
|
|
|
|
7,572
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures and investments
|
|
|
-
|
|
|
|
(3,064)
|
|
|
|
-
|
|
|
|
(8,386)
|
|
|
|
1,400
|
|
|
|
(10,050)
|
|
Working capital changes associated with investing activities
|
|
|
-
|
|
|
|
(4)
|
|
|
|
-
|
|
|
|
(964)
|
|
|
|
-
|
|
|
|
(968)
|
|
Proceeds from asset dispositions
|
|
|
3,500
|
|
|
|
826
|
|
|
|
-
|
|
|
|
1,225
|
|
|
|
(3,599)
|
|
|
|
1,952
|
|
Long-term advances/loansrelated parties
|
|
|
-
|
|
|
|
(278)
|
|
|
|
-
|
|
|
|
(2,245)
|
|
|
|
2,523
|
|
|
|
-
|
|
Collection of advances/loansrelated parties
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
205
|
|
|
|
(100)
|
|
|
|
105
|
|
Intercompany cash management
|
|
|
102
|
|
|
|
46
|
|
|
|
-
|
|
|
|
(148)
|
|
|
|
-
|
|
|
|
-
|
|
Other
|
|
|
-
|
|
|
|
304
|
|
|
|
-
|
|
|
|
1
|
|
|
|
1
|
|
|
|
306
|
|
|
|
Net Cash Provided by (Used in) Investing Activities
|
|
|
3,602
|
|
|
|
(2,170)
|
|
|
|
-
|
|
|
|
(10,312)
|
|
|
|
225
|
|
|
|
(8,655)
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of debt
|
|
|
-
|
|
|
|
4,743
|
|
|
|
-
|
|
|
|
278
|
|
|
|
(2,523)
|
|
|
|
2,498
|
|
Repayment of debt
|
|
|
-
|
|
|
|
(100)
|
|
|
|
-
|
|
|
|
(103)
|
|
|
|
100
|
|
|
|
(103)
|
|
Issuance of company common stock
|
|
|
283
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(2)
|
|
|
|
(363)
|
|
|
|
(82)
|
|
Dividends paid
|
|
|
(3,664)
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(339)
|
|
|
|
339
|
|
|
|
(3,664)
|
|
Other
|
|
|
4
|
|
|
|
(3,484)
|
|
|
|
-
|
|
|
|
1,204
|
|
|
|
2,198
|
|
|
|
(78)
|
|
|
|
Net Cash Provided by (Used in) Financing Activities
|
|
|
(3,377)
|
|
|
|
1,159
|
|
|
|
-
|
|
|
|
1,038
|
|
|
|
(249)
|
|
|
|
(1,429)
|
|
|
|
|
|
|
|
|
|
|
Effect of Exchange Rate Changes on Cash and Cash Equivalents
|
|
|
-
|
|
|
|
-
|
|
|
|
(1)
|
|
|
|
(181)
|
|
|
|
-
|
|
|
|
(182)
|
|
|
|
|
|
|
|
|
|
|
Net Change in Cash and Cash Equivalents
|
|
|
-
|
|
|
|
(766)
|
|
|
|
8
|
|
|
|
(1,936)
|
|
|
|
-
|
|
|
|
(2,694)
|
|
Cash and cash equivalents at beginning of period
|
|
|
-
|
|
|
|
770
|
|
|
|
7
|
|
|
|
4,285
|
|
|
|
-
|
|
|
|
5,062
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
-
|
|
|
|
4
|
|
|
|
15
|
|
|
|
2,349
|
|
|
|
-
|
|
|
|
2,368
|
|
|
|
175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Millions of Dollars
|
|
|
|
|
|
|
Statement of Cash Flows
|
|
Year Ended December 31, 2014
|
|
|
|
|
|
|
|
|
|
ConocoPhillips
|
|
|
|
ConocoPhillips
Company
|
|
|
|
ConocoPhillips
Canada Funding
Company I
|
|
|
|
All Other
Subsidiaries
|
|
|
|
Consolidating
Adjustments
|
|
|
|
Total
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) continuing operating activities
|
|
$
|
17,259
|
|
|
|
2,948
|
|
|
|
27
|
|
|
|
16,941
|
|
|
|
(20,763)
|
|
|
|
16,412
|
|
Net cash provided by discontinued operations
|
|
|
-
|
|
|
|
202
|
|
|
|
-
|
|
|
|
408
|
|
|
|
(453)
|
|
|
|
157
|
|
|
|
Net Cash Provided by (Used in) Operating Activities
|
|
|
17,259
|
|
|
|
3,150
|
|
|
|
27
|
|
|
|
17,349
|
|
|
|
(21,216)
|
|
|
|
16,569
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures and investments
|
|
|
-
|
|
|
|
(6,507)
|
|
|
|
-
|
|
|
|
(14,840)
|
|
|
|
4,262
|
|
|
|
(17,085)
|
|
Working capital changes associated with investing activities
|
|
|
-
|
|
|
|
17
|
|
|
|
-
|
|
|
|
163
|
|
|
|
-
|
|
|
|
180
|
|
Proceeds from asset dispositions
|
|
|
16,912
|
|
|
|
1,588
|
|
|
|
-
|
|
|
|
253
|
|
|
|
(17,150)
|
|
|
|
1,603
|
|
Net purchases of short-term investments
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
253
|
|
|
|
-
|
|
|
|
253
|
|
Long-term advances/loansrelated parties
|
|
|
-
|
|
|
|
(736)
|
|
|
|
(241)
|
|
|
|
(7)
|
|
|
|
984
|
|
|
|
-
|
|
Collection of advances/loansrelated parties
|
|
|
-
|
|
|
|
593
|
|
|
|
-
|
|
|
|
112
|
|
|
|
(102)
|
|
|
|
603
|
|
Intercompany cash management
|
|
|
(29,113)
|
|
|
|
31,993
|
|
|
|
-
|
|
|
|
(2,880)
|
|
|
|
-
|
|
|
|
-
|
|
Other
|
|
|
-
|
|
|
|
(415)
|
|
|
|
-
|
|
|
|
(31)
|
|
|
|
-
|
|
|
|
(446)
|
|
|
|
Net cash provided by (used in) continuing investing activities
|
|
|
(12,201)
|
|
|
|
26,533
|
|
|
|
(241)
|
|
|
|
(16,977)
|
|
|
|
(12,006)
|
|
|
|
(14,892)
|
|
Net cash provided by (used in) discontinued operations
|
|
|
-
|
|
|
|
133
|
|
|
|
-
|
|
|
|
(73)
|
|
|
|
(133)
|
|
|
|
(73)
|
|
|
|
Net Cash Provided by (Used in) Investing Activities
|
|
|
(12,201)
|
|
|
|
26,666
|
|
|
|
(241)
|
|
|
|
(17,050)
|
|
|
|
(12,139)
|
|
|
|
(14,965)
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of debt
|
|
|
-
|
|
|
|
2,994
|
|
|
|
-
|
|
|
|
984
|
|
|
|
(984)
|
|
|
|
2,994
|
|
Repayment of debt
|
|
|
(1,909)
|
|
|
|
(16)
|
|
|
|
-
|
|
|
|
(191)
|
|
|
|
102
|
|
|
|
(2,014)
|
|
Issuance of company common stock
|
|
|
377
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(342)
|
|
|
|
35
|
|
Dividends paid
|
|
|
(3,525)
|
|
|
|
(17,588)
|
|
|
|
-
|
|
|
|
(3,768)
|
|
|
|
21,356
|
|
|
|
(3,525)
|
|
Other
|
|
|
(1)
|
|
|
|
(16,870)
|
|
|
|
-
|
|
|
|
3,919
|
|
|
|
12,888
|
|
|
|
(64)
|
|
|
|
Net cash used in continuing financing activities
|
|
|
(5,058)
|
|
|
|
(31,480)
|
|
|
|
-
|
|
|
|
944
|
|
|
|
33,020
|
|
|
|
(2,574)
|
|
Net cash used in discontinued operations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(335)
|
|
|
|
335
|
|
|
|
-
|
|
|
|
Net Cash Used in Financing Activities
|
|
|
(5,058)
|
|
|
|
(31,480)
|
|
|
|
-
|
|
|
|
609
|
|
|
|
33,355
|
|
|
|
(2,574)
|
|
|
|
|
|
|
|
|
|
|
Effect of Exchange Rate Changes on Cash and Cash Equivalents
|
|
|
-
|
|
|
|
-
|
|
|
|
(8)
|
|
|
|
(206)
|
|
|
|
-
|
|
|
|
(214)
|
|
|
|
|
|
|
|
|
|
|
Net Change in Cash and Cash Equivalents
|
|
|
-
|
|
|
|
(1,664)
|
|
|
|
(222)
|
|
|
|
702
|
|
|
|
-
|
|
|
|
(1,184)
|
|
Cash and cash equivalents at beginning of period
|
|
|
-
|
|
|
|
2,434
|
|
|
|
229
|
|
|
|
3,583
|
|
|
|
-
|
|
|
|
6,246
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
-
|
|
|
|
770
|
|
|
|
7
|
|
|
|
4,285
|
|
|
|
-
|
|
|
|
5,062
|
|
|
|
176