Hess (HES) 10-K 26 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Feb. 19, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Trading Symbol	HES
Entity Registrant Name	HESS CORP
Entity Central Index Key	4,447
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		315,240,299
Entity Public Float			$ 16,710

Consolidated Balance Sheet

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current Assets:
Cash and cash equivalents	$ 2,716	$ 2,444
Accounts receivable
Trade	847	1,642
Other	312	431
Inventories	399	527
Other current assets	130	1,269
Total current assets	4,404	6,313
Property, plant and equipment:
Total — at cost	46,826	46,522
Less: Reserves for depreciation, depletion, amortization and lease impairment	20,474	19,005
Property, plant and equipment — net	26,352	27,517
Goodwill	375	1,858
Deferred income taxes	2,653	2,371
Other assets	411	348
TOTAL ASSETS	34,195	38,407
Current Liabilities:
Accounts payable	457	708
Accrued liabilities	1,997	3,781
Taxes payable	88	294
Current maturities of long-term debt	86	68
Total current liabilities	2,628	4,851
Long-term debt	6,544	5,919
Deferred income taxes	1,334	1,838
Asset retirement obligations	2,158	2,281
Other liabilities and deferred credits	1,130	1,198
Total liabilities	13,794	16,087
Hess Corporation stockholders’ equity
Common stock, par value $1.00 Authorized — 600,000,000 shares Issued — 286,045,586 shares at December 31, 2015 (2014: 285,834,964)	286	286
Capital in excess of par value	4,127	3,277
Retained earnings	16,637	20,052
Accumulated other comprehensive income (loss)	(1,664)	(1,410)
Total Hess Corporation stockholders’ equity	19,386	22,205
Noncontrolling interests	1,015	115
Total equity	20,401	22,320
TOTAL LIABILITIES AND EQUITY	$ 34,195	$ 38,407

Consolidated Balance Sheet (Par

Consolidated Balance Sheet (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Statement Of Financial Position [Abstract]
Common stock, par value	$ 1	$ 1
Common stock, shares authorized	600,000,000	600,000,000
Common stock, shares issued	286,045,586	285,834,964

Statement of Consolidated Incom

Statement of Consolidated Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues and Non-Operating Income
Sales and other operating revenues	$ 6,636	$ 10,737	$ 11,905
Gains on asset sales, net	51	823	2,174
Other, net	(126)	(121)	(51)
Total revenues and non-operating income	6,561	11,439	14,028
Costs and Expenses
Cost of products sold (excluding items shown separately below)	1,294	1,719	1,725
Operating costs and expenses	2,029	2,034	2,244
Production and severance taxes	146	275	372
Exploration expenses, including dry holes and lease impairment	881	840	1,031
General and administrative expenses	557	588	673
Interest expense	341	323	406
Depreciation, depletion and amortization	3,955	3,224	2,687
Impairment	1,616	0	289
Total costs and expenses	10,819	9,003	9,427
Income (Loss) From Continuing Operations Before Income Taxes	(4,258)	2,436	4,601
Provision (benefit) for income taxes	(1,299)	744	565
Income (Loss) From Continuing Operations	(2,959)	1,692	4,036
Income (Loss) From Discontinued Operations, Net of Income Taxes	(48)	682	1,186
Net Income (Loss)	(3,007)	2,374	5,222
Less: Net income (loss) attributable to noncontrolling interests	49	57	170
Net Income (Loss) Attributable to Hess Corporation	$ (3,056)	$ 2,317	$ 5,052
Basic:
Continuing operations	$ (10.61)	$ 5.57	$ 11.47
Discontinued operations	(0.17)	2.06	3.54
Net Income (Loss) Per Share	(10.78)	7.63	15.01
Diluted:
Continuing operations	(10.61)	5.50	11.33
Discontinued operations	(0.17)	2.03	3.49
Net Income (Loss) Per Share	$ (10.78)	$ 7.53	$ 14.82
Weighted Average Number of Common Shares Outstanding (Diluted)	283.6	307.7	340.9

Statement of Consolidated Compr

Statement of Consolidated Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement Of Income And Comprehensive Income [Abstract]
Net Income (Loss)	$ (3,007)	$ 2,374	$ 5,222
Derivatives designated as cash flow hedges:
Effect of hedge (gains) losses reclassified to income	(118)	(137)	(33)
Income taxes on effect of hedge (gains) losses reclassified to income	44	51	18
Net effect of hedge (gains) losses reclassified to income	(74)	(86)	(15)
Change in fair value of cash flow hedges	121	128	68
Income taxes on change in fair value of cash flow hedges	(45)	(48)	(25)
Net change in fair value of cash flow hedges	76	80	43
Change in derivatives designated as cash flow hedges, after-tax	2	(6)	28
Pension and other postretirement plans:
Reduction (increase) of unrecognized actuarial losses	17	(534)	414
Income taxes on actuarial changes in plan liabilities	4	186	(157)
Reduction (increase) in unrecognized actuarial losses, net	21	(348)	257
Amortization of net actuarial losses	92	56	63
Income taxes on amortization of net actuarial losses	(31)	(18)	(23)
Net effect of amortization of net actuarial losses	61	38	40
Recognition of accumulated actuarial losses - HOVENSA	15	0	0
Income taxes on recognition of accumulated actuarial losses - HOVENSA	(9)	0	0
Recognition of accumulated actuarial losses, net of tax - HOVENSA	6	0	0
Change in pension and other postretirement plans, after-tax	88	(310)	297
Foreign currency translation adjustment:
Foreign currency translation adjustment	(344)	(756)	(283)
Reclassified to Gains on asset sales, net	0	0	119
Change in foreign currency translation adjustment	(344)	(756)	(164)
Other Comprehensive Income (Loss)	(254)	(1,072)	161
Comprehensive Income (Loss)	(3,261)	1,302	5,383
Less: Comprehensive income (loss) attributable to noncontrolling interests	49	57	176
Comprehensive Income (Loss) Attributable to Hess Corporation	$ (3,310)	$ 1,245	$ 5,207

Statement of Consolidated Cash

Statement of Consolidated Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flows From Operating Activities
Net Income (Loss)	$ (3,007)	$ 2,374	$ 5,222
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
(Gains) losses on asset sales, net	(51)	(823)	(2,174)
Depreciation, depletion and amortization	3,955	3,224	2,687
Impairment	1,616	0	289
Loss from equity affiliates	25	84	0
Exploratory dry hole costs	410	301	344
Exploration lease impairment	182	207	245
Stock compensation expense	97	87	60
Provision (benefit) for deferred income taxes	(1,319)	270	(427)
(Income) loss from discontinued operations, net of income taxes	48	(682)	(1,186)
Changes in operating assets and liabilities
(Increase) decrease in accounts receivable	841	(199)	(239)
(Increase) decrease in inventories	29	62	134
Increase (decrease) in accounts payable and accrued liabilities	(424)	79	(375)
Increase (decrease) in taxes payable	(222)	(108)	(435)
Changes in operating assets and liabilities	(164)	(372)	(209)
Cash provided by (used in) operating activities - continuing operations	2,016	4,504	3,936
Cash provided by (used in) operating activities - discontinued operations	(35)	(47)	1,162
Net cash provided by (used in) operating activities	1,981	4,457	5,098
Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P	(3,956)	(4,867)	(5,413)
Additions to property, plant and equipment - Bakken Midstream	(365)	(347)	(524)
Proceeds from asset sales	50	2,978	4,458
Other, net	(44)	(192)	(285)
Cash provided by (used in) investing activities - continuing operations	(4,315)	(2,428)	(1,764)
Cash provided by (used in) investing activities - discontinued operations	109	2,436	2,114
Net cash provided by (used in) investing activities	(4,206)	8	350
Cash Flows From Financing Activities
Net borrowings (repayments) of debt with maturities of 90 days or less	0	0	(1,748)
Debt with maturities of greater than 90 days – Borrowings	710	598	535
Debt with maturities of greater than 90 days – Repayments	(67)	(590)	(1,271)
Common stock acquired and retired	(142)	(3,715)	(1,493)
Cash dividends paid	(287)	(303)	(235)
Employee stock options exercised, including income tax benefits	12	182	128
Noncontrolling interests, net	2,296	0	(182)
Other, net	(25)	0	0
Cash provided by (used in) financing activities - continuing operations	2,497	(3,828)	(4,266)
Cash provided by (used in) financing activities - discontinued operations	0	(7)	(10)
Net cash provided by (used in) financing activities	2,497	(3,835)	(4,276)
Net Increase (Decrease) In Cash and Cash Equivalents	272	630	1,172
Cash and Cash Equivalents at Beginning of Year	2,444	1,814	642
Cash and Cash Equivalents at End of Year	$ 2,716	$ 2,444	$ 1,814

Statement of Consolidated Equit

Statement of Consolidated Equity - USD ($) $ in Millions	Total	Common Stock	Capital in Excess of Par	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Total Hess Stockholders' Equity	Noncontrolling Interests
Beginning balance at Dec. 31, 2012	$ 21,203	$ 342	$ 3,524	$ 17,717	$ (493)	$ 21,090	$ 113
Net Income (Loss)	5,222			5,052		5,052	170
Other comprehensive income (loss)	161				155	155	6
Activity related to restricted common stock awards, net	33	1	32			33
Employee stock options, including income tax benefits	139	2	137			139
Performance share units	10		10			10
Common stock acquired and retired	(1,538)	(20)	(205)	(1,313)		(1,538)
Cash dividends declared	(235)			(235)		(235)
Noncontrolling interests, net	(211)			14		14	(225)
Ending balance at Dec. 31, 2013	24,784	325	3,498	21,235	(338)	24,720	64
Net Income (Loss)	2,374			2,317		2,317	57
Other comprehensive income (loss)	(1,072)				(1,072)	(1,072)
Activity related to restricted common stock awards, net	61	1	60			61
Employee stock options, including income tax benefits	185	3	182			185
Performance share units	19		19			19
Common stock acquired and retired	(3,722)	(43)	(482)	(3,197)		(3,722)
Cash dividends declared	(303)			(303)		(303)
Noncontrolling interests, net	(6)						(6)
Ending balance at Dec. 31, 2014	22,320	286	3,277	20,052	(1,410)	22,205	115
Net Income (Loss)	(3,007)			(3,056)		(3,056)	49
Other comprehensive income (loss)	(254)				(254)	(254)
Activity related to restricted common stock awards, net	67	1	66			67
Employee stock options, including income tax benefits	15		15			15
Performance share units	24		24			24
Common stock acquired and retired	(91)	(1)	(18)	(72)		(91)
Cash dividends declared	(287)			(287)		(287)
Formation of Bakken Midstream joint venture	2,061		763			763	1,298
Noncontrolling interests, net	(447)						(447)
Ending balance at Dec. 31, 2015	$ 20,401	$ 286	$ 4,127	$ 16,637	$ (1,664)	$ 19,386	$ 1,015

Nature of Operations, Basis of

Nature of Operations, Basis of Presentation and Summary of Accounting Policies	12 Months Ended
	Dec. 31, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Nature of Operations, Basis of Presentation and Summary of Accounting Policies	1. Nature of Operations, Basis of Presentation and Summary of Accounting Policies Unless the context indicates otherwise, references to “Hess”, “the Corporation”, “Registrant”, “we”, “us” and “our” refer to the consolidated business operations of Hess Corporation and its affiliates. Nature of Business: Hess Corporation is a global Exploration and Production (E&P) company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located primarily in the United States (U.S.), Denmark, Equatorial Guinea, the Joint Development Area of Malaysia/Thailand (JDA), Malaysia, and Norway. The Bakken Midstream operating segment, which was established in the second quarter of 2015, provides fee-based services, including crude oil and natural gas gathering, processing of natural gas and the fractionation of natural gas liquids, transportation of crude oil by rail car, terminaling and loading crude oil and natural gas liquids, and the storage and terminaling of propane, primarily located in the Bakken shale play of North Dakota. In the first quarter of 2013, we announced several initiatives to continue our transformation from an integrated energy company into a more geographically focused pure play E&P company. As part of our transformation, we sold mature or lower margin E&P assets in Algeria, Azerbaijan, Indonesia, Russia, Thailand, the United Kingdom (UK) North Sea, and certain interests onshore in the U.S. In addition, the transformation plan included fully exiting our Marketing and Refining (M&R) business, including our terminal, retail, energy marketing and energy trading operations, as well as the permanent shutdown of refining operations at our Port Reading facility. HOVENSA L.L.C. (HOVENSA), a 50/50 joint venture between the Corporation’s subsidiary, Hess Oil Virgin Islands Corp. (HOVIC), and Petroleos de Venezuela S.A. (PDVSA), had previously shut down its U.S. Virgin Islands refinery in 2012. HOVENSA filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in the United States District Court of the Virgin Islands in September 2015. In January 2016, Limetree Bay Terminals, LLC (Limetree) purchased the terminal and refinery assets of the St. Croix Facility and HOVENSA will conduct an orderly wind-down of its remaining activities. See Note 3, Discontinued Operations Note 9, Dispositions Note 19, Guarantees, Contingencies and Commitments Note 23, Subsequent Events Basis of Presentation and Principles of Consolidation: The consolidated financial statements include the accounts of Hess Corporation and entities in which we own more than a 50% voting interest. We also consolidate Hess Infrastructure Partners LP (HIP), a variable interest entity, based on our conclusion that we have the power through our 50% ownership to direct those activities that most significantly impact the economic performance of HIP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to HIP. Our undivided interests in unincorporated oil and gas exploration and production ventures are proportionately consolidated. Investments in affiliated companies, 20% to 50% owned and where we have the ability to influence the operating or financial decisions of the affiliate, are accounted for using the equity method. In November 2015, the Financial Accounting Standards Board (FASB) issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes Statement of Financial Position , we have adopted the update Note 20, Segment Information Estimates and Assumptions: In preparing financial statements in conformity with U.S. generally accepted accounting principles (GAAP), management makes estimates and assumptions that affect the reported amounts of assets and liabilities in the Consolidated Balance Sheet and revenues and expenses in the Statement of Consolidated Income . Actual results could differ from those estimates. Estimates made by management include oil and gas reserves, asset and other valuations, depreciable lives, pension liabilities, legal and environmental obligations, asset retirement obligations and income taxes. Revenue Recognition: The E&P segment recognizes revenue from the sale of crude oil, natural gas liquids, and natural gas, when title passes to the customer. Differences between E&P natural gas volumes sold and our entitlement share of natural gas production are not material. In our E&P activities, we engage in crude oil purchase and sale transactions with the same counterparty that are entered into in contemplation of one another for the primary purpose of changing location or quality. These arrangements are reported net in Sales and other operating revenues in the Statement of Consolidated Income Our Bakken Midstream segment recognizes revenue from fee-based services including crude oil and natural gas gathering, processing of natural gas and the fractionation of natural gas liquids, terminaling and loading crude oil and natural gas liquids, transportation of crude oil by rail car and the storage and terminaling of propane when pervasive evidence of an arrangement exists, delivery has occurred or services rendered, price is fixed or determinable, and collectability is reasonably assured. Prior to 2014, when providing natural gas processing services, our Bakken Midstream operating segment purchased unprocessed natural gas from us and third parties and provided processing services pursuant to contracts whereby it retained a portion of the sales proceeds received and charged certain fees to customers. The remaining proceeds were remitted back to customers based on the contractual arrangements. Exploration and Development Costs: E&P activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized. In production operations, costs of injected CO 2 for tertiary recovery are expensed as incurred. The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of a project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors, firm plans for additional drilling and other factors. Depreciation, Depletion and Amortization: We record depletion expense for acquisition costs of proved properties using the units of production method over proved oil and gas reserves. Depreciation and depletion expense for oil and gas production facilities and wells is calculated using the units of production method over proved developed oil and gas reserves. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors. Depreciation of all other plant and equipment is determined on the straight-line method based on estimated useful lives. Capitalized Interest: Interest from external borrowings is capitalized on material projects using the weighted average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at first production from the field. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying assets. Impairment of Long‑lived Assets: We review long‑lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts of the long-lived assets are not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is determined based on the estimated fair value of the assets generally determined by discounting anticipated future net cash flows, an income valuation approach, or by a market‑based valuation approach, which are Level 3 fair value measurements. In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a projected amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows, since the standardized measure requires the use of historical twelve month average prices. As a result of the prevailing low crude oil price environment, we tested our oil and gas properties for impairment at December 31, 2015. See Note 10, Impairment . Impairment of Goodwill: Goodwill is tested for impairment annually on October 1 st Note 10, Impairment. Cash and Cash Equivalents: Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have maturities of three months or less when acquired. Inventories: Inventories are valued at the lower of cost or market. Cost is generally determined using average actual costs. Income Taxes: Deferred income taxes are determined using the liability method. We have net operating loss carryforwards or credit carryforwards in multiple jurisdictions and have recorded deferred tax assets for those losses and credits. Additionally, we have deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount that is expected to be realized. In evaluating the realizability of deferred tax assets, we consider the reversal of temporary differences, the expected utilization of net operating losses and credit carryforwards during available carryforward periods, the availability of tax planning strategies, the existence of appreciated assets and estimates of future taxable income and other factors. In addition, we recognize the financial statement effect of a tax position only when management believes that it is more likely than not, that based on the technical merits, the position will be sustained upon examination. We do not provide for deferred U.S. income taxes for that portion of undistributed earnings of foreign subsidiaries that are indefinitely reinvested in foreign operations. We classify interest and penalties associated with uncertain tax positions as income tax expense. Asset Retirement Obligations: We have material legal obligations to remove and dismantle long‑lived assets and to restore land or the seabed at certain exploration and production locations. We initially recognize a liability for the fair value of legally required asset retirement obligations in the period in which the retirement obligations are incurred, and capitalize the associated asset retirement costs as part of the carrying amount of the long‑lived assets. In subsequent periods, the liability is accreted, and the asset is depreciated over the useful life of the related asset. Fair value is determined by applying a credit adjusted risk-free rate to the undiscounted expected future abandonment expenditures, which represent Level 3 inputs in the fair value hierarchy defined under Fair Value Measurements below. Retirement Plans: We recognize the funded status of defined benefit postretirement plans in the Consolidated Balance Sheet . The funded status is measured as the difference between the fair value of plan assets and the projected benefit obligation. We recognize the net changes in the funded status of these plans in the year in which such changes occur. Prior service costs and actuarial gains and losses in excess of 10% of the greater of the benefit obligation or the market value of assets are amortized over the average remaining service period of active employees. Derivatives: We utilize derivative instruments for financial risk management activities. In these activities, we may use futures, forwards, options and swaps, individually or in combination, to mitigate our exposure to fluctuations in prices of crude oil and natural gas, as well as changes in interest and foreign currency exchange rates. All derivative instruments are recorded at fair value in our Consolidated Balance Sheet Fair Value Measurements: We use various valuation approaches in determining fair value for financial instruments, including the market and income approaches. Our fair value measurements also include non-performance risk and time value of money considerations. Counterparty credit is considered for receivable balances, and our credit is considered for accrued liabilities. We also record certain nonfinancial assets and liabilities at fair value when required by GAAP. These fair value measurements are recorded in connection with business combinations, qualifying nonmonetary exchanges, the initial recognition of asset retirement obligations and any impairment of long‑lived assets, equity method investments or goodwill. We determine fair value in accordance with the fair value measurements accounting standard which established a hierarchy for the inputs used to measure fair value based on the source of the inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3), including discounted cash flows and other unobservable data. Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market. Multiple inputs may be used to measure fair value; however, the level of fair value for each physical derivative and financial asset or liability is based on the lowest significant input level within this fair value hierarchy. Details on the methods and assumptions used to determine the fair values are as follows: Fair value measurements based on Level 1 inputs: Measurements that are most observable are based on quoted prices of identical instruments obtained from the principal markets in which they are traded. Closing prices are both readily available and representative of fair value. Market transactions occur with sufficient frequency and volume to assure liquidity. Fair value measurements based on Level 2 inputs: Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. Measurements based on Level 2 inputs include over-the-counter derivative instruments that are priced on an exchange traded curve, but have contractual terms that are not identical to exchange traded contracts. Fair value measurements based on Level 3 inputs: Measurements that are least observable are estimated from related market data, determined from sources with little or no market activity for comparable contracts or are positions with longer durations. Fair values determined using discounted cash flows and other unobservable data are also classified as Level 3. Netting of Financial Instruments: We generally enter into master netting arrangements to mitigate legal and counterparty credit risk. Master netting arrangements are generally accepted overarching master contracts that govern all individual transactions with the same counterparty entity as a single legally enforceable agreement. The U.S. Bankruptcy Code provides for the enforcement of certain termination and netting rights under certain types of contracts upon the bankruptcy filing of a counterparty, commonly known as the “safe harbor” provisions. If a master netting arrangement provides for termination and netting upon the counterparty’s bankruptcy, these rights are generally enforceable with respect to “safe harbor” transactions. If these arrangements provide the right of offset and our intent and practice is to offset amounts in the case of such a termination, our policy is to record the fair value of derivative assets and liabilities on a net basis. In the normal course of business we rely on legal and credit risk mitigation clauses providing for adequate credit assurance as well as close‑out netting, including two‑party netting and single counterparty multilateral netting. As applied to us, “two‑party netting” is the right to net amounts owing under safe harbor transactions between a single defaulting counterparty entity and a single Hess entity, and “single counterparty multilateral netting” is the right to net amounts owing under safe harbor transactions among a single defaulting counterparty entity and multiple Hess entities. We are reasonably assured that these netting rights would be upheld in a bankruptcy proceeding in the U.S. in which the defaulting counterparty is a debtor under the U.S. Bankruptcy Code. Share-based Compensation: We account for share-based compensation under the fair value method of accounting. The fair value of all share‑based compensation is recognized as expense on a straight‑line basis over the full vesting period of the awards. We estimate the fair value of employee stock options at the date of grant using a Black‑Scholes valuation model, performance share units using a Monte Carlo simulation model, and restricted stock based on the market value of the underlying shares at the date of grant. Foreign Currency Translation: The U.S. Dollar is the functional currency (primary currency in which business is conducted) for most foreign operations. Adjustments resulting from remeasuring monetary assets and liabilities that are denominated in a currency other than the functional currency are recorded in Other, net in the Statement of Consolidated Income . For operations that do not use the U.S. Dollar as the functional currency, primarily those in Norway where the Norwegian Krone is used, adjustments resulting from translating foreign currency assets and liabilities into U.S. Dollars are recorded in the Consolidated Balance Sheet in a separate component of equity titled Accumulated other comprehensive income (loss). Maintenance and Repairs: Maintenance and repairs are expensed as incurred. Capital improvements are recorded as additions in Property, plant and equipment. Environmental Expenditures: We accrue and expense the undiscounted environmental costs necessary to remediate existing conditions related to past operations when the future costs are probable and reasonably estimable. At year‑end 2015, our reserve for estimated remediation liabilities was approximately $80 million and was included within accrued liabilities. Environmental expenditures that increase the life or efficiency of property or reduce or prevent future adverse impacts to the environment are capitalized. New Accounting Pronouncements: In May 2014, the FASB issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers , as a new Accounting Standards Codification (ASC) Topic ASC 606. This ASU is effective for us beginning in the first quarter of 2018 , with early adoption permitted from the first quarter of 2017. We are currently assessing the impact of the ASU on our consolidated financial statements. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes Consolidated Balance Sheet

Bakken Midstream Joint Venture

Bakken Midstream Joint Venture	12 Months Ended
	Dec. 31, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Bakken Midstream Joint Venture	2. Bakken Midstream Joint Venture On July 1, 2015 we sold a 50% interest in Hess Infrastructure Partners LP (HIP) to Global Infrastructure Partners (GIP) for net cash consideration of approximately $2.6 billion. HIP and its affiliates primarily comprise our Bakken Midstream operating segment which provides fee-based services including crude oil and natural gas gathering, processing of natural gas and the fractionation of natural gas liquids, terminaling and loading crude oil and natural gas liquids, transportation of crude oil by rail car and the storage and terminaling of propane, primarily located in the Bakken shale play of North Dakota. The Bakken Midstream operating segment currently generates substantially all of its revenues under long-term, fee-based agreements with our E&P operating segment and intends to pursue additional throughput volumes from third parties in the Williston Basin area. We operate the Bakken Midstream assets and operations, including routine and emergency maintenance and repair services under various operational and administrative services agreements. The tariff agreements between our E&P operating segment and the Bakken Midstream entities became effective on January 1, 2014 and are 10-year, fee-based commercial agreements, with HIP having the sole option to renew the agreements for an additional 10-year term. These agreements include minimum volume commitments based on dedicated production, inflation escalators and fee recalculation mechanisms. The Bakken Midstream segment has minimal direct commodity price exposure, and the E&P segment retains ownership of the crude oil, natural gas or natural gas liquids processed, terminaled, stored or transported by the Bakken Midstream segment. We consolidate the activities of HIP, which qualifies as a variable interest entity (VIE) under U.S. generally accepted accounting principles. We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power, through our 50% ownership, to direct those activities that most significantly impact the economic performance of HIP. This conclusion was based on a qualitative analysis that considered HIP’s governance structure, the commercial agreements between HIP and us, and the voting rights established between the members which provide us the ability to control the operations of HIP. As a result of the sale to GIP, we recorded an after-tax gain of $763 million in additional paid-in-capital and $1,298 million in noncontrolling interest representing GIP’s proportional share of our basis in the net assets of HIP. The results attributable to GIP’s 50% ownership are reported within Net income (loss) attributable to noncontrolling interests in the Statement of Consolidated Income Consolidated Balance Sheet Upon formation, the joint venture incurred $600 million of debt through a 5-year Term Loan A facility with the proceeds distributed equally to the partners. See Note 8, Debt

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2015
Discontinued Operations And Disposal Groups [Abstract]
Discontinued Operations	3. Discontinued Operations The results of operations for our divested Marketing and Refining businesses included ownership of the energy trading partnership through February 2015, retail marketing through September 2014, terminals through December 2013, energy marketing through November 2013 and Port Reading refining activities through the date they were permanently shut down in February 2013, and have been reported as discontinued operations in the Statement of Consolidated Income Sales and other operating revenues and Income from discontinued operations were as follows: 2015 2014 2013 (In millions) Sales and other operating revenues $ 14 $ 9,576 $ 22,652 Income (loss) from discontinued operations before income taxes $ (74 ) $ 1,071 $ 1,835 Current tax provision (benefit) — — — Deferred tax provision (benefit) (26 ) 389 649 Provision (benefit) for income taxes (26 ) 389 649 Income (loss) from discontinued operations, net of income taxes $ (48 ) $ 682 $ 1,186 Less: Net income (loss) attributable to noncontrolling interests — 57 (6 ) Income (loss) from discontinued operations attributable to Hess Corporation $ (48 ) $ 625 $ 1,192 2015: In February 2015, we sold our interest in HETCO, which was subsequently renamed Hartree Partners, LP (Hartree). Pursuant to the terms of the sale, Hartree was permitted to utilize our guarantees issued in favor of Hartree's existing counterparties until November 12, 2015, provided that new trades were for a period of one year or less, complied with certain credit requirements, and net exposures remained within value at risk limits previously applied by us. The guarantees remain in effect until the qualifying trades outstanding at November 12, 2015 mature. We have the right to seek reimbursement from Hartree and a separate Hartree credit support facility upon any counterparty draw on the applicable guarantee from us. No draws on the guaranteed trades have occurred through December 31, 2015. A liability of $10 million associated with the guarantee is included in Other accrued liabilities at December 31, 2015. At December 31, 2014, HETCO assets totaling $1,035 million, consisting of accounts receivable and other long-lived assets, were reported in Other current assets, and liabilities totaling $797 million, which consisted primarily of accounts payable, were reported in Accrued Liabilities in the Consolidated Balance Sheet . 2014: In September, we completed the sale of our retail business for cash proceeds of approximately $2.8 billion. This transaction resulted in a pre-tax gain of $954 million ($602 million after income taxes) after deducting the net book value of assets, including $115 million of goodwill. During the year, we recorded pre-tax gains of $275 million ($171 million after income taxes) relating to the liquidation of last-in, first-out (LIFO) inventories associated with the divested downstream operations. In addition, we recorded pre-tax charges totaling $308 million ($202 million after income taxes) for impairments, environmental matters, severance and exit related activities associated with the divestiture of downstream operations. We also recognized a pre-tax charge of $115 million ($72 million after income taxes) related to the termination of lease contracts and the purchase of 180 retail gasoline stations in preparation for the sale of the retail operations. In January, our retail business acquired our partners’ 56% interest in WilcoHess, a retail gasoline joint venture, for approximately $290 million and the settlement of liabilities. In connection with this business combination, we recorded a pre-tax gain of $39 million ($24 million after income taxes) to remeasure the carrying value of our original 44% equity interest in WilcoHess to fair value, including recognition of goodwill in the amount of $115 million. The assets and liabilities acquired from WilcoHess were included in the sale of the retail business in September 2014. 2013: In December, we sold our U.S. East Coast terminal network, St. Lucia terminal and related businesses for cash proceeds of approximately $1.0 billion. The transaction resulted in a pre-tax gain of $739 million ($531 million after income taxes). In November, we sold our energy marketing business for cash proceeds of approximately $1.2 billion, which resulted in a pre-tax gain of $761 million ($464 million after income taxes). During the year we recognized pre-tax gains of $678 million ($414 million after income taxes) relating to the liquidation of LIFO inventories. In addition, we recorded pre-tax charges totaling $523 million ($334 million after income taxes) for impairments, severance, Port Reading refinery shutdown costs, environmental matters, and exit related activities associated with the divestiture of downstream operations.

Inventories

Inventories	12 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Inventories	4. Inventories Inventories at December 31 were as follows: 2015 2014 (In millions) Crude oil and natural gas liquids $ 144 $ 246 Materials and supplies 255 281 Total inventories $ 399 $ 527

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2015
Property Plant And Equipment [Abstract]
Property, Plant and Equipment	5. Property, Plant and Equipment Property, plant and equipment at December 31 were as follows: 2015 2014 (In millions) Exploration and Production Unproved properties $ 958 $ 1,468 Proved properties 4,202 4,211 Wells, equipment and related facilities 38,738 38,263 43,898 43,942 Bakken Midstream 2,757 2,386 Corporate, Interest and Other 171 194 Total — at cost 46,826 46,522 Less: Reserves for depreciation, depletion, amortization and lease impairment 20,474 19,005 Property, plant and equipment — net $ 26,352 $ 27,517 Capitalized Exploratory Well Costs : The following table discloses the amount of capitalized exploratory well costs pending determination of proved reserves at December 31, and the changes therein during the respective years: 2015 2014 2013 (In millions) Balance at January 1 $ 1,416 $ 2,045 $ 2,259 Additions to capitalized exploratory well costs pending the determination of proved reserves 424 292 237 Reclassifications to wells, facilities and equipment based on the determination of proved reserves (72 ) (629 ) (106 ) Capitalized exploratory well costs charged to expense (356 ) (235 ) (267 ) Dispositions and other 3 (57 ) (78 ) Ending balance at December 31 $ 1,415 $ 1,416 $ 2,045 Number of wells at end of year 35 37 50 In 2015, exploratory drilling activity primarily related to the Gulf of Mexico and the offshore Stabroek license in Guyana. For the years ended December 31, 2015, 2014 and 2013, reclassifications to wells, facilities and equipment based on the determination of proved reserves primarily related to Equatorial Guinea, the Stampede project in the Gulf of Mexico, (which the co-owners sanctioned for development in 2014) and the Shenzi project in the Gulf of Mexico, respectively. In 2015, capitalized exploratory well costs charged to expense related to the Dinarta Block in the Kurdistan Region of Iraq resulting from our and our partners’ decision to cease further drilling and relinquish the block, gas discoveries offshore Ghana that have not sufficiently progressed appraisal negotiations with the regulator, and three wells with discovered resources offshore Australia that we determined will not be included in the current development concept for the Equus project. In 2014 capitalized well costs charged to expense included a previously capitalized exploration well in Green Canyon Block 469 in the Gulf of Mexico where it was determined no further development activities were planned, and in 2013, two previously capitalized exploration wells in Area 54, offshore Libya, were expensed due to civil unrest in the country. The preceding table excludes exploratory dry hole costs of $54 million (2014: $66 million; 2013: $77 million), which were incurred and subsequently expensed in the same year. Exploratory well costs capitalized for greater than one year following completion of drilling were $1,053 million at December 31, 2015, separated by year of completion as follows (in millions): 2014 $ 79 2013 43 2012 336 2011 207 2010 and prior 388 $ 1,053 Approximately 75% of the capitalized well costs in excess of one year relates to Block WA-390-P, offshore Western Australia, where development planning and commercial activities for our natural gas discoveries are ongoing. In December 2014, we executed a non-binding letter of intent with the North West Shelf (NWS), a third-party joint venture with existing natural gas processing and liquefaction facilities. In 2015, we initiated joint front-end engineering studies with NWS and we also commenced discussions with potential long-term purchasers of liquefied natural gas. In addition, at our adjacent WA-474-P Block which could become part of the Equus project, we plan to drill a commitment well in 2016. Successful execution of binding agreements with NWS is necessary before we can execute a gas sales agreement and sanction development of the project. Approximately 25% of the capitalized well costs in excess of one year relates to offshore Ghana. Appraisal plans for the seven discoveries on the block were submitted to the Ghanaian government in May 2013 for approval. Five of the plans were approved and discussions continue with the government on the two remaining appraisal plans. In 2014, we completed three appraisal wells and subsurface evaluation, and development planning progressed in 2015. The government of Côte d’Ivoire has challenged the maritime border between it and the country of Ghana, which includes a portion of our Deepwater Tano/Cape Three Points license. We are unable to proceed with development of this license until there is a resolution of this matter, which may also impact our ability to develop the license. The International Tribunal for Law of the Sea is expected to render a final ruling on the maritime border dispute in 2017. Under terms of our license, the deadline to declare commerciality for the Pecan Field, which would be the primary development hub for the block, is in March 2016, and the deadline to submit a plan of development is in September 2016. We have requested an extension of the submission deadline for a plan of development for the Pecan Field, and will continue to work with the government on how best to progress work on the block given the maritime border dispute.

Goodwill

Goodwill	12 Months Ended
	Dec. 31, 2015
Goodwill And Intangible Assets Disclosure [Abstract]
Goodwill	6. Goodwill The changes in the carrying amount of goodwill were as follows: Exploration and Production Bakken Midstream Total (In millions) Beginning balance at January 1, 2014 $ 1,869 $ — $ 1,869 Acquisitions 115 — 115 Dispositions (126 ) — (126 ) Balance at December 31, 2014 1,858 — 1,858 Reclassification (375 ) 375 — Impairment (1,483 ) — (1,483 ) Ending balance at December 31, 2015 $ — $ 375 $ 375 In the second quarter of 2015, we established a new operating segment, the Bakken Midstream segment which had previously been reported as part of the Onshore reporting unit within the E&P operating segment. The E&P operating segment previously had two reporting units, Offshore which had allocated goodwill of $1,098 million and Onshore which had allocated goodwill of $760 million prior to forming the Bakken Midstream operating segment. Upon formation of the Bakken Midstream operating segment, we allocated $375 million of goodwill from the Onshore reporting unit to the Bakken Midstream operating segment based on the relative fair values of the Bakken Midstream business and the remainder of the Onshore reporting unit. There was no change to the composition of the Offshore reporting unit. See Note 10, Impairment The acquired goodwill in 2014 resulted from the purchase of our partners’ 56% interest in WilcoHess, which was subsequently disposed of as part of the sale of our retail marketing operations. See Note 3, Discontinued Operations .

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	7. Asset Retirement Obligations The following table describes changes to our asset retirement obligations: 2015 2014 (In millions) Asset retirement obligations at beginning of period $ 2,723 $ 2,772 Liabilities incurred 57 63 Liabilities settled or disposed of (360 ) (420 ) Accretion expense 126 136 Revisions of estimated liabilities 92 263 Foreign currency translation (255 ) (91 ) Asset retirement obligations at end of period 2,383 2,723 Less: Current obligations 225 442 Long-term obligations at end of period $ 2,158 $ 2,281 The liabilities settled or disposed of related primarily to abandonment activities conducted at the Valhall field offshore Norway and at formerly operated fields in the U.K. North Sea. The revisions in 2015 and 2014 primarily reflect changes in the expected scope of operations and updates to service and equipment costs.

Debt

Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt	8. Debt Long‑term debt at December 31 consisted of the following: 2015 2014 (In millions) Debt excluding Bakken Midstream: Fixed-rate public notes: 1.3% due 2017 $ 300 $ 300 8.1% due 2019 999 999 3.5% due 2024 298 298 7.9% due 2029 696 696 7.3% due 2031 747 747 7.1% due 2033 598 598 6.0% due 2040 745 745 5.6% due 2041 1,242 1,242 Total fixed-rate public notes 5,625 5,625 Financing obligations associated with floating production system 264 331 Fair value adjustments - interest rate hedging 31 31 Total debt excluding Bakken Midstream $ 5,920 $ 5,987 Debt related to Bakken Midstream: Bakken Midstream - term loan A facility $ 600 $ — Bakken Midstream - revolving credit facility 110 — Total debt related to Bakken Midstream $ 710 $ — Total long-term debt: Total debt (a) (b) $ 6,630 $ 5,987 Less: Current maturities of long-term debt 86 68 Total long-term debt $ 6,544 $ 5,919 (a) At December 31, 2015 the fair value of total debt amounted to $6,515 million (2014: $7,003 million ). (b) The In January 2015, we entered into a new $4 billion syndicated revolving credit facility that expires in January 2020. The new facility, which replaced a $4 billion facility that was scheduled to expire in April 2016, can be used for borrowings and letters of credit. Based on our credit rating as of December 31, 2015, borrowing on the facility will generally bear interest at 1.075% above the London Interbank Offered Rate (LIBOR) with the facility fee amounting to 0.175% per annum. The interest rate and facility fee are subject to adjustment if our credit rating changes. At December 31, 2015, there were no borrowings outstanding or letters of credit issued against the syndicated revolving credit facility. In June 2014, we issued $600 million of unsecured, fixed-rate notes ($598 million net of discount) comprising $300 million with a coupon of 1.3% and scheduled to mature in June 2017 as well as $300 million with a coupon of 3.5% and scheduled to mature in July 2024. In 2014, we repaid $590 million of debt, including $250 million of unsecured, fixed-rate notes, $249 million for the payment of various lease obligations primarily to retire retail gasoline station leases and $74 million assumed in the acquisition of WilcoHess. In 2015 we capitalized $45 million of interest (2014: $76 million; 2013: $60 million). At December 31, 2015, and 2014, our fixed-rate public notes had a principal amount of $5,650 million ($5,625 million net of unamortized discount) with a weighted average interest rate 6.4%. Our long‑term debt agreements, including the revolving credit facility, contain financial covenants that restrict the amount of total borrowings and secured debt. The most restrictive of these covenants allow us to borrow up to an additional $5,495 million of secured debt at December 31, 2015. In July 2015, HIP, a 50/50 joint venture between us and GIP, incurred $600 million of debt through a 5-year Term Loan A facility. The proceeds from the debt were distributed equally to the partners. HIP also entered into a $400 million 5-year syndicated revolving credit facility, which can be used for borrowings and letters of credit, and is expected to fund the joint venture’s operating activities and capital expenditures. Borrowings on both loan facilities generally bear interest at LIBOR plus an applicable margin ranging from 1.10% to 2.00%. Facility fees on the revolving credit facility accrue at an applicable rate every quarter, ranging from 0.15% to 0.35% per annum. Prior to obtaining credit ratings, applicable interest margins and facility fees are based on the joint venture’s leverage ratio, which is calculated as total debt to Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA). If the joint venture obtains credit ratings, pricing levels will be based on its credit ratings in effect from time to time. The joint venture is subject to customary covenants in the credit agreement, including financial covenants that generally require a leverage ratio of no more than 5.0 to 1.0 for the prior four fiscal quarters and an interest coverage ratio, which is calculated as EBITDA to interest expense, of no less than 2.25 to 1.0 for the prior four fiscal quarters. At December 31, 2015, borrowings attributable to the joint venture, which are non-recourse to Hess Corporation, amounted to $600 million on the Term Loan A loan facility and $110 million on the revolving credit facility. HIP is in compliance with all debt covenants at December 31, 2015, and its financial covenants do not currently impact their ability to issue indebtedness to fund future capital expenditures. Outstanding letters of credit at December 31 were as follows: 2015 2014 (In millions) Committed lines (a) $ 10 $ 25 Uncommitted lines (a) 103 372 Total (b) $ 113 $ 397 (a) At December 31, 2015, committed and uncommitted lines have expiration dates through 2016. (b) At December 31, 2015, $32 million relates to contingent liabilities and $81 million relates to liabilities recorded in the Consolidated Balance Sheet (2014: $54 million and $343 million, respectively).

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2015
Disposition Of Businesses [Abstract]
Dispositions	9. Dispositions 2015: In December, we completed the disposition of our interest in Algeria and recognized a pre-tax loss of $21 million ($21 million after income taxes), and sold land associated with our former joint venture interest in the Bayonne Energy Center for $20 million, resulting in a pre-tax gain of $20 million ($13 million after income taxes). In the third quarter of 2015, we completed the sale of approximately 13,000 acres of Utica dry gas acreage for a sale price of approximately $120 million. This transaction resulted in a pre-tax gain of $49 million ($31 million after income taxes). 2014: In January, we completed the sale of our interest in the Pangkah asset, offshore Indonesia for cash proceeds of approximately $650 million, which resulted in a pre-tax gain of $31 million ($10 million loss after income taxes). In April, we completed the sale of our interests in Thailand for cash proceeds of approximately $805 million, which resulted in a pre-tax gain of $706 million ($706 million after income taxes). In the first six months of 2014, we completed the sale of approximately 77,000 net acres in the dry gas area of the Utica shale play including related wells and facilities through multiple transactions, for cash proceeds of $1,075 million and recorded a pre-tax gain of $62 million ($35 million gain after income taxes). In June, we completed the sale of our joint venture interest in an electric generating facility in Newark, New Jersey for cash proceeds of $320 million, resulting in a pre-tax gain of approximately $13 million ($8 million after income taxes). In September, we sold our joint venture interest in Bayonne Energy Center for $79 million, which did not result in a gain or loss. Also in September, we completed the sale of our interest in an exploration asset in the United Kingdom North Sea for $53 million, which resulted in a pre-tax gain of $33 million ($33 million after income taxes). 2013: In January, we completed the sale of our interests in the Beryl fields and the Scottish Area Gas Evacuation System in the UK North Sea for cash proceeds of $442 million; this transaction resulted in a pre‑tax gain of $328 million ($323 million after income taxes). In March, we sold our interests in the Azeri‑Chirag‑Guneshli fields, offshore Azerbaijan in the Caspian Sea, and the associated Baku‑Tbilisi‑Ceyhan (BTC) oil transportation pipeline company for cash proceeds of $884 million; this transaction resulted in a pre‑tax gain of $360 million ($360 million after income taxes). In April, we completed the sale of our Russian subsidiary, Samara-Nafta, for cash proceeds of $2.1 billion; based on our 90% interest in Samara-Nafta, after-tax proceeds to Hess were approximately $1.9 billion. This transaction resulted in a pre-tax gain of $1,119 million ($1,119 million after income taxes), which was reduced by $168 million for the noncontrolling interest holder’s share of the gain, resulting in a net gain attributable to us of $951 million. In December, we completed the sale of our interest in the Natuna A Field, offshore Indonesia for total cash proceeds of approximately $656 million; this transaction resulted in a pre‑tax gain of $388 million ($343 million after income taxes).

Impairment

Impairment	12 Months Ended
	Dec. 31, 2015
Asset Impairment Charges [Abstract]
Impairment	10. Impairment In 2015, we recorded pre-tax goodwill impairment charges totaling $1,483 million ($1,483 million after income taxes). As a result of establishing the Bakken Midstream operating segment in the second quarter of 2015, (see Note 6, Goodwill As a result of declining commodity prices, in 2015 we also recognized an impairment charge of $133 million pre-tax ($83 million after income taxes) relating to our conventional legacy assets in North Dakota based projected discounted cash flows, using similar Level 3 inputs to those discussed above. In 2013, we announced the sale of our E&P assets in Indonesia for approximately $1.3 billion. The sale was executed in two separate transactions, with Natuna A completing in December 2013 and Pangkah in January 2014, as a result of a partner exercising their preemptive rights. Based on the sales proceeds for each transaction, results of operations for 2013 included a pre‑tax gain on sale related to Natuna A of $388 million ($343 million after income taxes), and a pre‑tax asset impairment charge of $289 million ($187 million after income taxes) to adjust the carrying value of the Pangkah assets to their fair value at December 31, 2013.

Share-based Compensation

Share-based Compensation	12 Months Ended
	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Share-based Compensation	11. Share-based Compensation We have established and maintain a Long-term Incentive Plan (LTIP), as amended, for the granting of restricted common shares, performance share units (PSUs) and stock options to our employees. As of December 31, 2015, the total number of authorized common stock under LTIP, as amended, was 38.0 million shares, of which we have 14.2 million shares available for issuance. Outstanding restricted stock and PSUs generally vest three years from the date of grant. Restricted common shares are valued based on the prevailing market price of our common stock on the date of grant. Outstanding stock options vest over three years from the date of grant and have a 10‑year term and an exercise price equal to the market price on the date of grant. The number of shares of common stock to be issued under the PSU agreement is based on a comparison of the Corporation’s total shareholder return (TSR) to the TSR of a predetermined group of peer companies over a three‑year performance period ending December 31 of the year prior to settlement of the grant. Payouts of the performance share awards will range from 0% to 200% of the target awards based on the Corporation’s TSR ranking within the peer group. Dividend equivalents for the performance period will accrue on performance shares, but will only be paid out on earned shares after the performance period. Share‑based compensation expense consisted of the following: Before Income Taxes After Income Taxes 2015 2014 2013 (b) 2015 2014 2013 (In millions) Restricted stock $ 67 $ 62 $ 31 $ 42 $ 39 $ 19 Stock options 5 2 13 3 1 8 Performance share units 25 19 10 16 12 6 Total (a) $ 97 $ 83 $ 54 $ 61 $ 52 $ 33 (a) Includes pre‑tax share‑based compensation expense included in Income from continuing operations of approximately $97 million, $87 million and $60 million for 2015, 2014 and 2013, respectively. (b) Reflects the reversal of $33 million ($25 million for restricted stock, $7 million for PSUs and $1 million for stock options) in compensation expense for grants that were not expected to vest as a result of our transformation to a pure play E&P company. Based on share‑based compensation awards outstanding at December 31, 2015, unearned compensation expense, before income taxes, will be recognized in future years as follows (in millions): 2016—$73, 2017—$42 and 2018—$6. Share‑based compensation activity consisted of the following: Performance Share Units Stock Options Restricted Stock Performance Share Units Weighted - Average Fair Value on Date of Grant Options Weighted - Average Exercise Price per Share Shares of Restricted Common Stock Weighted - Average Price on Date of Grant (In thousands, except per share amounts) Outstanding at January 1, 2015 800 $ 89.91 6,766 $ 66.79 2,901 $ 71.58 Granted 366 76.64 521 74.49 1,131 74.38 Exercised — — (244 ) 48.51 — — Vested (288 ) 72.93 — — (921 ) 63.63 Forfeited (58 ) 97.16 (132 ) 79.29 (291 ) 71.39 Outstanding at December 31, 2015 820 $ 89.43 6,911 $ 67.77 2,820 $ 75.32 As of December 31, 2015, there were 6.91 million outstanding stock options (6.31 million exercisable) with a weighted average remaining contractual life of 3.5 years (3.0 years for exercisable options). The weighted average exercise price for options exercisable at December 31, 2015 was $67.03 per share. The following weighted average assumptions were utilized to estimate the fair value of stock options: 2015 2014 2013 Risk free interest rate 1.77 % 1.86 % — Stock price volatility 0.312 0.363 — Dividend yield 1.34 % 1.24 % — Expected life in years 6.0 6.0 — Weighted average fair value per option granted $ 21.00 $ 26.46 — The following weighted average assumptions were utilized to estimate the fair value of PSU awards: 2015 2014 2013 Risk free interest rate 1.02 % 0.65 % 0.36 % Stock price volatility 0.270 0.359 0.359 Contractual term in years 3.0 3.0 3.0 Grant date price of Hess common stock $ 74.49 $ 80.35 $ 69.49 The risk free interest rate is based on the vesting period of the award and is obtained from published sources. The stock price volatility is determined from the historical stock prices of the peer group using the vesting period. The contractual term is equivalent to the vesting period.

Retirement Plans

Retirement Plans	12 Months Ended
	Dec. 31, 2015
Compensation And Retirement Disclosure [Abstract]
Retirement Plans	12. Retirement Plans We have funded noncontributory defined benefit pension plans for a significant portion of our employees. In addition, we have an unfunded supplemental pension plan covering certain employees, which provides incremental payments that would have been payable from our principal pension plans, were it not for limitations imposed by income tax regulations. The plans provide defined benefits based on years of service and final average salary. Additionally, we maintain an unfunded postretirement medical plan that provides health benefits to certain qualified retirees from ages 55 through 65. The measurement date for all retirement plans is December 31. The following table summarizes the benefit obligations, the fair value of plan assets, and the funded status of our pension and postretirement medical plans: Funded Unfunded Postretirement Pension Plans Pension Plan Medical Plan 2015 2014 2015 2014 2015 2014 (In millions) Change in benefit obligation Balance at January 1 $ 2,450 $ 1,957 $ 278 $ 253 $ 94 $ 97 Service cost 51 45 16 12 4 4 Interest cost 93 91 9 9 3 3 Actuarial (gain) loss (a) (156 ) 470 (2 ) 61 5 (4 ) Benefit payments (b) (85 ) (77 ) (42 ) (57 ) (8 ) (6 ) Plan curtailments (4 ) (3 ) — — — — Special termination benefits 1 2 — — — — Foreign currency exchange rate changes (29 ) (35 ) — — — — Balance at December 31 2,321 2,450 259 278 98 94 Change in fair value of plan assets Balance at January 1 $ 2,251 $ 2,145 $ — $ — $ — $ — Actual return on plan assets 28 151 — — — — Employer contributions 44 68 42 57 8 6 Benefit payments (b) (85 ) (77 ) (42 ) (57 ) (8 ) (6 ) Foreign currency exchange rate changes (32 ) (36 ) — — — — Balance at December 31 2,206 2,251 — — — — Funded status (plan assets greater (less) than benefit obligations) at December 31 $ (115 ) $ (199 ) $ (259 ) $ (278 ) $ (98 ) $ (94 ) Unrecognized net actuarial (gains) losses 775 859 105 135 — (5 ) (a) The change in discount rate and mortality assumptions in 2014 resulted in total actuarial losses of approximately $330 million and $125 million, respectively. (b) Benefit payments include lump-sum settlement payments of $41 million in 2015 and $55 million in 2014. Amounts recognized in the Consolidated Balance Sheet at December 31 consisted of the following: Funded Unfunded Postretirement Pension Plans Pension Plan Medical Plan 2015 2014 2015 2014 2015 2014 (In millions) Pension asset / (accrued benefit liability) $ (115 ) $ (199 ) $ (259 ) $ (278 ) $ (98 ) $ (94 ) Accumulated other comprehensive loss, pre-tax (a) 775 859 105 135 — (5 ) (a) The after‑tax deficit reflected in Accumulated other comprehensive income (loss) was $563 million at December 31, 2015 (2014: $652 million). At December 31, 2015, the accumulated benefit obligation for the funded and unfunded defined benefit pension plans was $2,223 million and $196 million, respectively (2014: $2,325 million and $214 million, respectively). The net periodic benefit cost for funded and unfunded pension plans, and the postretirement medical plan, is as follows: Pension Plans Postretirement Medical Plan 2015 2014 2013 2015 2014 2013 (In millions) Service cost $ 67 $ 57 $ 73 $ 4 $ 4 $ 4 Interest cost 102 100 89 3 3 3 Expected return on plan assets (168 ) (161 ) (141 ) — — — Amortization of unrecognized net actuarial losses 75 32 61 — — 1 Settlement loss 17 24 — — — — Curtailment loss — — 1 — — — Special termination benefit recognized 1 1 5 — — — Net periodic benefit cost $ 94 $ 53 $ 88 $ 7 $ 7 $ 8 For 2016, the pension and postretirement medical expense is estimated to be approximately $71 million, which includes approximately $64 million related to the amortization of unrecognized net actuarial losses. The weighted average actuarial assumptions used for funded and unfunded pension plans were as follows: 2015 2014 2013 Weighted average assumptions used to determine benefit obligations at December 31 Discount rate 4.1 % 3.8 % 4.6 % Rate of compensation increase 4.5 % 5.0 % 4.4 % Weighted average assumptions used to determine net periodic benefit cost for the years ended December 31 Discount rate 3.8 % 4.6 % 4.0 % Expected return on plan assets 7.5 % 7.5 % 7.5 % Rate of compensation increase 5.0 % 4.4 % 4.3 % The actuarial assumptions used for postretirement medical plan, as follows: 2015 2014 2013 Assumptions used to determine benefit obligations at December 31 Discount rate 3.5 % 3.1 % 3.6 % Initial health care trend rate 6.7 % 6.8 % 7.1 % Ultimate trend rate 4.5 % 4.5 % 4.6 % Year in which ultimate trend rate is reached 2038 2029 2027 The assumptions used to determine net periodic benefit cost for each year were established at the end of each previous year while the assumptions used to determine benefit obligations were established at each year‑end. The net periodic benefit cost and the actuarial present value of benefit obligations are based on actuarial assumptions that are reviewed on an annual basis. The discount rate is developed based on a portfolio of high‑quality, fixed income debt instruments with maturities that approximate the expected payment of plan obligations. The overall expected return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of pension assets to that asset category. Our investment strategy is to maximize long‑term returns at an acceptable level of risk through broad diversification of plan assets in a variety of asset classes. Asset classes and target allocations are determined by our investment committee and include domestic and foreign equities, fixed income, and other investments, including hedge funds, real estate and private equity. Investment managers are prohibited from investing in securities issued by the Corporation unless indirectly held as part of an index strategy. The majority of plan assets are highly liquid, providing ample liquidity for benefit payment requirements. The current target allocations for plan assets are 50% equity securities, 25% fixed income securities (including cash and short‑term investment funds) and 25% to all other types of investments. Asset allocations are rebalanced on a periodic basis throughout the year to bring assets to within an acceptable range of target levels. The following tables provide the fair value of the financial assets of the funded pension plans as of December 31, 2015 and 2014 in accordance with the fair value measurement hierarchy described in Note 1, Nature of Operations, Basis of Presentation and Summary of Accounting Policies Level 1 Level 2 Level 3 Total (In millions) December 31, 2015 Cash and short-term investment funds $ — $ 34 $ — $ 34 Equities: U.S. equities (domestic) 556 — — 556 International equities (non-U.S.) 159 266 — 425 Global equities (domestic and non-U.S.) 2 217 — 219 Fixed income: Treasury and government issued (a) — 213 — 213 Government related (b) — 6 1 7 Mortgage-backed securities (c) — 174 2 176 Corporate — 157 — 157 Other: Hedge funds — — 216 216 Private equity funds — — 122 122 Real estate funds 12 — 52 64 Diversified commodities funds — 17 — 17 $ 729 $ 1,084 $ 393 $ 2,206 December 31, 2014 Cash and short-term investment funds $ 6 $ 47 $ — $ 53 Equities: U.S. equities (domestic) 719 — — 719 International equities (non-U.S.) 72 177 — 249 Global equities (domestic and non-U.S.) 10 218 — 228 Fixed income: Treasury and government issued (a) — 222 — 222 Government related (b) — 7 1 8 Mortgage-backed securities (c) — 147 1 148 Corporate 3 137 — 140 Other: Hedge funds — — 302 302 Private equity funds — — 105 105 Real estate funds 12 — 48 60 Diversified commodities funds — 17 — 17 $ 822 $ 972 $ 457 $ 2,251 (a) Includes securities issued and guaranteed by U.S. and non‑U.S. governments. (b) Primarily consists of securities issued by governmental agencies and municipalities. (c) Comprised of U.S. residential and commercial mortgage-backed securities. Cash and short‑term investment funds consist of cash on hand and short-term investment funds that provide for daily investments and redemptions and are valued and carried at a $1 net asset value (NAV) per fund share. Cash on hand is classified as Level 1 and short‑term investment funds are classified as Level 2. Equities consist of equity securities issued by U.S. and non‑U.S. corporations as well as commingled investment funds that invest in equity securities. Individually held equity securities, which are traded actively on exchanges and have readily available price quotes, are classified as Level 1. Commingled fund values, which are valued at the NAV per fund share derived from the quoted prices in active markets of the underlying securities, are classified as Level 2. Fixed income investments consist of securities issued by the U.S. government, non‑U.S. governments, governmental agencies, municipalities and corporations, and agency and non-agency mortgage‑backed securities. This investment category also includes commingled investment funds that invest in fixed income securities. Individual fixed income securities are generally priced on the basis of evaluated prices from independent pricing services, which are monitored and provided by the third-party custodial firm responsible for safekeeping plan assets. Individual fixed income securities are classified as Level 2 or 3. Fixed income commingled fund values, which reflect the NAV per fund share derived indirectly from observable inputs or from quoted prices in less liquid markets of the underlying securities, are classified as Level 2. Other investments consist of exchange‑traded real estate investment trust securities, as well as commingled fund and limited partnership investments in hedge funds, private equity, real estate and diversified commodities. Exchange‑traded securities are classified as Level 1. Commingled fund values reflect the NAV per fund share and are classified as Level 2 or 3. Private equity and real estate limited partnership values reflect information reported by the fund managers, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data and independent appraisals from third‑party sources with professional qualifications. Hedge funds, private equity and non‑exchange‑traded real estate investments are classified as Level 3. The following tables provide changes in financial assets that are measured at fair value based on Level 3 inputs that are held by institutional funds classified as: Private Real Fixed Hedge Equity Estate Income Funds Funds Funds Total (In millions) Balance at January 1, 2014 $ 3 $ 291 $ 89 $ 47 $ 430 Actual return on plan assets — 9 15 — 24 Purchases, sales or other settlements (1 ) 2 1 1 3 Net transfers in (out) of Level 3 — — — — — Balance at December 31, 2014 2 302 105 48 457 Actual return on plan assets — (5 ) 18 9 22 Purchases, sales or other settlements 1 (81 ) (1 ) (5 ) (86 ) Net transfers in (out) of Level 3 — — — — — Balance at December 31, 2015 $ 3 $ 216 $ 122 $ 52 $ 393 We expect to contribute approximately $27 million to our funded pension plans in 2016. Estimated future benefit payments by the funded and unfunded pension plans, and the postretirement medical plan, which reflect expected future service, are as follows (in millions): 2016 $ 111 2017 117 2018 120 2019 129 2020 134 Years 2021 to 2025 711 We also have several defined contribution plans for certain eligible employees. Employees may contribute a portion of their compensation to these plans and we match a portion of the employee contributions. We recorded expense of $28 million in 2015 for contributions to these plans (2014: $32 million; 2013: $41 million). In February 2016, we assumed the HOVENSA pension plan as per the court approved settlement of the HOVENSA Liquidation Plan. See Note 23, Subsequent Events

Exit and Disposal Costs

Exit and Disposal Costs	12 Months Ended
	Dec. 31, 2015
Restructuring And Related Activities [Abstract]
Exit and Disposal Costs	13. Exit and Disposal Costs In 2015, we incurred severance expense of $13 million (2014: $76 million; 2013: $252 million) and paid accrued severance costs of $57 million (2014: $170 million; 2013: $81 million). The employee severance charges primarily resulted from our divestiture program announced in 2013. The severance charges were based on amounts incurred under ongoing severance arrangements or other statutory requirements, plus amounts earned under enhanced benefit arrangements. The expense associated with the enhanced benefits was recognized ratably over the estimated service period required for the employee to earn the benefit upon termination. In 2015, we recorded exit related costs of $15 million (2014: $65 million; 2013: $220 million) and paid $21 million (2014: $158 million; 2013: $102 million) for accrued facility and other exit costs. The facility and other exit costs relate to charges associated with the cessation of use of certain leased office space, contract terminations, professional fees, and costs associated with the shutdown of Port Reading refining operations. At December 31, 2015, we have accrued liabilities of $33 million (2014: $77 million) for severance and $19 million (2014: $25 million) for exit related costs. We expect to make all payments for severance in 2016, and to pay facility and exit cost through 2027.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	14. Income Taxes The provision (benefit) for income taxes from continuing operations consisted of: 2015 2014 2013 (In millions) United States Federal Current $ (7 ) $ (1 ) $ 8 Deferred (995 ) 156 103 State (61 ) 57 9 (1,063 ) 212 120 Foreign Current 4 453 941 Deferred (231 ) 79 186 (227 ) 532 1,127 Total (1,290 ) 744 1,247 Adjustment of deferred taxes for foreign income tax law changes (a) (9 ) — (682 ) Total provision (benefit) for income taxes $ (1,299 ) $ 744 $ 565 (a) The reported amount for 2015 reflects $9 million for the effect of a change in Norway’s hydrocarbon and base corporate income tax rates in December 2015. The reported amount for 2013 reflects $674 million for the effect of the Denmark hydrocarbon income tax law change to the Chapter 3A regime in December 2013 and $8 million for the effect of a change in Norway’s hydrocarbon and base corporate income tax rates in December 2013. Income (loss) from continuing operations before income taxes consisted of the following: 2015 2014 2013 (In millions) United States (a) $ (2,728 ) $ 676 $ 580 Foreign (1,530 ) 1,760 4,021 Total income (loss) from continuing operations before income taxes $ (4,258 ) $ 2,436 $ 4,601 (a) Includes substantially all of our interest expense, corporate expense and the results of commodity hedging activities. The components of deferred tax liabilities and deferred tax assets at December 31 were as follows: 2015 2014 (In millions) Deferred tax liabilities Property, plant and equipment and investments (a) $ (3,743 ) $ (4,226 ) Other (257 ) (269 ) Total deferred tax liabilities (4,000 ) (4,495 ) Deferred tax assets Net operating loss carryforwards 3,852 3,010 Tax credit carryforwards 188 193 Property, plant and equipment and investments (a) 981 1,110 Accrued compensation, deferred credits and other liabilities 492 449 Asset retirement obligations 1,220 1,421 Other 165 261 Total deferred tax assets 6,898 6,444 Valuation allowances (1,579 ) (1,416 ) Total deferred tax assets, net of valuation allowances 5,319 5,028 Net deferred tax assets $ 1,319 $ 533 (a) 2014 has been adjusted to conform to the 2015 presentation. At December 31, 2015, we have recognized a gross deferred tax asset related to net operating loss carryforwards of $3,852 million before application of valuation allowances. The deferred tax asset is comprised of $2,245 million attributable to foreign net operating losses which begin to expire in 2025, $1,394 million attributable to U.S. federal operating losses which begin to expire in 2020 and $213 million attributable to losses in various U.S. states which begin to expire in 2016. The deferred tax asset attributable to foreign net operating losses, net of valuation allowances, is $1,631 million, substantially all of which relates to loss carryforwards in Denmark, Norway and Malaysia. The deferred tax asset attributable to federal net operating losses, net of valuation allowances, is $1,394 million. The deferred tax asset attributable to state net operating losses, net of valuation allowances, is $63 million, substantially all of which relates to North Dakota. At December 31, 2015, we have federal, state and foreign alternative minimum tax credit carryforwards of $102 million which can be carried forward indefinitely, and approximately $1 million of other business credit carryforwards. The deferred tax asset attributable to these credits, net of valuation allowances is $54 million. A full valuation allowance is established against our foreign tax credit carryforwards of $85 million which begin to expire in 2016. In the Consolidated Balance Sheet 2015 2014 (In millions) Deferred income taxes (long-term asset) $ 2,653 $ 2,371 Deferred income taxes (long-term liability) (1,334 ) (1,838 ) Net deferred tax assets $ 1,319 $ 533 The difference between our effective income tax rate from continuing operations and the U.S. statutory rate is reconciled below: 2015 2014 2013 U.S. statutory rate 35.0 % 35.0 % 35.0 % Effect of foreign operations (a)(b) 5.9 0.7 5.9 State income taxes, net of Federal income tax 0.9 1.5 0.1 Change in enacted tax laws 0.2 — (14.8 ) Gains on asset sales, net (0.2 ) (8.3 ) (15.6 ) Goodwill impairment (12.2 ) — — Valuation allowance against previously benefitted deferred tax assets (a) (3.1 ) 0.6 1.0 Benefit of legal entity restructuring 3.5 — — Other (a) 0.5 1.0 0.7 Total 30.5 % 30.5 % 12.3 % (a) 2014 and 2013 have been adjusted to conform to the 2015 presentation. (b) The variance in effective income tax rates attributable to the effect of foreign operations primarily resulted from the mix of income among high and low tax rate jurisdictions. Below is a reconciliation of the gross beginning and ending amounts of unrecognized tax benefits: 2015 2014 (In millions) Balance at January 1 $ 603 $ 570 Additions based on tax positions taken in the current year 19 42 Additions based on tax positions of prior years 29 70 Reductions based on tax positions of prior years (31) (76) Reductions due to settlements with taxing authorities (12) (3) Reductions due to lapses in statutes of limitation (4) — Balance at December 31 $ 604 $ 603 The December 31, 2015 balance of unrecognized tax benefits includes $529 million that, if recognized, would impact our effective income tax rate. Over the next 12 months, it is reasonably possible that the total amount of unrecognized tax benefits could decrease between $109 million to $161 million due to settlements with taxing authorities or other resolutions, as well as lapses in statutes of limitation. At December 31, 2015, our accrued interest and penalties related to unrecognized tax benefits is $74 million (2014: $62 million). We have not recognized deferred income taxes on the portion of undistributed earnings of foreign subsidiaries expected to be indefinitely reinvested in foreign operations. At December 31, 2015, we have undistributed earnings from foreign subsidiaries, which we expect to be indefinitely reinvested in foreign operations, of approximately $7.7 billion. We have not measured the unrecognized deferred tax liability related to these earnings because this determination is not practicable. We file income tax returns in the U.S. and various foreign jurisdictions. We are no longer subject to examinations by income tax authorities in most jurisdictions for years prior to 2005.

Outstanding and Weighted Averag

Outstanding and Weighted Average Common Shares	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Outstanding and Weighted Average Common Shares	15. Outstanding and Weighted Average Common Shares The following table provides the changes in our outstanding common shares: 2015 2014 2013 (In millions) Balance at January 1 285.8 325.3 341.5 Activity related to restricted common stock awards, net 0.8 0.6 0.8 Stock options exercised 0.2 3.3 2.3 PSU vested 0.6 — — Shares repurchased (a) (1.4 ) (43.4 ) (19.3 ) Balance at December 31 286.0 285.8 325.3 (a) See Note 17, Share Repurchase Plan. The following table presents the calculation of basic and diluted earnings per share: 2015 2014 2013 (In millions) Income (loss) from continuing operations, net of income taxes $ (2,959 ) $ 1,692 $ 4,036 Less: Net income (loss) attributable to noncontrolling interests 49 — 176 Net income (loss) from continuing operations attributable to Hess Corporation (3,008 ) 1,692 3,860 Income from discontinued operations, net of income taxes (48 ) 682 1,186 Less: Net income (loss) attributable to noncontrolling interests — 57 (6 ) Net income from discontinued operations attributable Hess Corporation (48 ) 625 1,192 Net income (loss) attributable to Hess Corporation $ (3,056 ) $ 2,317 $ 5,052 Weighted average common shares outstanding: Basic 283.6 303.7 336.6 Effect of dilutive securities Restricted common stock — 1.5 1.4 Stock options — 1.8 1.7 Performance share units — 0.7 1.2 Diluted 283.6 307.7 340.9 Net income (loss) attributable to Hess Corporation per share: Basic: Continuing operations $ (10.61 ) $ 5.57 $ 11.47 Discontinued operations (0.17 ) 2.06 3.54 Net income (loss) per share $ (10.78 ) $ 7.63 $ 15.01 Diluted: Continuing operations $ (10.61 ) $ 5.50 $ 11.33 Discontinued operations (0.17 ) 2.03 3.49 Net income (loss) per share $ (10.78 ) $ 7.53 $ 14.82 The weighted average common shares used in the diluted earnings per share calculations excluded the effect of approximately 6.9 million stock options, 2.9 million restricted stock awards and 1.0 million PSUs from calculating diluted shares as those are anti-dilutive. We excluded 1.4 million of stock options in 2014 (2013: 4.4 million) from calculating weighted average shares used in the diluted earnings per share, because their effect would be anti-dilutive. In 2015 and 2014, cash dividends declared on common stock totaled $1.00 per share ($0.25 per quarter). In 2013, cash dividends declared on common stock totaled $0.70 per share ($0.10 per share for the first two quarters and $0.25 per share commencing in the third quarter of 2013).

Supplementary Cash Flow Informa

Supplementary Cash Flow Information	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Supplementary Cash Flow Information	16. Supplementary Cash Flow Information The following information supplements the Statement of Consolidated Cash Flows 2015 2014 2013 (In millions) Cash Flows From Operating Activities Interest paid $ (331 ) $ (326 ) $ (408 ) Income taxes paid, net of refunds (140 ) (455 ) (1,353 ) Cash Flows From Investing Activities Capital expenditures incurred - E&P (3,753 ) (4,920 ) (5,174 ) Increase (decrease) in related liabilities (203 ) 53 (239 ) Additions to property, plant and equipment - E&P (3,956 ) (4,867 ) (5,413 ) Capital expenditures incurred - Bakken Midstream (296 ) (301 ) (535 ) Increase (decrease) in related liabilities (69 ) (46 ) 11 Additions to property, plant and equipment - Bakken Midstream (365 ) (347 ) (524 ) Cash Flows From Financing Activities Contribution from formation of Bakken Midstream joint venture 2,628 — — Distributions to partner in Bakken Midstream joint venture (332 ) — — Noncontrolling interests, net related to Continuing operations 2,296 — — Significant Non-Cash Transactions Increase in debt due to construction of a floating production system - Tubular Bells Field $ — $ 68 $ 116

Share Repurchase Plan

Share Repurchase Plan	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Share Repurchase Plan	17. Share Repurchase Plan In 2013, our Board of Directors authorized the repurchase of up to $4.0 billion in aggregate purchase price of our common stock. In May 2014, the Board of Directors approved an increase in the program to $6.5 billion. Repurchases under this program were as follows: 2015 2014 2013 To Date (In millions, except cost per share) Total cost of shares repurchased $ 91 $ 3,722 $ 1,538 $ 5,351 Total number of shares repurchased 1.45 43.35 19.31 64.11 Average cost per share (including transaction fees) $ 62.76 $ 85.83 $ 79.65 $ 83.45 As of December 31, 2015, we are authorized but not required to purchase additional common stock up to a value of $1.15 billion.

Leased Assets

Leased Assets	12 Months Ended
	Dec. 31, 2015
Leases [Abstract]
Leased Assets	18. Leased Assets We and certain of our subsidiaries lease drilling rigs, tankers, office space and other assets for varying periods under contractual obligations accounted for as operating leases. Operating lease expenses for drilling rigs used to drill development wells and successful exploration wells are capitalized. At December 31, 2015, future minimum rental payments applicable to non‑cancelable operating leases with remaining terms of one year or more (other than oil and gas property leases) are as follows (in millions): 2016 $ 674 2017 524 2018 401 2019 366 2020 107 Remaining years 373 Total minimum lease payments 2,445 Less: Income from subleases 85 Net minimum lease payments $ 2,360 Rental expense was as follows: 2015 2014 2013 (In millions) Total rental expense $ 167 $ 248 $ 355 Less: Income from subleases 10 17 15 Net rental expense $ 157 $ 231 $ 340

Guarantees, Contingencies and C

Guarantees, Contingencies and Commitments	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Guarantees, Contingencies and Commitments	19. Guarantees, Contingencies and Commitments Guarantees and Contingencies At December 31, 2015, we have $32 million in letters of credit for which we are contingently liable. In addition, we are subject to loss contingencies with respect to various claims, lawsuits and other proceedings. A liability is recognized in our consolidated financial statements when it is probable that a loss has been incurred and the amount can be reasonably estimated. If the risk of loss is probable, but the amount cannot be reasonably estimated or the risk of loss is only reasonably possible, a liability is not accrued; however, we disclose the nature of those contingencies. We cannot predict with certainty if, how or when existing claims, lawsuits and proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages. Numerous issues may need to be resolved, including through lengthy discovery, conciliation and/or arbitration proceedings, or litigation before a loss or range of loss can be reasonably estimated. Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of such lawsuits, claims and proceedings, including the matters described below, is not expected to have a material adverse effect on our financial condition. However, we could incur judgments, enter into settlements or revise our opinion regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations in the period in which the amounts are accrued and our cash flows in the period in which the amounts are paid. In May 2005, the government of the U.S. Virgin Islands filed a complaint in the District Court of the Virgin Islands against HOVENSA LLC (“HOVENSA”), a 50/50 joint venture between our subsidiary, Hess Oil Virgin Islands Corp. (“HOVIC”), and a subsidiary of Petroleos de Venezuela S.A. (PDVSA), and other companies that operated industrial facilities on the south shore of St. Croix asserting that the defendants are liable under the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and territorial statutory and common law for damages to natural resources. In 2014, HOVIC, HOVENSA and the government of the U.S. Virgin Islands entered into a settlement agreement pursuant to which HOVENSA paid $3.5 million and agreed to pay the government of the U.S. Virgin Islands an additional $40 million no later than December 31, 2014. On September 15, 2015, HOVENSA filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States District Court of the Virgin Islands - Bankruptcy Division (the “Bankruptcy Court”) and commenced a court-supervised sale of substantially all of its assets pursuant to section 363 of the Bankruptcy Code. To fund HOVENSA's sale process and orderly wind-down, HOVENSA entered into a $40 million debtor-in-possession credit facility with HOVENSA’s owners, the terms of which were approved by the Bankruptcy Court. On December 1, 2015, the Bankruptcy Court entered an order approving the sale of HOVENSA’s terminal and refinery assets to Limetree Bay Terminals, LLC (“Limetree”). The Senate of the U.S. Virgin Islands approved the sale on December 29, 2015, and the sale to Limetree was completed on January 4, 2016. The $40 million claim held by the U.S. Virgin Islands government against HOVENSA on account of the 2014 settlement agreement was also paid from the sale proceeds. On January 19, 2016, the Bankruptcy Court entered an order confirming HOVENSA’s Chapter 11 plan of liquidation (the “Liquidation Plan”). Under the Liquidation Plan, HOVENSA established a liquidating trust to distribute certain assets and sale proceeds to its creditors, established an environmental response trust to administer to HOVENSA’s remaining environmental obligations and will conduct an orderly wind-down of its remaining activities. The Liquidation Plan also provides for releases of any claims held by HOVENSA and its bankruptcy estate against us and HOVIC, and releases any claims held by certain third-party creditors of HOVENSA against us and HOVIC both effective upon the effective date of the Liquidation Plan. In connection with the Liquidation Plan and HOVENSA’s asset sale, HOVIC relinquished its claims against HOVENSA on account of the promissory notes issued by HOVENSA to HOVIC. On September 13, 2015, the government of the U.S. Virgin Islands filed a complaint against us in the territorial Superior Court of the Virgin Islands, Division of St. Croix, alleging, among other things, that we violated territorial statutes and committed various torts in connection with the 50% ownership interest of our subsidiary, HOVIC, in HOVENSA. In connection with the closing of HOVENSA’s asset sale to Limetree, we, the government of the U.S. Virgin Islands, HOVIC, HOVENSA, and PDVSA entered into a mutual release agreement that resulted in the dismissal, with prejudice, of all pending litigation among those parties, including the lawsuit filed by the government of the U.S. Virgin Islands against us and various tax refund lawsuits filed by HOVIC and PDVSA against the government of the U.S. Virgin Islands. As part of this agreement, the government of the U.S. Virgin Islands also granted us, HOVIC, and HOVENSA a general release of all other existing claims, with the exception of claims related to environmental matters, which were released upon the establishment of the environmental response trust in connection with the Liquidation Plan. In February 2015, the Pension Benefit Guaranty Corporation (PBGC) issued a notice of determination to terminate the HOVENSA pension plan. In connection with the HOVENSA’s sale to Limetree and the Liquidation Plan, the Corporation assumed the HOVENSA pension plan upon the effective date of the Liquidation Plan and PBGC withdrew its notice of determination. In 2015, we recorded a charge of $30 million primarily representing the estimated net difference between the HOVENSA pension plan obligation and fair value of the plan assets. On July 25, 2011, the Virgin Islands Department of Planning and Natural Resources commenced an enforcement action against HOVENSA by issuance of documents titled “Notice Of Violation, Order For Corrective Action, Notice Of Assessment of Civil Penalty, Notice Of Opportunity For Hearing” (the “NOVs”). The NOVs assert violations of Virgin Islands’ Air Pollution Control laws and regulations arising out of odor incidents on St. Croix in May 2011 and proposed total penalties of $210,000. We expect that any penalties arising from this matter will be covered by the liquidating trust established under the Liquidation Plan. We, along with many companies engaged in refining and marketing of gasoline, have been a party to lawsuits and claims related to the use of methyl tertiary butyl ether (MTBE) in gasoline. A series of similar lawsuits, many involving water utilities or governmental entities, were filed in jurisdictions across the U.S. against producers of MTBE and petroleum refiners who produced gasoline containing MTBE, including us. The principal allegation in all cases was that gasoline containing MTBE is a defective product and that these parties are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE. The majority of the cases asserted against us have been settled. In June 2014, the Commonwealth of Pennsylvania and the State of Vermont each filed independent lawsuits alleging that we and all major oil companies with operations in each respective state, have damaged the groundwater in those states by introducing thereto gasoline with MTBE. The Pennsylvania suit has been removed to Federal court and has been forwarded to the existing MTBE multidistrict litigation pending in the Southern District of New York. The suit filed in Vermont is proceeding there in a state court. An action brought by the Commonwealth of Puerto Rico was settled in conjunction with the Bankruptcy Court’s confirmation of HOVENSA’s Liquidation Plan. We received a directive from the New Jersey Department of Environmental Protection (NJDEP) to remediate contamination in the sediments of the lower Passaic River and the NJDEP is also seeking natural resource damages. The directive, insofar as it affects us, relates to alleged releases from a petroleum bulk storage terminal in Newark, New Jersey we previously owned. We and over 70 companies entered into an Administrative Order on Consent with the Environmental Protection Agency (EPA) to study the same contamination; this work remains ongoing. We and other parties settled a cost recovery claim by the State of New Jersey and also agreed with EPA to fund remediation of a portion of the site. The EPA is continuing to study contamination and remedial designs for other portions of the River. To that end, in April 2014 EPA issued a Focused Feasibility Study (“FFS”) proposing to conduct bank-to-bank dredging of the lower eight miles of the Passaic River at an estimated cost of $1.7 billion. EPA may issue a Record of Decision (“ROD”) in 2016 selecting a remedy for the lower eight miles based on the FFS, but the ultimate remedy (and associated cost) for the lower Passaic River remains uncertain at this stage. The ROD is unlikely to address an additional nine miles of the Passaic River, which may require additional remedial action. In addition, the federal trustees for natural resources have begun a separate assessment of damages to natural resources in the Passaic River. Given the ongoing studies and the fact that EPA has not yet selected a remedy for part or all of the lower Passaic River, remedial costs cannot be reliably estimated at this time. In March 2014, we received an Administrative Order from EPA requiring us and 26 other parties to undertake the Remedial Design for the remedy selected by the EPA for the Gowanus Canal Superfund Site in Brooklyn, New York. The remedy includes dredging of surface sediments and the placement of a cap over the deeper sediments throughout the Canal and in-situ stabilization of certain contaminated sediments that will remain in place below the cap. EPA has estimated that this remedy will cost $506 million; however, the ultimate costs that will be incurred in connection with the design and implementation of the remedy remain uncertain. Our alleged liability derives from our former ownership and operation of a fuel oil terminal adjacent to the Canal. We indicated to EPA that we would comply with the Administrative Order and are currently contributing funding for the Remedial Design based on an interim allocation of costs among the parties. At the same time, we are participating in an allocation process whereby neutral experts selected by the parties will determine the final shares of the Remedial Design costs to be paid by each of the participants. The parties have not yet addressed the allocation of costs associated with implementing the remedy that is currently being designed. From time to time, we are involved in other judicial and administrative proceedings, including proceedings relating to other environmental matters. We cannot predict with certainty if, how or when such proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages. Numerous issues may need to be resolved, including through potentially lengthy discovery and determination of important factual matters before a loss or range of loss can be reasonably estimated for any proceeding. Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of such proceedings is not expected to have a material adverse effect on our financial condition, results of operations or cash flows. Unconditional Purchase Obligations and Commitments The following table shows aggregate information for certain unconditional purchase obligations and commitments at December 31, 2015 which are not included elsewhere within these Consolidated Financial Statements Payments Due by Period 2017 and 2019 and Total 2016 2018 2020 Thereafter (In millions) Capital expenditures $ 1,750 $ 1,503 $ 247 $ — $ — Operating expenses 548 384 108 32 24 Transportation and related contracts 1,598 121 453 433 591

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Segment Information	20. Segment Information We currently have two operating segments, Exploration and Production and Bakken Midstream. The Exploration and Production operating segment explores for, develops, produces, purchases and sells crude oil, natural gas liquids and natural gas with production operations primarily in the United States (U.S.), Denmark, Equatorial Guinea, the Joint Development Area of Malaysia/Thailand (JDA), Malaysia, and Norway. The Bakken Midstream operating segment provides fee-based services including crude oil and natural gas gathering, processing of natural gas and the fractionation of natural gas liquids, terminaling and loading crude oil and natural gas liquids, transportation of crude oil by rail car and the storage and terminaling of propane, primarily located in the Bakken shale play of North Dakota. All unallocated costs are reflected under Corporate, Interest and Other. The following table presents operating segment financial data for continuing operations (in millions): 2015 Exploration and Production Bakken Midstream Corporate, Interest and Other Eliminations Total Operating Revenues - Third parties $ 6,636 $ — $ — $ — $ 6,636 Intersegment Revenues — 564 — (564 ) — Operating Revenues $ 6,636 $ 564 $ — $ (564 ) $ 6,636 Net income (loss) from continuing operations attributable to Hess Corporation $ (2,717 ) $ 86 $ (377 ) $ — $ (3,008 ) Interest expense — 10 331 — 341 Depreciation, depletion and amortization 3,852 88 15 — 3,955 Impairment 1,616 — — — 1,616 Provision (benefit) for income taxes (1,111 ) 52 (240 ) — (1,299 ) Investment in affiliates 154 — — — 154 Identifiable assets 28,863 2,761 2,571 — 34,195 Capital Expenditures 3,753 296 — — 4,049 2014 Exploration and Production Bakken Midstream Corporate, Interest and Other Eliminations Total Operating Revenues - Third parties $ 10,737 $ — $ — $ — $ 10,737 Intersegment Revenues — 319 — (319 ) — Operating Revenues $ 10,737 $ 319 $ — $ (319 ) $ 10,737 Net income (loss) from continuing operations attributable to Hess Corporation $ 2,086 $ 10 $ (404 ) $ — $ 1,692 Interest expense — 2 321 — 323 Depreciation, depletion and amortization 3,140 70 14 — 3,224 Provision (benefit) for income taxes 989 7 (252 ) — 744 Investment in affiliates 151 — — — 151 Identifiable assets 32,742 2,465 2,042 — 37,249 Capital Expenditures 4,920 301 53 — 5,274 2013 Exploration and Production Bakken Midstream Corporate, Interest and Other Eliminations Total Operating Revenues - Third parties $ 11,762 $ 143 $ — $ — $ 11,905 Intersegment Revenues 125 127 — (252 ) — Operating Revenues $ 11,887 $ 270 $ — $ (252 ) $ 11,905 Net income (loss) from continuing operations attributable to Hess Corporation $ 4,439 $ (136 ) $ (443 ) $ — $ 3,860 Interest Expense — — 406 — 406 Depreciation, depletion and amortization 2,638 33 16 — 2,687 Impairment 289 — — — 289 Provision (benefit) for income taxes 912 (81 ) (266 ) — 565 Investment in affiliates 109 — 397 — 506 Capital Expenditures 5,174 535 58 — 5,767 The following table presents financial information by major geographic area: United States Europe Africa Asia and Other Countries Corporate, Interest and other Total (In millions) 2015 Operating revenues $ 4,150 $ 870 $ 945 $ 671 $ — $ 6,636 Net income (loss) from continuing operations attributable to Hess Corporation (1,834 ) (408 ) (274 ) (115 ) (377 ) (3,008 ) Depreciation, depletion and amortization 2,449 635 539 317 15 3,955 Impairments 986 279 100 251 — 1,616 Provision (benefit) for income taxes (522 ) (84 ) (48 ) (405 ) (240 ) (1,299 ) Identifiable assets 18,372 6,207 2,178 4,867 2,571 34,195 Property, plant and equipment (net) (a) 15,729 5,300 1,682 3,520 121 26,352 Capital expenditures 2,727 297 160 865 — 4,049 2014 Operating revenues $ 6,270 $ 1,557 $ 2,002 $ 908 $ — $ 10,737 Net income (loss) from continuing operations attributable to Hess Corporation 654 226 545 671 (404 ) 1,692 Depreciation, depletion and amortization 1,751 683 487 289 14 3,224 Provision (benefit) for income taxes 446 91 435 24 (252 ) 744 Identifiable assets 17,729 7,730 3,002 6,746 2,042 37,249 Property, plant and equipment (net) (a) 15,595 6,339 2,235 3,232 116 27,517 Capital expenditures 3,467 524 399 831 53 5,274 2013 Operating revenues $ 6,076 $ 1,337 $ 2,736 $ 1,756 $ — $ 11,905 Net income (loss) from continuing operations attributable to Hess Corporation 777 2,051 594 881 (443 ) 3,860 Depreciation, depletion and amortization 1,393 484 518 276 16 2,687 Impairments — — — 289 — 289 Provision (benefit) for income taxes 495 (646 ) 767 215 (266 ) 565 Capital expenditures 3,613 689 578 829 58 5,767 (a) Of the total Europe, Property, plant and equipment (net), Norway represented $4,108 million in 2015 (2014: $5,246 million).

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	21. Related Party Transactions The following table presents our related party transactions: 2015 2014 2013 (In millions) Purchases: HOVENSA $ — $ — $ — Bayonne Energy Center LLC — — 38 Sales: WilcoHess (a) — 211 2,828 HOVENSA — 31 90 (a) We acquired our partners’ 56% interest in WilcoHess in January 2014 for approximately $290 million. See Note 3, Discontinued Operations.

Financial Risk Management Activ

Financial Risk Management Activities	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Financial Risk Management Activities	22. Financial Risk Management Activities In the normal course of our business, we are exposed to commodity risks related to changes in the prices of crude oil and natural gas as well as changes in interest rates and foreign currency values. In the disclosures that follow, corporate financial risk management activities refer to the mitigation of these risks through hedging activities. We maintain a control environment for all of our financial risk management under the direction of our Chief Risk Officer. Hedging strategies are reviewed annually by the Audit Committee of the Board of Directors. Our treasury department is responsible for administering foreign exchange rate and interest rate hedging programs using similar controls and processes, where applicable. Derivatives include both financial instruments and forward purchase and sale contracts. Corporate Financial Risk Management Activities: Financial risk management activities include transactions designed to reduce risk in the selling prices of crude oil or natural gas we produced or by reducing our exposure to foreign currency or interest rate movements. Generally, futures, swaps or option strategies may be used to fix the forward selling price of a portion of our crude oil or natural gas production. Forward contracts may also be used to purchase certain currencies in which we conduct the business with the intent of reducing exposure to foreign currency fluctuations. These forward contracts comprise various currencies, primarily the British Pound and Danish Krone. Interest rate swaps may be used to convert interest payments on certain long-term debt from fixed to floating rates. Gross notional amounts of both long and short positions are presented in the volume tables beginning below. These amounts include long and short positions that offset in closed positions and have not reached contractual maturity. Gross notional amounts do not quantify risk or represent assets or liabilities of the Corporation, but are used in the calculation of cash settlements under the contracts. The gross volumes of the financial risk management derivative contracts outstanding at December 31, were as follows: 2015 2014 Foreign exchange (millions of USD) $ 967 $ 1,189 Interest rate swaps (millions of USD) $ 1,300 $ 1,300 The table below reflects the gross and net fair values of the risk management derivative instruments, all of which are based on Level 2 inputs: Accounts Receivable Accounts Payable (In millions) December 31, 2015 Derivative contracts designated as hedging instruments Interest rate $ 3 $ — Total derivative contracts designated as hedging instruments 3 — Derivative contracts not designated as hedging instruments Foreign exchange 19 (3 ) Total derivative contracts not designated as hedging instruments 19 (3 ) Gross fair value of derivative contracts 22 (3 ) Master netting arrangements (3 ) 3 Net fair value of derivative contracts $ 19 $ — December 31, 2014 Derivative contracts designated as hedging instruments Interest rate $ 39 $ — Total derivative contracts designated as hedging instruments 39 — Derivative contracts not designated as hedging instruments Foreign exchange 29 — Total derivative contracts not designated as hedging instruments 29 — Gross fair value of derivative contracts 68 — Net fair value of derivative contracts $ 68 $ — Derivative contracts designated as hedging instruments: Commodity: In 2015, c rude oil price hedging contracts increased E&P Sales and other operating revenues by $126 million, including losses of $48 million associated with changes in the time value of crude oil collars . In 2014 and 2013, c rude oil price hedging contracts increased E&P Sales and other operating revenues by $193 million and $39 million, respectively. Interest rate swaps: At December 31, 2015, we had interest rate swaps with gross notional amounts of $1,300 million (2014: $1,300 million), which were designated as fair value hedges. During 2015, we settled existing interest rate swaps and received cash proceeds of $41 million. Changes in the fair value of interest rate swaps and the hedged fixed‑rate debt are recorded in Interest expense in the . In 2015, we recorded an increase of $4 million, excluding accrued interest, in the fair value of interest rate swaps and a corresponding adjustment in the carrying value of the hedged fixed‑rate debt (2014: $1 million increase; 2013: $35 million decrease). Derivative contracts not designated as hedging instruments: Foreign exchange : Total foreign exchange gains and losses are reported in Other, net in Revenues and non-operating income in the and amounted to a loss of $21 million in 2015 (2014: loss of $43 million; 2013: loss of $54 million) and includes gains or losses on foreign exchange contracts that are not designated as hedges amounting to a gain of $98 million in 2015 (2014: gain of $117 million; 2013: loss of $39 million). The after‑tax foreign currency translation adjustments included in the amounted to a loss of $344 million for the year-ended December 31, 2015 (2014: loss of $756 million; 2013: loss of $164 million). Cumulative currency translation adjustments reduced shareholders’ equity by $1,101 million at December 31, 2015 and $757 million at December 31, 2014. Trading Activities: In February 2015, we sold our interest in our energy trading joint venture, HETCO, which was subsequently, renamed Hartree Partners, LP (Hartree). Pursuant to the terms of the sale, Hartree was permitted to utilize our guarantees issued in favor of Hartree's existing counterparties until November 12, 2015, provided that new trades were for a period of one year or less, complied with certain credit requirements, and net exposures remained within value at risk limits previously applied by us. The guarantees remain in effect until the qualifying trades outstanding at November 12, 2015 mature. We have the right to seek reimbursement from Hartree and a separate Hartree credit support facility upon any counterparty draw on the applicable guarantee from us. No draws on the guaranteed trades have occurred through December 31, 2015. A liability of $10 million associated with the guarantee is included in Other accrued liabilities at December 31, 2015. Credit Risk: We are exposed to credit risks that may at times be concentrated with certain counterparties, groups of counterparties or customers. Accounts receivable are generated from a diverse domestic and international customer base. As of December 31, 2015, our Accounts receivable—Trade related to continuing operations were concentrated with the following counterparty industry segments: Integrated Oil Companies — 58%, Governments — 18%, Financial Institutions — 10% and Other — 14%. We reduce risk related to certain counterparties, where applicable, by using master netting arrangements and requiring collateral, generally cash or letters of credit. At December 31, 2015, we had outstanding letters of credit totaling $113 million (2014: $397 million, of which $240 million related to discontinued operations). Fair Value Measurement: We have other short-term financial instruments, primarily cash equivalents, accounts receivable and accounts payable, for which the carrying value approximated fair value at December 31, 2015 and December 31, 2014. In addition, the disclosure for fair value of long-term debt in Note 8, Debt was based on Level 2 inputs.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	23. Subsequent Events HOVENSA Bankruptcy Settlement: On January 4, 2016, the sale of HOVENSA’s terminal and refinery assets to Limetree Bay Terminals, LLC (“Limetree”), an affiliate of ArcLight Capital Partners, LLC, closed. On January 19, 2016, the Bankruptcy Court entered an order confirming HOVENSA’s Chapter 11 plan of liquidation (the “Liquidation Plan”). Under the Liquidation Plan, HOVENSA established a liquidating trust to distribute certain assets and sale proceeds to its creditors, established an environmental response trust to administer to HOVENSA’s remaining environmental obligations and will conduct an orderly wind-down of its remaining activities. The Liquidation Plan also provides for releases of any claims held by HOVENSA and its bankruptcy estate against us and HOVIC, which were effective on the effective date of the Liquidation Plan. In connection with the Liquidation Plan and HOVENSA’s asset sale, we relinquished our claims against HOVENSA to recover the 2012 and 2015 promissory notes issued by HOVENSA. In addition, we assumed the HOVENSA pension plan upon the effective date of the Liquidation Plan. In 2015, we recorded a charge of $30 million primarily representing the estimated net difference between the HOVENSA pension plan obligation and fair value of the plan assets. Hess Common and Preferred Stock Issuance : In February 2016, we issued 28,750,000 shares of common stock and depositary shares representing 575,000 shares of 8% Series A Mandatory Convertible Preferred Stock (Convertible Preferred Stock), par value $1 per share, with a liquidation preference of $1,000 per share, for total net proceeds of approximately $1.6 billion after deducting underwriting discounts, commissions, and estimated offering expenses. Unless converted earlier, each share of Convertible Preferred Stock will automatically convert into between 21.822 shares and 25.642 shares of our common stock based on the average share price over a period of twenty consecutive trading days ending prior to February 1, 2019 (the “Final Average Price”), subject to anti-dilution adjustments. We also entered into capped call transactions that are expected generally to reduce the potential dilution to our common stock upon conversion of the Convertible Preferred Stock if the Final Average Price exceeds $45.83 per share, subject to anti-dilution adjustments. The number of common shares to be delivered by the counterparties to us will be the value of the capped call transactions at conversion divided by the Final Average Price. The value of the capped call transactions will be zero if the Final Average Price is $45.83 or less and can be up to the capped value of approximately $98 million if the Final Average Price is $53.625 or higher. For any Final Average Price between $45.83 and $53.625, the value of the capped call transactions will be 12.55 million covered shares multiplied by the difference between the Final Average Price and $45.83. 1

Valuation and Qualifying Accoun

Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2015
Valuation And Qualifying Accounts [Abstract]
Valuation and Qualifying Accounts	Schedule II HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2015, 2014 and 2013 Additions Description Balance Charged to Charged to Deductions Balance (In millions) 2015 Losses on receivables $ 13 $ 32 $ — $ 2 $ 43 Deferred income tax valuation $ 1,416 $ 280 $ — $ 118 $ 1,578 2014 Losses on receivables $ 27 $ — $ — $ 14 $ 13 Deferred income tax valuation $ 1,519 $ 142 $ (1 ) $ 244 $ 1,416 2013 Losses on receivables $ 34 $ 10 $ — $ 17 $ 27 Deferred income tax valuation $ 1,282 $ 383 $ (17 ) $ 129 $ 1,519

Nature of Operations, Basis o32

Nature of Operations, Basis of Presentation and Summary of Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Basis of Presentation and Principles of Consolidation	Basis of Presentation and Principles of Consolidation: The consolidated financial statements include the accounts of Hess Corporation and entities in which we own more than a 50% voting interest. We also consolidate Hess Infrastructure Partners LP (HIP), a variable interest entity, based on our conclusion that we have the power through our 50% ownership to direct those activities that most significantly impact the economic performance of HIP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to HIP. Our undivided interests in unincorporated oil and gas exploration and production ventures are proportionately consolidated. Investments in affiliated companies, 20% to 50% owned and where we have the ability to influence the operating or financial decisions of the affiliate, are accounted for using the equity method. In November 2015, the Financial Accounting Standards Board (FASB) issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes Statement of Financial Position , we have adopted the update Note 20, Segment Information
Estimates and Assumptions	Estimates and Assumptions: In preparing financial statements in conformity with U.S. generally accepted accounting principles (GAAP), management makes estimates and assumptions that affect the reported amounts of assets and liabilities in the Consolidated Balance Sheet and revenues and expenses in the Statement of Consolidated Income . Actual results could differ from those estimates. Estimates made by management include oil and gas reserves, asset and other valuations, depreciable lives, pension liabilities, legal and environmental obligations, asset retirement obligations and income taxes.
Revenue Recognition	Revenue Recognition: The E&P segment recognizes revenue from the sale of crude oil, natural gas liquids, and natural gas, when title passes to the customer. Differences between E&P natural gas volumes sold and our entitlement share of natural gas production are not material. In our E&P activities, we engage in crude oil purchase and sale transactions with the same counterparty that are entered into in contemplation of one another for the primary purpose of changing location or quality. These arrangements are reported net in Sales and other operating revenues in the Statement of Consolidated Income Our Bakken Midstream segment recognizes revenue from fee-based services including crude oil and natural gas gathering, processing of natural gas and the fractionation of natural gas liquids, terminaling and loading crude oil and natural gas liquids, transportation of crude oil by rail car and the storage and terminaling of propane when pervasive evidence of an arrangement exists, delivery has occurred or services rendered, price is fixed or determinable, and collectability is reasonably assured. Prior to 2014, when providing natural gas processing services, our Bakken Midstream operating segment purchased unprocessed natural gas from us and third parties and provided processing services pursuant to contracts whereby it retained a portion of the sales proceeds received and charged certain fees to customers. The remaining proceeds were remitted back to customers based on the contractual arrangements.
Exploration and Development Costs	Exploration and Development Costs: E&P activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized. In production operations, costs of injected CO 2 for tertiary recovery are expensed as incurred. The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of a project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors, firm plans for additional drilling and other factors.
Depreciation, Depletion and Amortization	Depreciation, Depletion and Amortization: We record depletion expense for acquisition costs of proved properties using the units of production method over proved oil and gas reserves. Depreciation and depletion expense for oil and gas production facilities and wells is calculated using the units of production method over proved developed oil and gas reserves. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors. Depreciation of all other plant and equipment is determined on the straight-line method based on estimated useful lives.
Capitalized Interest	Capitalized Interest: Interest from external borrowings is capitalized on material projects using the weighted average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at first production from the field. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying assets.
Impairment of Long-lived Assets	Impairment of Long‑lived Assets: We review long‑lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts of the long-lived assets are not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is determined based on the estimated fair value of the assets generally determined by discounting anticipated future net cash flows, an income valuation approach, or by a market‑based valuation approach, which are Level 3 fair value measurements. In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a projected amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows, since the standardized measure requires the use of historical twelve month average prices. As a result of the prevailing low crude oil price environment, we tested our oil and gas properties for impairment at December 31, 2015. See Note 10, Impairment .
Impairment of Goodwill	Impairment of Goodwill: Goodwill is tested for impairment annually on October 1 st Note 10, Impairment.
Cash and Cash Equivalents	Cash and Cash Equivalents: Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have maturities of three months or less when acquired.
Inventories	Inventories: Inventories are valued at the lower of cost or market. Cost is generally determined using average actual costs.
Income Taxes	Income Taxes: Deferred income taxes are determined using the liability method. We have net operating loss carryforwards or credit carryforwards in multiple jurisdictions and have recorded deferred tax assets for those losses and credits. Additionally, we have deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount that is expected to be realized. In evaluating the realizability of deferred tax assets, we consider the reversal of temporary differences, the expected utilization of net operating losses and credit carryforwards during available carryforward periods, the availability of tax planning strategies, the existence of appreciated assets and estimates of future taxable income and other factors. In addition, we recognize the financial statement effect of a tax position only when management believes that it is more likely than not, that based on the technical merits, the position will be sustained upon examination. We do not provide for deferred U.S. income taxes for that portion of undistributed earnings of foreign subsidiaries that are indefinitely reinvested in foreign operations. We classify interest and penalties associated with uncertain tax positions as income tax expense.
Asset Retirement Obligations	Asset Retirement Obligations: We have material legal obligations to remove and dismantle long ‑lived assets and to restore land or the seabed at certain exploration and production locations. We initially recognize a liability for the fair value of legally required asset retirement obligations in the period in which the retirement obligations are incurred, and capitalize the associated asset retirement costs as part of the carrying amount of the long‑lived assets. In subsequent periods, the liability is accreted, and the asset is depreciated over the useful life of the related asset. Fair value is determined by applying a credit adjusted risk-free rate to the undiscounted expected future abandonment expenditures, which represent Level 3 inputs in the fair value hierarchy defined under Fair Value Measurements below.
Retirement Plans	Retirement Plans: We recognize the funded status of defined benefit postretirement plans in the Consolidated Balance Sheet . The funded status is measured as the difference between the fair value of plan assets and the projected benefit obligation. We recognize the net changes in the funded status of these plans in the year in which such changes occur. Prior service costs and actuarial gains and losses in excess of 10% of the greater of the benefit obligation or the market value of assets are amortized over the average remaining service period of active employees.
Derivatives	Derivatives: We utilize derivative instruments for financial risk management activities. In these activities, we may use futures, forwards, options and swaps, individually or in combination, to mitigate our exposure to fluctuations in prices of crude oil and natural gas, as well as changes in interest and foreign currency exchange rates. All derivative instruments are recorded at fair value in our Consolidated Balance Sheet
Fair Value Measurements	Fair Value Measurements: We use various valuation approaches in determining fair value for financial instruments, including the market and income approaches. Our fair value measurements also include non-performance risk and time value of money considerations. Counterparty credit is considered for receivable balances, and our credit is considered for accrued liabilities. We also record certain nonfinancial assets and liabilities at fair value when required by GAAP. These fair value measurements are recorded in connection with business combinations, qualifying nonmonetary exchanges, the initial recognition of asset retirement obligations and any impairment of long‑lived assets, equity method investments or goodwill. We determine fair value in accordance with the fair value measurements accounting standard which established a hierarchy for the inputs used to measure fair value based on the source of the inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3), including discounted cash flows and other unobservable data. Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market. Multiple inputs may be used to measure fair value; however, the level of fair value for each physical derivative and financial asset or liability is based on the lowest significant input level within this fair value hierarchy. Details on the methods and assumptions used to determine the fair values are as follows: Fair value measurements based on Level 1 inputs: Measurements that are most observable are based on quoted prices of identical instruments obtained from the principal markets in which they are traded. Closing prices are both readily available and representative of fair value. Market transactions occur with sufficient frequency and volume to assure liquidity. Fair value measurements based on Level 2 inputs: Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. Measurements based on Level 2 inputs include over-the-counter derivative instruments that are priced on an exchange traded curve, but have contractual terms that are not identical to exchange traded contracts. Fair value measurements based on Level 3 inputs: Measurements that are least observable are estimated from related market data, determined from sources with little or no market activity for comparable contracts or are positions with longer durations. Fair values determined using discounted cash flows and other unobservable data are also classified as Level 3. Netting of Financial Instruments: We generally enter into master netting arrangements to mitigate legal and counterparty credit risk. Master netting arrangements are generally accepted overarching master contracts that govern all individual transactions with the same counterparty entity as a single legally enforceable agreement. The U.S. Bankruptcy Code provides for the enforcement of certain termination and netting rights under certain types of contracts upon the bankruptcy filing of a counterparty, commonly known as the “safe harbor” provisions. If a master netting arrangement provides for termination and netting upon the counterparty’s bankruptcy, these rights are generally enforceable with respect to “safe harbor” transactions. If these arrangements provide the right of offset and our intent and practice is to offset amounts in the case of such a termination, our policy is to record the fair value of derivative assets and liabilities on a net basis. In the normal course of business we rely on legal and credit risk mitigation clauses providing for adequate credit assurance as well as close‑out netting, including two‑party netting and single counterparty multilateral netting. As applied to us, “two‑party netting” is the right to net amounts owing under safe harbor transactions between a single defaulting counterparty entity and a single Hess entity, and “single counterparty multilateral netting” is the right to net amounts owing under safe harbor transactions among a single defaulting counterparty entity and multiple Hess entities. We are reasonably assured that these netting rights would be upheld in a bankruptcy proceeding in the U.S. in which the defaulting counterparty is a debtor under the U.S. Bankruptcy Code.
Share-based Compensation	Share-based Compensation: We account for share-based compensation under the fair value method of accounting. The fair value of all share ‑based compensation is recognized as expense on a straight‑line basis over the full vesting period of the awards. We estimate the fair value of employee stock options at the date of grant using a Black‑Scholes valuation model, performance share units using a Monte Carlo simulation model, and restricted stock based on the market value of the underlying shares at the date of grant.
Foreign Currency Translation	Foreign Currency Translation: The U.S. Dollar is the functional currency (primary currency in which business is conducted) for most foreign operations. Adjustments resulting from remeasuring monetary assets and liabilities that are denominated in a currency other than the functional currency are recorded in Other, net in the Statement of Consolidated Income . For operations that do not use the U.S. Dollar as the functional currency, primarily those in Norway where the Norwegian Krone is used, adjustments resulting from translating foreign currency assets and liabilities into U.S. Dollars are recorded in the Consolidated Balance Sheet in a separate component of equity titled Accumulated other comprehensive income (loss).
Maintenance and Repairs	Maintenance and Repairs: Maintenance and repairs are expensed as incurred. Capital improvements are recorded as additions in Property, plant and equipment.
Environmental Expenditures	Environmental Expenditures: We accrue and expense the undiscounted environmental costs necessary to remediate existing conditions related to past operations when the future costs are probable and reasonably estimable. At year‑end 2015, our reserve for estimated remediation liabilities was approximately $80 million and was included within accrued liabilities. Environmental expenditures that increase the life or efficiency of property or reduce or prevent future adverse impacts to the environment are capitalized.
New Accounting Pronouncements	New Accounting Pronouncements: In May 2014, the FASB issued Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers , as a new Accounting Standards Codification (ASC) Topic ASC 606. This ASU is effective for us beginning in the first quarter of 2018 , with early adoption permitted from the first quarter of 2017. We are currently assessing the impact of the ASU on our consolidated financial statements. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes Consolidated Balance Sheet

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2015
Discontinued Operations And Disposal Groups [Abstract]
Summary of Sales and Other Operating Revenues and Income (Loss) from Discontinued Operations	Sales and other operating revenues and Income from discontinued operations were as follows: 2015 2014 2013 (In millions) Sales and other operating revenues $ 14 $ 9,576 $ 22,652 Income (loss) from discontinued operations before income taxes $ (74 ) $ 1,071 $ 1,835 Current tax provision (benefit) — — — Deferred tax provision (benefit) (26 ) 389 649 Provision (benefit) for income taxes (26 ) 389 649 Income (loss) from discontinued operations, net of income taxes $ (48 ) $ 682 $ 1,186 Less: Net income (loss) attributable to noncontrolling interests — 57 (6 ) Income (loss) from discontinued operations attributable to Hess Corporation $ (48 ) $ 625 $ 1,192

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Inventories	Inventories at December 31 were as follows: 2015 2014 (In millions) Crude oil and natural gas liquids $ 144 $ 246 Materials and supplies 255 281 Total inventories $ 399 $ 527

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property Plant And Equipment [Abstract]
Components of Property, Plant and Equipment	Property, plant and equipment at December 31 were as follows: 2015 2014 (In millions) Exploration and Production Unproved properties $ 958 $ 1,468 Proved properties 4,202 4,211 Wells, equipment and related facilities 38,738 38,263 43,898 43,942 Bakken Midstream 2,757 2,386 Corporate, Interest and Other 171 194 Total — at cost 46,826 46,522 Less: Reserves for depreciation, depletion, amortization and lease impairment 20,474 19,005 Property, plant and equipment — net $ 26,352 $ 27,517
Net Changes in Capitalized Exploratory Well Costs	Capitalized Exploratory Well Costs : The following table discloses the amount of capitalized exploratory well costs pending determination of proved reserves at December 31, and the changes therein during the respective years: 2015 2014 2013 (In millions) Balance at January 1 $ 1,416 $ 2,045 $ 2,259 Additions to capitalized exploratory well costs pending the determination of proved reserves 424 292 237 Reclassifications to wells, facilities and equipment based on the determination of proved reserves (72 ) (629 ) (106 ) Capitalized exploratory well costs charged to expense (356 ) (235 ) (267 ) Dispositions and other 3 (57 ) (78 ) Ending balance at December 31 $ 1,415 $ 1,416 $ 2,045 Number of wells at end of year 35 37 50
Exploratory Drilling Costs Capitalized in Excess of One Year After Completion of Drilling	Exploratory well costs capitalized for greater than one year following completion of drilling were $1,053 million at December 31, 2015, separated by year of completion as follows (in millions): 2014 $ 79 2013 43 2012 336 2011 207 2010 and prior 388 $ 1,053

Goodwill (Tables)

Goodwill (Tables)	12 Months Ended
	Dec. 31, 2015
Goodwill And Intangible Assets Disclosure [Abstract]
Changes in Carrying Amount of Goodwill	The changes in the carrying amount of goodwill were as follows: Exploration and Production Bakken Midstream Total (In millions) Beginning balance at January 1, 2014 $ 1,869 $ — $ 1,869 Acquisitions 115 — 115 Dispositions (126 ) — (126 ) Balance at December 31, 2014 1,858 — 1,858 Reclassification (375 ) 375 — Impairment (1,483 ) — (1,483 ) Ending balance at December 31, 2015 $ — $ 375 $ 375

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Changes to Asset Retirement Obligations	The following table describes changes to our asset retirement obligations: 2015 2014 (In millions) Asset retirement obligations at beginning of period $ 2,723 $ 2,772 Liabilities incurred 57 63 Liabilities settled or disposed of (360 ) (420 ) Accretion expense 126 136 Revisions of estimated liabilities 92 263 Foreign currency translation (255 ) (91 ) Asset retirement obligations at end of period 2,383 2,723 Less: Current obligations 225 442 Long-term obligations at end of period $ 2,158 $ 2,281

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Components of Debt	Long‑term debt at December 31 consisted of the following: 2015 2014 (In millions) Debt excluding Bakken Midstream: Fixed-rate public notes: 1.3% due 2017 $ 300 $ 300 8.1% due 2019 999 999 3.5% due 2024 298 298 7.9% due 2029 696 696 7.3% due 2031 747 747 7.1% due 2033 598 598 6.0% due 2040 745 745 5.6% due 2041 1,242 1,242 Total fixed-rate public notes 5,625 5,625 Financing obligations associated with floating production system 264 331 Fair value adjustments - interest rate hedging 31 31 Total debt excluding Bakken Midstream $ 5,920 $ 5,987 Debt related to Bakken Midstream: Bakken Midstream - term loan A facility $ 600 $ — Bakken Midstream - revolving credit facility 110 — Total debt related to Bakken Midstream $ 710 $ — Total long-term debt: Total debt (a) (b) $ 6,630 $ 5,987 Less: Current maturities of long-term debt 86 68 Total long-term debt $ 6,544 $ 5,919 (a) At December 31, 2015 the fair value of total debt amounted to $6,515 million (2014: $7,003 million ). (b) The
Outstanding Letters of Credit	Outstanding letters of credit at December 31 were as follows: 2015 2014 (In millions) Committed lines (a) $ 10 $ 25 Uncommitted lines (a) 103 372 Total (b) $ 113 $ 397 (a) At December 31, 2015, committed and uncommitted lines have expiration dates through 2016. (b) At December 31, 2015, $32 million relates to contingent liabilities and $81 million relates to liabilities recorded in the Consolidated Balance Sheet (2014: $54 million and $343 million, respectively).

Share-based Compensation (Table

Share-based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Share-based Compensation Expense	Share‑based compensation expense consisted of the following: Before Income Taxes After Income Taxes 2015 2014 2013 (b) 2015 2014 2013 (In millions) Restricted stock $ 67 $ 62 $ 31 $ 42 $ 39 $ 19 Stock options 5 2 13 3 1 8 Performance share units 25 19 10 16 12 6 Total (a) $ 97 $ 83 $ 54 $ 61 $ 52 $ 33 (a) Includes pre‑tax share‑based compensation expense included in Income from continuing operations of approximately $97 million, $87 million and $60 million for 2015, 2014 and 2013, respectively. (b) Reflects the reversal of $33 million ($25 million for restricted stock, $7 million for PSUs and $1 million for stock options) in compensation expense for grants that were not expected to vest as a result of our transformation to a pure play E&P company.
Summary of Share-based Compensation Activity	Share‑based compensation activity consisted of the following: Performance Share Units Stock Options Restricted Stock Performance Share Units Weighted - Average Fair Value on Date of Grant Options Weighted - Average Exercise Price per Share Shares of Restricted Common Stock Weighted - Average Price on Date of Grant (In thousands, except per share amounts) Outstanding at January 1, 2015 800 $ 89.91 6,766 $ 66.79 2,901 $ 71.58 Granted 366 76.64 521 74.49 1,131 74.38 Exercised — — (244 ) 48.51 — — Vested (288 ) 72.93 — — (921 ) 63.63 Forfeited (58 ) 97.16 (132 ) 79.29 (291 ) 71.39 Outstanding at December 31, 2015 820 $ 89.43 6,911 $ 67.77 2,820 $ 75.32
Weighted Average Assumptions Utilized to Estimate Fair Value of Stock Options	The following weighted average assumptions were utilized to estimate the fair value of stock options: 2015 2014 2013 Risk free interest rate 1.77 % 1.86 % — Stock price volatility 0.312 0.363 — Dividend yield 1.34 % 1.24 % — Expected life in years 6.0 6.0 — Weighted average fair value per option granted $ 21.00 $ 26.46 —
Weighted Average Assumptions Utilized to Estimate Fair Value of PSU Awards	The following weighted average assumptions were utilized to estimate the fair value of PSU awards: 2015 2014 2013 Risk free interest rate 1.02 % 0.65 % 0.36 % Stock price volatility 0.270 0.359 0.359 Contractual term in years 3.0 3.0 3.0 Grant date price of Hess common stock $ 74.49 $ 80.35 $ 69.49

Retirement Plans (Tables)

Retirement Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Compensation And Retirement Disclosure [Abstract]
Change in Benefit Obligation, Fair Value of Plan Assets, and Funded Status of Pension Plans and Postretirement Medical Plan	The following table summarizes the benefit obligations, the fair value of plan assets, and the funded status of our pension and postretirement medical plans: Funded Unfunded Postretirement Pension Plans Pension Plan Medical Plan 2015 2014 2015 2014 2015 2014 (In millions) Change in benefit obligation Balance at January 1 $ 2,450 $ 1,957 $ 278 $ 253 $ 94 $ 97 Service cost 51 45 16 12 4 4 Interest cost 93 91 9 9 3 3 Actuarial (gain) loss (a) (156 ) 470 (2 ) 61 5 (4 ) Benefit payments (b) (85 ) (77 ) (42 ) (57 ) (8 ) (6 ) Plan curtailments (4 ) (3 ) — — — — Special termination benefits 1 2 — — — — Foreign currency exchange rate changes (29 ) (35 ) — — — — Balance at December 31 2,321 2,450 259 278 98 94 Change in fair value of plan assets Balance at January 1 $ 2,251 $ 2,145 $ — $ — $ — $ — Actual return on plan assets 28 151 — — — — Employer contributions 44 68 42 57 8 6 Benefit payments (b) (85 ) (77 ) (42 ) (57 ) (8 ) (6 ) Foreign currency exchange rate changes (32 ) (36 ) — — — — Balance at December 31 2,206 2,251 — — — — Funded status (plan assets greater (less) than benefit obligations) at December 31 $ (115 ) $ (199 ) $ (259 ) $ (278 ) $ (98 ) $ (94 ) Unrecognized net actuarial (gains) losses 775 859 105 135 — (5 ) (a) The change in discount rate and mortality assumptions in 2014 resulted in total actuarial losses of approximately $330 million and $125 million, respectively. (b) Benefit payments include lump-sum settlement payments of $41 million in 2015 and $55 million in 2014.
Pension Plans and Postretirement Medical Plan Amounts Recognized in Consolidated Balance Sheet	Amounts recognized in the Consolidated Balance Sheet at December 31 consisted of the following: Funded Unfunded Postretirement Pension Plans Pension Plan Medical Plan 2015 2014 2015 2014 2015 2014 (In millions) Pension asset / (accrued benefit liability) $ (115 ) $ (199 ) $ (259 ) $ (278 ) $ (98 ) $ (94 ) Accumulated other comprehensive loss, pre-tax (a) 775 859 105 135 — (5 ) (a) The after‑tax deficit reflected in Accumulated other comprehensive income (loss) was $563 million at December 31, 2015 (2014: $652 million).
Components of Net Periodic Benefit Cost for Funded and Unfunded Pension Plans and Postretirement Medical Plan	The net periodic benefit cost for funded and unfunded pension plans, and the postretirement medical plan, is as follows: Pension Plans Postretirement Medical Plan 2015 2014 2013 2015 2014 2013 (In millions) Service cost $ 67 $ 57 $ 73 $ 4 $ 4 $ 4 Interest cost 102 100 89 3 3 3 Expected return on plan assets (168 ) (161 ) (141 ) — — — Amortization of unrecognized net actuarial losses 75 32 61 — — 1 Settlement loss 17 24 — — — — Curtailment loss — — 1 — — — Special termination benefit recognized 1 1 5 — — — Net periodic benefit cost $ 94 $ 53 $ 88 $ 7 $ 7 $ 8
Actuarial Assumptions Used For Pension Plans & Postretirement Medical Plan	The weighted average actuarial assumptions used for funded and unfunded pension plans were as follows: 2015 2014 2013 Weighted average assumptions used to determine benefit obligations at December 31 Discount rate 4.1 % 3.8 % 4.6 % Rate of compensation increase 4.5 % 5.0 % 4.4 % Weighted average assumptions used to determine net periodic benefit cost for the years ended December 31 Discount rate 3.8 % 4.6 % 4.0 % Expected return on plan assets 7.5 % 7.5 % 7.5 % Rate of compensation increase 5.0 % 4.4 % 4.3 % The actuarial assumptions used for postretirement medical plan, as follows: 2015 2014 2013 Assumptions used to determine benefit obligations at December 31 Discount rate 3.5 % 3.1 % 3.6 % Initial health care trend rate 6.7 % 6.8 % 7.1 % Ultimate trend rate 4.5 % 4.5 % 4.6 % Year in which ultimate trend rate is reached 2038 2029 2027
Fair Value of Financial Assets of Funded Pension Plans	The following tables provide the fair value of the financial assets of the funded pension plans as of December 31, 2015 and 2014 in accordance with the fair value measurement hierarchy described in Note 1, Nature of Operations, Basis of Presentation and Summary of Accounting Policies Level 1 Level 2 Level 3 Total (In millions) December 31, 2015 Cash and short-term investment funds $ — $ 34 $ — $ 34 Equities: U.S. equities (domestic) 556 — — 556 International equities (non-U.S.) 159 266 — 425 Global equities (domestic and non-U.S.) 2 217 — 219 Fixed income: Treasury and government issued (a) — 213 — 213 Government related (b) — 6 1 7 Mortgage-backed securities (c) — 174 2 176 Corporate — 157 — 157 Other: Hedge funds — — 216 216 Private equity funds — — 122 122 Real estate funds 12 — 52 64 Diversified commodities funds — 17 — 17 $ 729 $ 1,084 $ 393 $ 2,206 December 31, 2014 Cash and short-term investment funds $ 6 $ 47 $ — $ 53 Equities: U.S. equities (domestic) 719 — — 719 International equities (non-U.S.) 72 177 — 249 Global equities (domestic and non-U.S.) 10 218 — 228 Fixed income: Treasury and government issued (a) — 222 — 222 Government related (b) — 7 1 8 Mortgage-backed securities (c) — 147 1 148 Corporate 3 137 — 140 Other: Hedge funds — — 302 302 Private equity funds — — 105 105 Real estate funds 12 — 48 60 Diversified commodities funds — 17 — 17 $ 822 $ 972 $ 457 $ 2,251 (a) Includes securities issued and guaranteed by U.S. and non‑U.S. governments. (b) Primarily consists of securities issued by governmental agencies and municipalities. (c) Comprised of U.S. residential and commercial mortgage-backed securities.
Changes in Financial Assets that are Measured at Fair Value Based on Level 3 Inputs that are held by Institutional Funds	The following tables provide changes in financial assets that are measured at fair value based on Level 3 inputs that are held by institutional funds classified as: Private Real Fixed Hedge Equity Estate Income Funds Funds Funds Total (In millions) Balance at January 1, 2014 $ 3 $ 291 $ 89 $ 47 $ 430 Actual return on plan assets — 9 15 — 24 Purchases, sales or other settlements (1 ) 2 1 1 3 Net transfers in (out) of Level 3 — — — — — Balance at December 31, 2014 2 302 105 48 457 Actual return on plan assets — (5 ) 18 9 22 Purchases, sales or other settlements 1 (81 ) (1 ) (5 ) (86 ) Net transfers in (out) of Level 3 — — — — — Balance at December 31, 2015 $ 3 $ 216 $ 122 $ 52 $ 393
Estimated Future Benefit Payments for Funded and Unfunded Pension Plans and Postretirement Medical Plan	Estimated future benefit payments by the funded and unfunded pension plans, and the postretirement medical plan, which reflect expected future service, are as follows (in millions): 2016 $ 111 2017 117 2018 120 2019 129 2020 134 Years 2021 to 2025 711

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Components of Income Tax Provision (Benefit) for Continuing Operations	The provision (benefit) for income taxes from continuing operations consisted of: 2015 2014 2013 (In millions) United States Federal Current $ (7 ) $ (1 ) $ 8 Deferred (995 ) 156 103 State (61 ) 57 9 (1,063 ) 212 120 Foreign Current 4 453 941 Deferred (231 ) 79 186 (227 ) 532 1,127 Total (1,290 ) 744 1,247 Adjustment of deferred taxes for foreign income tax law changes (a) (9 ) — (682 ) Total provision (benefit) for income taxes $ (1,299 ) $ 744 $ 565 (a) The reported amount for 2015 reflects $9 million for the effect of a change in Norway’s hydrocarbon and base corporate income tax rates in December 2015. The reported amount for 2013 reflects $674 million for the effect of the Denmark hydrocarbon income tax law change to the Chapter 3A regime in December 2013 and $8 million for the effect of a change in Norway’s hydrocarbon and base corporate income tax rates in December 2013.
Income (Loss) From Continuing Operations Before Income Taxes	Income (loss) from continuing operations before income taxes consisted of the following: 2015 2014 2013 (In millions) United States (a) $ (2,728 ) $ 676 $ 580 Foreign (1,530 ) 1,760 4,021 Total income (loss) from continuing operations before income taxes $ (4,258 ) $ 2,436 $ 4,601 (a) Includes substantially all of our interest expense, corporate expense and the results of commodity hedging activities.
Components of Deferred Tax Liabilities and Deferred Tax Assets, and Presentation in Consolidated Balance Sheet	The components of deferred tax liabilities and deferred tax assets at December 31 were as follows: 2015 2014 (In millions) Deferred tax liabilities Property, plant and equipment and investments (a) $ (3,743 ) $ (4,226 ) Other (257 ) (269 ) Total deferred tax liabilities (4,000 ) (4,495 ) Deferred tax assets Net operating loss carryforwards 3,852 3,010 Tax credit carryforwards 188 193 Property, plant and equipment and investments (a) 981 1,110 Accrued compensation, deferred credits and other liabilities 492 449 Asset retirement obligations 1,220 1,421 Other 165 261 Total deferred tax assets 6,898 6,444 Valuation allowances (1,579 ) (1,416 ) Total deferred tax assets, net of valuation allowances 5,319 5,028 Net deferred tax assets $ 1,319 $ 533 (a) 2014 has been adjusted to conform to the 2015 presentation. In the Consolidated Balance Sheet 2015 2014 (In millions) Deferred income taxes (long-term asset) $ 2,653 $ 2,371 Deferred income taxes (long-term liability) (1,334 ) (1,838 ) Net deferred tax assets $ 1,319 $ 533
Effective Income Tax Rate Reconciliation for Continuing Operations	The difference between our effective income tax rate from continuing operations and the U.S. statutory rate is reconciled below: 2015 2014 2013 U.S. statutory rate 35.0 % 35.0 % 35.0 % Effect of foreign operations (a)(b) 5.9 0.7 5.9 State income taxes, net of Federal income tax 0.9 1.5 0.1 Change in enacted tax laws 0.2 — (14.8 ) Gains on asset sales, net (0.2 ) (8.3 ) (15.6 ) Goodwill impairment (12.2 ) — — Valuation allowance against previously benefitted deferred tax assets (a) (3.1 ) 0.6 1.0 Benefit of legal entity restructuring 3.5 — — Other (a) 0.5 1.0 0.7 Total 30.5 % 30.5 % 12.3 % (a) 2014 and 2013 have been adjusted to conform to the 2015 presentation. (b) The variance in effective income tax rates attributable to the effect of foreign operations primarily resulted from the mix of income among high and low tax rate jurisdictions.
Reconciliation of Beginning and Ending Amounts of Unrecognized Tax Benefits	Below is a reconciliation of the gross beginning and ending amounts of unrecognized tax benefits: 2015 2014 (In millions) Balance at January 1 $ 603 $ 570 Additions based on tax positions taken in the current year 19 42 Additions based on tax positions of prior years 29 70 Reductions based on tax positions of prior years (31) (76) Reductions due to settlements with taxing authorities (12) (3) Reductions due to lapses in statutes of limitation (4) — Balance at December 31 $ 604 $ 603

Outstanding and Weighted Aver42

Outstanding and Weighted Average Common Shares (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Changes in Outstanding Common Shares	The following table provides the changes in our outstanding common shares: 2015 2014 2013 (In millions) Balance at January 1 285.8 325.3 341.5 Activity related to restricted common stock awards, net 0.8 0.6 0.8 Stock options exercised 0.2 3.3 2.3 PSU vested 0.6 — — Shares repurchased (a) (1.4 ) (43.4 ) (19.3 ) Balance at December 31 286.0 285.8 325.3 (a) See Note 17, Share Repurchase Plan.
Net Income (Loss) and Computation of Basic and Diluted Earnings Per Share	The following table presents the calculation of basic and diluted earnings per share: 2015 2014 2013 (In millions) Income (loss) from continuing operations, net of income taxes $ (2,959 ) $ 1,692 $ 4,036 Less: Net income (loss) attributable to noncontrolling interests 49 — 176 Net income (loss) from continuing operations attributable to Hess Corporation (3,008 ) 1,692 3,860 Income from discontinued operations, net of income taxes (48 ) 682 1,186 Less: Net income (loss) attributable to noncontrolling interests — 57 (6 ) Net income from discontinued operations attributable Hess Corporation (48 ) 625 1,192 Net income (loss) attributable to Hess Corporation $ (3,056 ) $ 2,317 $ 5,052 Weighted average common shares outstanding: Basic 283.6 303.7 336.6 Effect of dilutive securities Restricted common stock — 1.5 1.4 Stock options — 1.8 1.7 Performance share units — 0.7 1.2 Diluted 283.6 307.7 340.9 Net income (loss) attributable to Hess Corporation per share: Basic: Continuing operations $ (10.61 ) $ 5.57 $ 11.47 Discontinued operations (0.17 ) 2.06 3.54 Net income (loss) per share $ (10.78 ) $ 7.63 $ 15.01 Diluted: Continuing operations $ (10.61 ) $ 5.50 $ 11.33 Discontinued operations (0.17 ) 2.03 3.49 Net income (loss) per share $ (10.78 ) $ 7.53 $ 14.82

Supplementary Cash Flow Infor43

Supplementary Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Supplementary Cash Flow Information for Statement of Consolidated Cash Flows	The following information supplements the Statement of Consolidated Cash Flows 2015 2014 2013 (In millions) Cash Flows From Operating Activities Interest paid $ (331 ) $ (326 ) $ (408 ) Income taxes paid, net of refunds (140 ) (455 ) (1,353 ) Cash Flows From Investing Activities Capital expenditures incurred - E&P (3,753 ) (4,920 ) (5,174 ) Increase (decrease) in related liabilities (203 ) 53 (239 ) Additions to property, plant and equipment - E&P (3,956 ) (4,867 ) (5,413 ) Capital expenditures incurred - Bakken Midstream (296 ) (301 ) (535 ) Increase (decrease) in related liabilities (69 ) (46 ) 11 Additions to property, plant and equipment - Bakken Midstream (365 ) (347 ) (524 ) Cash Flows From Financing Activities Contribution from formation of Bakken Midstream joint venture 2,628 — — Distributions to partner in Bakken Midstream joint venture (332 ) — — Noncontrolling interests, net related to Continuing operations 2,296 — — Significant Non-Cash Transactions Increase in debt due to construction of a floating production system - Tubular Bells Field $ — $ 68 $ 116

Share Repurchase Plan (Tables)

Share Repurchase Plan (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Schedule of Share Repurchases Under Share Repurchase Plan	Repurchases under this program were as follows: 2015 2014 2013 To Date (In millions, except cost per share) Total cost of shares repurchased $ 91 $ 3,722 $ 1,538 $ 5,351 Total number of shares repurchased 1.45 43.35 19.31 64.11 Average cost per share (including transaction fees) $ 62.76 $ 85.83 $ 79.65 $ 83.45

Leased Assets (Tables)

Leased Assets (Tables)	12 Months Ended
	Dec. 31, 2015
Leases [Abstract]
Future Minimum Rental Payments	At December 31, 2015, future minimum rental payments applicable to non‑cancelable operating leases with remaining terms of one year or more (other than oil and gas property leases) are as follows (in millions): 2016 $ 674 2017 524 2018 401 2019 366 2020 107 Remaining years 373 Total minimum lease payments 2,445 Less: Income from subleases 85 Net minimum lease payments $ 2,360
Rental Expense	Rental expense was as follows: 2015 2014 2013 (In millions) Total rental expense $ 167 $ 248 $ 355 Less: Income from subleases 10 17 15 Net rental expense $ 157 $ 231 $ 340

Guarantees, Contingencies and46

Guarantees, Contingencies and Commitments (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Schedule of Unconditional Purchase Obligations and Commitments	The following table shows aggregate information for certain unconditional purchase obligations and commitments at December 31, 2015 which are not included elsewhere within these Consolidated Financial Statements Payments Due by Period 2017 and 2019 and Total 2016 2018 2020 Thereafter (In millions) Capital expenditures $ 1,750 $ 1,503 $ 247 $ — $ — Operating expenses 548 384 108 32 24 Transportation and related contracts 1,598 121 453 433 591

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Financial Data by Operating Segment	The following table presents operating segment financial data for continuing operations (in millions): 2015 Exploration and Production Bakken Midstream Corporate, Interest and Other Eliminations Total Operating Revenues - Third parties $ 6,636 $ — $ — $ — $ 6,636 Intersegment Revenues — 564 — (564 ) — Operating Revenues $ 6,636 $ 564 $ — $ (564 ) $ 6,636 Net income (loss) from continuing operations attributable to Hess Corporation $ (2,717 ) $ 86 $ (377 ) $ — $ (3,008 ) Interest expense — 10 331 — 341 Depreciation, depletion and amortization 3,852 88 15 — 3,955 Impairment 1,616 — — — 1,616 Provision (benefit) for income taxes (1,111 ) 52 (240 ) — (1,299 ) Investment in affiliates 154 — — — 154 Identifiable assets 28,863 2,761 2,571 — 34,195 Capital Expenditures 3,753 296 — — 4,049 2014 Exploration and Production Bakken Midstream Corporate, Interest and Other Eliminations Total Operating Revenues - Third parties $ 10,737 $ — $ — $ — $ 10,737 Intersegment Revenues — 319 — (319 ) — Operating Revenues $ 10,737 $ 319 $ — $ (319 ) $ 10,737 Net income (loss) from continuing operations attributable to Hess Corporation $ 2,086 $ 10 $ (404 ) $ — $ 1,692 Interest expense — 2 321 — 323 Depreciation, depletion and amortization 3,140 70 14 — 3,224 Provision (benefit) for income taxes 989 7 (252 ) — 744 Investment in affiliates 151 — — — 151 Identifiable assets 32,742 2,465 2,042 — 37,249 Capital Expenditures 4,920 301 53 — 5,274 2013 Exploration and Production Bakken Midstream Corporate, Interest and Other Eliminations Total Operating Revenues - Third parties $ 11,762 $ 143 $ — $ — $ 11,905 Intersegment Revenues 125 127 — (252 ) — Operating Revenues $ 11,887 $ 270 $ — $ (252 ) $ 11,905 Net income (loss) from continuing operations attributable to Hess Corporation $ 4,439 $ (136 ) $ (443 ) $ — $ 3,860 Interest Expense — — 406 — 406 Depreciation, depletion and amortization 2,638 33 16 — 2,687 Impairment 289 — — — 289 Provision (benefit) for income taxes 912 (81 ) (266 ) — 565 Investment in affiliates 109 — 397 — 506 Capital Expenditures 5,174 535 58 — 5,767
Financial Information by Major Geographic Area	The following table presents financial information by major geographic area: United States Europe Africa Asia and Other Countries Corporate, Interest and other Total (In millions) 2015 Operating revenues $ 4,150 $ 870 $ 945 $ 671 $ — $ 6,636 Net income (loss) from continuing operations attributable to Hess Corporation (1,834 ) (408 ) (274 ) (115 ) (377 ) (3,008 ) Depreciation, depletion and amortization 2,449 635 539 317 15 3,955 Impairments 986 279 100 251 — 1,616 Provision (benefit) for income taxes (522 ) (84 ) (48 ) (405 ) (240 ) (1,299 ) Identifiable assets 18,372 6,207 2,178 4,867 2,571 34,195 Property, plant and equipment (net) (a) 15,729 5,300 1,682 3,520 121 26,352 Capital expenditures 2,727 297 160 865 — 4,049 2014 Operating revenues $ 6,270 $ 1,557 $ 2,002 $ 908 $ — $ 10,737 Net income (loss) from continuing operations attributable to Hess Corporation 654 226 545 671 (404 ) 1,692 Depreciation, depletion and amortization 1,751 683 487 289 14 3,224 Provision (benefit) for income taxes 446 91 435 24 (252 ) 744 Identifiable assets 17,729 7,730 3,002 6,746 2,042 37,249 Property, plant and equipment (net) (a) 15,595 6,339 2,235 3,232 116 27,517 Capital expenditures 3,467 524 399 831 53 5,274 2013 Operating revenues $ 6,076 $ 1,337 $ 2,736 $ 1,756 $ — $ 11,905 Net income (loss) from continuing operations attributable to Hess Corporation 777 2,051 594 881 (443 ) 3,860 Depreciation, depletion and amortization 1,393 484 518 276 16 2,687 Impairments — — — 289 — 289 Provision (benefit) for income taxes 495 (646 ) 767 215 (266 ) 565 Capital expenditures 3,613 689 578 829 58 5,767 (a) Of the total Europe, Property, plant and equipment (net), Norway represented $4,108 million in 2015 (2014: $5,246 million).

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	The following table presents our related party transactions: 2015 2014 2013 (In millions) Purchases: HOVENSA $ — $ — $ — Bayonne Energy Center LLC — — 38 Sales: WilcoHess (a) — 211 2,828 HOVENSA — 31 90 (a) We acquired our partners’ 56% interest in WilcoHess in January 2014 for approximately $290 million. See Note 3, Discontinued Operations.

Financial Risk Management Act49

Financial Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gross Notional Volumes of Financial Risk Management Derivative Contracts Outstanding	The gross volumes of the financial risk management derivative contracts outstanding at December 31, were as follows: 2015 2014 Foreign exchange (millions of USD) $ 967 $ 1,189 Interest rate swaps (millions of USD) $ 1,300 $ 1,300
Gross and Net Fair Values of Financial Risk Management Derivative Instruments	The table below reflects the gross and net fair values of the risk management derivative instruments, all of which are based on Level 2 inputs: Accounts Receivable Accounts Payable (In millions) December 31, 2015 Derivative contracts designated as hedging instruments Interest rate $ 3 $ — Total derivative contracts designated as hedging instruments 3 — Derivative contracts not designated as hedging instruments Foreign exchange 19 (3 ) Total derivative contracts not designated as hedging instruments 19 (3 ) Gross fair value of derivative contracts 22 (3 ) Master netting arrangements (3 ) 3 Net fair value of derivative contracts $ 19 $ — December 31, 2014 Derivative contracts designated as hedging instruments Interest rate $ 39 $ — Total derivative contracts designated as hedging instruments 39 — Derivative contracts not designated as hedging instruments Foreign exchange 29 — Total derivative contracts not designated as hedging instruments 29 — Gross fair value of derivative contracts 68 — Net fair value of derivative contracts $ 68 $ —

Nature of Operations, Basis o50

Nature of Operations, Basis of Presentation and Summary of Accounting Policies - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Summary Of Significant Accounting Policies [Line Items]
Variable interest in Hess Infrastructure Partners LP (HIP)	50.00%
Reserve for estimated remediation liabilities	$ 80
Increase in deferred income tax assets		$ 202
Decrease in deferred income tax liabilities		171
Decrease in other current assets		$ 373
HOVENSA
Summary Of Significant Accounting Policies [Line Items]
Interest in joint venture	50.00%

Bakken Midstream Joint Venture

Bakken Midstream Joint Venture - Additional Information (Detail) - USD ($) $ in Millions	Jul. 02, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Jul. 01, 2015	Dec. 31, 2012
Variable Interest Entity [Line Items]
Percentage interest sold of Hess Infrastructure Partners						50.00%
Proceeds from sale of interest in Hess Infrastructure Partners	$ 2,628	$ 2,628	$ 0	$ 0
Term of tariff agreements between Hess Corporation and the Bakken Midstream					10 years
Additional renewal period of tariff agreements by Bakken Midstream					10 years
Hess Corporation's ownership percentage in Bakken Midstream		50.00%
After tax gain from sale of equity interest		$ 2,061
Noncontrolling interest, ownership percentage		50.00%			50.00%
Cash and cash equivalents		$ 2,716	2,444	$ 1,814	$ 2,716		$ 642
Property, plant and equipment, net		26,352	$ 27,517		26,352
Bakken Midstream
Variable Interest Entity [Line Items]
Term Loan A facility - Face amount		$ 600			600	$ 600
Term Loan A facility - Term	5 years	5 years
Cash and cash equivalents		$ 3			3
Property, plant and equipment, net		$ 2,358			$ 2,358
Bakken Midstream liabilities non-recourse to Hess Corporation		liabilities totaling $831 million
Capital in Excess of Par
Variable Interest Entity [Line Items]
After tax gain from sale of equity interest		$ 763
Noncontrolling Interests
Variable Interest Entity [Line Items]
After tax gain from sale of equity interest		$ 1,298

Discontinued Operations - Summa

Discontinued Operations - Summary of Sales and Other Operating Revenues and Income (Loss) from Discontinued Operations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Discontinued Operations And Disposal Groups [Abstract]
Sales and other operating revenues	$ 14	$ 9,576	$ 22,652
Income (loss) from discontinued operations before income taxes	(74)	1,071	1,835
Current tax provision (benefit)	0	0	0
Deferred tax provision (benefit)	(26)	389	649
Provision (benefit) for income taxes	(26)	389	649
Income (loss) from discontinued operations, net of income taxes	(48)	682	1,186
Less: Net income (loss) attributable to noncontrolling interests	0	57	(6)
Income (loss) from discontinued operations attributable to Hess Corporation	$ (48)	$ 625	$ 1,192

Discontinued Operations - Addit

Discontinued Operations - Additional Information (Detail) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2014USD ($)	Dec. 31, 2014USD ($)Lease	Dec. 31, 2013USD ($)	Dec. 31, 2015USD ($)
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Assets associated with HETCO - Reported in Other current assets		$ 1,035
Liabilities associated with HETCO - Reported in Accrued liabilities		797
Guarantee liability associated with HETCO - included in Other accrued liabilities				$ 10
Goodwill associated with divested business		$ 126
Percentage of interest in WilcoHess acquired for preparation of its subsequent sale with retail business	56.00%	56.00%
Cost of acquiring additional ownership interest in WilcoHess	$ 290
Goodwill acquired during period		$ 115
United States East Coast Terminal Network, St. Lucia Terminal & Related Businesses
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Cash proceeds from sale of business			$ 1,000
Gain (loss) from sale of business, pre-tax			739
Gain (loss) from sale of business, after-tax			531
Energy Marketing Business
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Cash proceeds from sale of business			1,200
Gain (loss) from sale of business, pre-tax			761
Gain (loss) from sale of business, after-tax			464
Retail Business
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Cash proceeds from sale of business		2,800
Gain (loss) from sale of business, pre-tax		954
Gain (loss) from sale of business, after-tax		602
Goodwill associated with divested business		115
Gain (loss) related to liquidation of LIFO inventory associated with divested business, pre-tax		275	678
Gain (loss) related to liquidation of LIFO inventory associated with divested business, after-tax		171	414
Charges for impairments, environmental matters, severance and exit costs associated with divested business, pre-tax		308	523
Charges for impairments, environmental matters, severance and exit costs associated with divested business, after-tax		202	$ 334
Charges related to termination of lease contracts and purchase of retail gasoline stations, pre-tax		115
Charges related to termination of lease contracts and purchase of retail gasoline stations, after-tax		$ 72
Number of retail gasoline stations purchased in preparation for subsequent sale of retail business | Lease		180
Original ownership interest held in WilcoHess		44.00%
Cost of acquiring additional ownership interest in WilcoHess		$ 290
Gain (loss) from remeasurement of carrying value of original equity interest of WilcoHess to fair value, pre-tax		39
Gain (loss) from remeasurement of carrying value of original equity interest of WilcoHess to fair value, after-tax		24
Goodwill acquired during period		$ 115

Inventories - Inventories (Deta

Inventories - Inventories (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Inventory Disclosure [Abstract]
Crude oil and natural gas liquids	$ 144	$ 246
Materials and supplies	255	281
Total inventories	$ 399	$ 527

Property, Plant and Equipment -

Property, Plant and Equipment - Components of Property, Plant and Equipment (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property Plant And Equipment [Line Items]
Total — at cost	$ 46,826	$ 46,522
Less: Reserves for depreciation, depletion, amortization and lease impairment	20,474	19,005
Property, plant and equipment, net	26,352	27,517
Exploration and Production
Property Plant And Equipment [Line Items]
Unproved properties	958	1,468
Proved properties	4,202	4,211
Wells, equipment and related facilities	38,738	38,263
Total — at cost	43,898	43,942
Bakken Midstream
Property Plant And Equipment [Line Items]
Total — at cost	2,757	2,386
Property, plant and equipment, net	2,358
Corporate, Interest and Other
Property Plant And Equipment [Line Items]
Total — at cost	$ 171	$ 194

Property, Plant and Equipment56

Property, Plant and Equipment - Net Changes in Capitalized Exploratory Well Costs (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Well	Dec. 31, 2014USD ($)Well	Dec. 31, 2013USD ($)Well
Capitalized Exploratory Well Costs [Abstract]
Beginning balance	$ 1,416	$ 2,045	$ 2,259
Additions to capitalized exploratory well costs pending the determination of proved reserves	424	292	237
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(72)	(629)	(106)
Capitalized exploratory well costs charged to expense	(356)	(235)	(267)
Dispositions and other	3	(57)	(78)
Ending balance	$ 1,415	$ 1,416	$ 2,045
Number of wells at end of year | Well	35	37	50

Property, Plant and Equipment57

Property, Plant and Equipment - Capitalized Exploratory Well Costs - Additional Information (Detail) $ in Millions	12 Months Ended			24 Months Ended
	Dec. 31, 2015USD ($)Well	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2015USD ($)Well
Capitalized Exploratory Well Costs [Line Items]
Exploratory dry hole costs which were incurred and subsequently expensed | $	$ 54	$ 66	$ 77
Capitalized exploratory well costs that have been capitalized for period greater than one year | $	$ 1,053			$ 1,053
Block WA-390-P, Offshore Western Australia
Capitalized Exploratory Well Costs [Line Items]
Capitalized well costs percentage	75.00%			75.00%
Offshore Ghana
Capitalized Exploratory Well Costs [Line Items]
Capitalized well costs percentage	25.00%			25.00%
Appraisal plans for this number of wells submitted to the Ghanaian government	7			7
This number of appraisal wells was approved by the Ghanaian government	5			5
This number of appraisal wells is pending approval by the Ghanaian government	2			2
This number of approved appraisal wells is completed				3

Property, Plant and Equipment58

Property, Plant and Equipment - Exploratory Drilling Costs Capitalized (Detail) $ in Millions	Dec. 31, 2015USD ($)
Projects With Exploratory Well Costs Capitalized For More Than One Year [Line Items]
Capitalized exploratory well costs that have been capitalized for period greater than one year	$ 1,053
Year 2,014
Projects With Exploratory Well Costs Capitalized For More Than One Year [Line Items]
Capitalized exploratory well costs that have been capitalized for period greater than one year	79
Year 2,013
Projects With Exploratory Well Costs Capitalized For More Than One Year [Line Items]
Capitalized exploratory well costs that have been capitalized for period greater than one year	43
Year 2,012
Projects With Exploratory Well Costs Capitalized For More Than One Year [Line Items]
Capitalized exploratory well costs that have been capitalized for period greater than one year	336
Year 2,011
Projects With Exploratory Well Costs Capitalized For More Than One Year [Line Items]
Capitalized exploratory well costs that have been capitalized for period greater than one year	207
Year 2010 and prior
Projects With Exploratory Well Costs Capitalized For More Than One Year [Line Items]
Capitalized exploratory well costs that have been capitalized for period greater than one year	$ 388

Goodwill - Changes in Carrying

Goodwill - Changes in Carrying Amount of Goodwill (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Goodwill [Line Items]
Beginning balance at January 1	$ 1,858	$ 1,869
Acquisitions		115
Dispositions		(126)
Reclassification	0
Impairment	(1,483)
Ending balance at December 31	375	1,858
Exploration and Production
Goodwill [Line Items]
Beginning balance at January 1	1,858	1,869
Acquisitions		115
Dispositions		(126)
Reclassification	(375)
Impairment	(1,483)
Ending balance at December 31	0	1,858
Bakken Midstream
Goodwill [Line Items]
Beginning balance at January 1	0	0
Acquisitions		0
Dispositions		0
Reclassification	375
Impairment	0
Ending balance at December 31	$ 375	$ 0

Goodwill - Additional Informati

Goodwill - Additional Information (Detail) $ in Millions	5 Months Ended	12 Months Ended
	May. 30, 2015Segment	Dec. 31, 2015USD ($)	Jun. 30, 2015USD ($)	Dec. 31, 2014USD ($)	Jan. 31, 2014	Dec. 31, 2013USD ($)
Goodwill [Line Items]
Number of reporting units in Exploration and Production segment | Segment	2
Goodwill		$ 375		$ 1,858		$ 1,869
Reclassification		0
Percentage of interest in WilcoHess acquired for preparation of its subsequent sale with retail business				56.00%	56.00%
Offshore Reporting Unit of Exploration and Production Segment
Goodwill [Line Items]
Goodwill			$ 1,098
Onshore Reporting Unit of Exploration and Production Segment
Goodwill [Line Items]
Goodwill			$ 760
Bakken Midstream
Goodwill [Line Items]
Goodwill		375		$ 0		$ 0
Reclassification		$ 375

Asset Retirement Obligations -

Asset Retirement Obligations - Changes to Asset Retirement Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$ 2,723	$ 2,772
Liabilities incurred	57	63
Liabilities settled or disposed of	(360)	(420)
Accretion expense	126	136
Revisions of estimated liabilities	92	263
Foreign currency translation	(255)	(91)
Asset retirement obligations at end of period	2,383	2,723
Less: Current obligations	225	442
Long-term obligations at end of period	$ 2,158	$ 2,281

Debt - Components of Debt (Deta

Debt - Components of Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Credit facility
Fixed-rate public notes	$ 5,625	$ 5,625
Total debt	6,630	5,987
Debt related to Bakken Midstream:
Less: Current maturities of long-term debt	86	68
Total long-term debt	6,544	5,919
Debt Excluding Bakken Midstream
Credit facility
Fixed-rate public notes	5,625	5,625
Financing obligations associated with floating production system	264	331
Fair value adjustments - interest rate hedging	31	31
Total debt	5,920	5,987
Bakken Midstream
Credit facility
Total debt	710	0
Debt related to Bakken Midstream:
Bakken Midstream - term loan A facility	600	0
Revolving credit facility - Outstanding amount	110	0
1.3% Due 2017 | Debt Excluding Bakken Midstream
Credit facility
Fixed-rate public notes	300	300
8.1% Due 2019 | Debt Excluding Bakken Midstream
Credit facility
Fixed-rate public notes	999	999
3.5% Due 2024 | Debt Excluding Bakken Midstream
Credit facility
Fixed-rate public notes	298	298
7.9% Due 2029 | Debt Excluding Bakken Midstream
Credit facility
Fixed-rate public notes	696	696
7.3% Due 2031 | Debt Excluding Bakken Midstream
Credit facility
Fixed-rate public notes	747	747
7.1% Due 2033 | Debt Excluding Bakken Midstream
Credit facility
Fixed-rate public notes	598	598
6.0% Due 2040 | Debt Excluding Bakken Midstream
Credit facility
Fixed-rate public notes	745	745
5.6% Due 2041 | Debt Excluding Bakken Midstream
Credit facility
Fixed-rate public notes	$ 1,242	$ 1,242

Debt - Components of Debt (Pare

Debt - Components of Debt (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2015
1.3% Due 2017
Debt Instrument [Line Items]
Coupon rate	1.30%
Maturity year	2,017
8.1% Due 2019
Debt Instrument [Line Items]
Coupon rate	8.10%
Maturity year	2,019
3.5% Due 2024
Debt Instrument [Line Items]
Coupon rate	3.50%
Maturity year	2,024
7.9% Due 2029
Debt Instrument [Line Items]
Coupon rate	7.90%
Maturity year	2,029
7.3% Due 2031
Debt Instrument [Line Items]
Coupon rate	7.30%
Maturity year	2,031
7.1% Due 2033
Debt Instrument [Line Items]
Coupon rate	7.10%
Maturity year	2,033
6.0% Due 2040
Debt Instrument [Line Items]
Coupon rate	6.00%
Maturity year	2,040
5.6% Due 2041
Debt Instrument [Line Items]
Coupon rate	5.60%
Maturity year	2,041

Debt - Additional Information (

Debt - Additional Information (Detail) - USD ($)	Jul. 02, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jul. 01, 2015	Jan. 31, 2015	Jun. 30, 2014
Debt Instrument [Line Items]
Aggregate long-term debt, maturing in 2016		$ 86,000,000
Aggregate long-term debt, maturing in 2017		412,000,000
Aggregate long-term debt, maturing in 2018		123,000,000
Aggregate long-term debt, maturing in 2019		1,121,000,000
Aggregate long-term debt, maturing in 2020		560,000,000
Fair value of total debt		6,515,000,000	$ 7,003,000,000
Letters of credit – Issued		32,000,000	54,000,000
Fixed-rate public notes, net of discount		5,625,000,000	5,625,000,000
Repayments of debt			590,000,000
Capitalized interest		45,000,000	76,000,000	$ 60,000,000
Fixed-rate notes, principal amount		$ 5,650,000,000	$ 5,650,000,000
Weighted average interest rate		6.40%	6.40%
Additional secured debt allowed to be borrowed		$ 5,495,000,000
Bakken Midstream
Debt Instrument [Line Items]
Revolving credit facility - Capacity		400,000,000			$ 400,000,000
Revolving credit facility - Outstanding amount		110,000,000	$ 0
Unsecured debt issued		$ 600,000,000			$ 600,000,000
Term Loan A facility - Term	5 years	5 years
Revolving credit facility - Term	5 years	5 years
Leverage ratio - Maximum		500.00%
Interest coverage ratio - Minimum		2.25 to 1.0
Bakken Midstream | Minimum
Debt Instrument [Line Items]
Revolving credit facility – Facility fee (per annum)		0.15%
Bakken Midstream | Maximum
Debt Instrument [Line Items]
Revolving credit facility – Facility fee (per annum)		0.35%
London Interbank Offered Rate | Bakken Midstream
Debt Instrument [Line Items]
Interest rate - Minimum		1.10%
Interest rate - Maximum		2.00%
WilcoHess
Debt Instrument [Line Items]
Repayments of debt			74,000,000
Capital Lease Obligations
Debt Instrument [Line Items]
Repayments of debt			249,000,000
Unsecured Fixed-Rate Notes Issued in June 2014
Debt Instrument [Line Items]
Unsecured debt issued							$ 600,000,000
Fixed-rate public notes, net of discount							598,000,000
Unsecured Fixed-Rate Notes Issued in June 2014 | Fixed Rate Public Notes
Debt Instrument [Line Items]
Repayments of debt			$ 250,000,000
1.3% Due 2017
Debt Instrument [Line Items]
Debt notes maturity period		2,017
1.3% Due 2017 | Fixed Rate Public Notes
Debt Instrument [Line Items]
Unsecured debt issued							300,000,000
Debt notes maturity period		June 2,017
3.5% Due 2024
Debt Instrument [Line Items]
Debt notes maturity period		2,024
3.5% Due 2024 | Fixed Rate Public Notes
Debt Instrument [Line Items]
Unsecured debt issued							$ 300,000,000
Debt notes maturity period		July 2,024
New Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility - Capacity						$ 4,000,000,000
Revolving credit facility - Expiration date		2020-01
Revolving credit facility – Interest rate		1.075% above the London Interbank Offered Rate
Revolving credit facility – Facility fee (per annum)		0.175%
Revolving credit facility - Outstanding amount		$ 0
Letters of credit – Issued		$ 0
Previous Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility - Capacity						$ 4,000,000,000
Revolving credit facility - Expiration date		2016-04

Debt - Outstanding Letters of C

Debt - Outstanding Letters of Credit (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Committed lines	$ 10	$ 25
Uncommitted lines	103	372
Total	$ 113	$ 397

Debt - Outstanding Letters of66

Debt - Outstanding Letters of Credit (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Line Of Credit Facility [Line Items]
Contingent liabilities under letters of credit outstanding	$ 32	$ 54
Letters of credit outstanding, balance sheet liabilities	$ 81	$ 343
Committed and Uncommitted Lines
Line Of Credit Facility [Line Items]
Maturity year	2,016

Dispositions - Additional Infor

Dispositions - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015USD ($)a	Dec. 31, 2014USD ($)a	Dec. 31, 2013USD ($)
Disposition Of Businesses [Line Items]
Cash proceeds from asset sales	$ 50,000,000	$ 2,978,000,000	$ 4,458,000,000
Gains (loss) on asset sales, net	51,000,000	823,000,000	2,174,000,000
Gain (loss) on asset sale, after-tax		0
Interests in Pangkah Asset, Offshore Indonesia
Disposition Of Businesses [Line Items]
Cash proceeds from asset sales		650,000,000
Gains (loss) on asset sales, net		31,000,000
Gain (loss) on asset sale, after-tax		(10,000,000)
Interests in Thailand
Disposition Of Businesses [Line Items]
Cash proceeds from asset sales		805,000,000
Gains (loss) on asset sales, net		706,000,000
Gain (loss) on asset sale, after-tax		706,000,000
Joint Venture Interest in an Electric Generating Facility in Newark, New Jersey
Disposition Of Businesses [Line Items]
Cash proceeds from asset sales		320,000,000
Gains (loss) on asset sales, net		13,000,000
Gain (loss) on asset sale, after-tax		8,000,000
Joint Venture Interest in Bayonne Energy Center
Disposition Of Businesses [Line Items]
Cash proceeds from asset sales		79,000,000
Interest in an Exploration Asset in United Kingdom North Sea
Disposition Of Businesses [Line Items]
Cash proceeds from asset sales		53,000,000
Gains (loss) on asset sales, net		33,000,000
Gain (loss) on asset sale, after-tax		$ 33,000,000
Interest in Beryl Fields & SAGE in United Kingdom North Sea
Disposition Of Businesses [Line Items]
Cash proceeds from asset sales			442,000,000
Gains (loss) on asset sales, net			328,000,000
Gain (loss) on asset sale, after-tax			323,000,000
Interest in Azeri Chirag Guneshli Fields, Offshore Azerbaijan in Caspian Sea & Baku Tbilisi Ceyhan (BTC), Oil Transportation Pipeline Company
Disposition Of Businesses [Line Items]
Cash proceeds from asset sales			884,000,000
Gains (loss) on asset sales, net			360,000,000
Gain (loss) on asset sale, after-tax			360,000,000
Samara-Nafta (Russian Subsidiary)
Disposition Of Businesses [Line Items]
Cash proceeds from asset sales			2,100,000,000
Gains (loss) on asset sales, net			1,119,000,000
Gain (loss) on asset sale, after-tax			$ 1,119,000,000
Corporation's proportionate interest in oil and gas assets (in percentage)			90.00%
Samara-Nafta (Russian Subsidiary) | Noncontrolling Interests
Disposition Of Businesses [Line Items]
Gains (loss) on asset sales, net			$ 168,000,000
Samara-Nafta (Russian Subsidiary) | Total Hess Stockholders' Equity
Disposition Of Businesses [Line Items]
Cash proceeds from asset sales			1,900,000,000
Gains (loss) on asset sales, net			951,000,000
Interest in Natuna A Field, Offshore Indonesia
Disposition Of Businesses [Line Items]
Cash proceeds from asset sales			656,000,000
Gains (loss) on asset sales, net			388,000,000
Gain (loss) on asset sale, after-tax			$ 343,000,000
Interest in Algeria
Disposition Of Businesses [Line Items]
Gains (loss) on asset sales, net	(21,000,000)
Gain (loss) on asset sale, after-tax	$ (21,000,000)
Net Acres in Utica Dry Gas Area of Utica Shale
Disposition Of Businesses [Line Items]
Net acres of Utica dry gas acreage sold | a	13,000	77,000
Cash proceeds from asset sales		$ 1,075,000,000
Sales price of Utica dry gas acreage sold	$ 120,000,000
Gains (loss) on asset sales, net	49,000,000	62,000,000
Gain (loss) on asset sale, after-tax	31,000,000	$ 35,000,000
Joint Venture Interest in Bayonne Energy Center
Disposition Of Businesses [Line Items]
Cash proceeds from asset sales	20,000,000
Gains (loss) on asset sales, net	20,000,000
Gain (loss) on asset sale, after-tax	$ 13,000,000

Impairment - Additional Informa

Impairment - Additional Information (Detail) - USD ($)	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Impairments [Line Items]
Impairment charge, pre-tax				$ 1,616,000,000	$ 0	$ 289,000,000
Goodwill impairment charge, pre-tax				1,483,000,000
Goodwill impairment charge, after-tax				1,483,000,000
Cash proceeds from asset sales				50,000,000	2,978,000,000	4,458,000,000
Gains on asset sales, net				51,000,000	823,000,000	2,174,000,000
Gain (loss) on asset sale, after-tax					$ 0
Legacy Assets in North Dakota
Impairments [Line Items]
Impairment charge, pre-tax				133,000,000
Impairment charge, after-tax				$ 83,000,000
Onshore Reporting Unit
Impairments [Line Items]
Goodwill impairment charge, pre-tax	$ 385,000,000
Offshore Reporting Unit
Impairments [Line Items]
Goodwill impairment charge, pre-tax			$ 1,098,000,000
Bakken Midstream
Impairments [Line Items]
Goodwill impairment charge, pre-tax	$ 0
Offshore and Onshore Reporting Units
Impairments [Line Items]
Goodwill impairment charge, pre-tax		$ 0
Interests in Natuna A Field & Pangkah Asset, Offshore Indonesia
Impairments [Line Items]
Cash proceeds from asset sales						1,300,000,000
Interest in Natuna A Field, Offshore Indonesia
Impairments [Line Items]
Cash proceeds from asset sales						656,000,000
Gains on asset sales, net						388,000,000
Gain (loss) on asset sale, after-tax						343,000,000
Interests in Pangkah Asset, Offshore Indonesia
Impairments [Line Items]
Impairment charge, pre-tax						289,000,000
Impairment charge, after-tax						$ 187,000,000

Share-based Compensation - Addi

Share-based Compensation - Additional Information (Detail) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)$ / sharesshares
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Number of authorized common stock shares under LTIP, as amended	38,000
Number of shares under LTIP, as amended, available for issuance of restricted common shares, performance share units and stock options	14,200
Contractual term of stock options	10 years
Performance of predetermined peer companies	3 years
Minimum PSU awards payout	0.00%
Maximum PSU awards payout	200.00%
Unearned compensation expense, before income taxes due 2016 | $	$ 73
Unearned compensation expense, before income taxes due 2017 | $	42
Unearned compensation expense, before income taxes due 2018 | $	$ 6
Outstanding stock options	6,910
Number of stock options, exercisable	6,310
Weighted average remaining contractual life for options, outstanding	3 years 6 months
Weighted average remaining contractual life for options, exercisable	3 years
Weighted average exercise price for options, exercisable | $ / shares	$ 67.03

Share-based Compensation - Shar

Share-based Compensation - Share-based Compensation Expense (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation expense, pre-tax	$ 97	$ 83	$ 54
Share-based compensation expense, after-tax	61	52	33
Pre-tax share-based compensation expense (benefit) included in Income from Continuing operations	97	87	60
Reversed due to Transformation to Pure Play E&P Company
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation expense, pre-tax			33
Restricted Stock
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation expense, pre-tax	67	62	31
Share-based compensation expense, after-tax	42	39	19
Restricted Stock | Reversed due to Transformation to Pure Play E&P Company
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation expense, pre-tax			25
Stock Options
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation expense, pre-tax	5	2	13
Share-based compensation expense, after-tax	3	1	8
Stock Options | Reversed due to Transformation to Pure Play E&P Company
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation expense, pre-tax			1
Performance Share Units
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation expense, pre-tax	25	19	10
Share-based compensation expense, after-tax	$ 16	$ 12	6
Performance Share Units | Reversed due to Transformation to Pure Play E&P Company
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Share-based compensation expense, pre-tax			$ 7

Share-based Compensation - Summ

Share-based Compensation - Summary of Stock-based Compensation Activity (Detail) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Options - Exercised	(200)	(3,300)	(2,300)
Options - Outstanding at end of period	6,910
Restricted Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Weighted average fair value on date of grant - Outstanding at beginning of period	$ 71.58
Weighted average fair value on date of grant - Granted	74.38
Weighted average fair value on date of grant - Vested	63.63
Weighted average fair value on date of grant - Forfeited	71.39
Weighted average fair value on date of grant - Outstanding at end of period	$ 75.32	$ 71.58
Awards - Outstanding at beginning of period	2,901
Awards - Granted	1,131
Awards - Vested	(921)
Awards - Forfeited	(291)
Awards - Outstanding at end of period	2,820	2,901
Vesting period from date of grant, in years	3 years
Stock Options
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Weighted average exercise price per share - Outstanding at beginning of period	$ 66.79
Weighted average exercise price per share - Granted	74.49
Weighted average exercise price per share - Exercised	48.51
Weighted average exercise price per share - Forfeited	79.29
Weighted average exercise price per share - Outstanding at end of period	$ 67.77	$ 66.79
Options - Outstanding at beginning of period	6,766
Options - Granted	521
Options - Exercised	(244)
Options - Forfeited	(132)
Options - Outstanding at end of period	6,911	6,766
Vesting period from date of grant, in years	3 years
Performance Share Units
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Weighted average fair value on date of grant - Outstanding at beginning of period	$ 89.91
Weighted average fair value on date of grant - Granted	76.64
Weighted average fair value on date of grant - Vested	72.93
Weighted average fair value on date of grant - Forfeited	97.16
Weighted average fair value on date of grant - Outstanding at end of period	$ 89.43	$ 89.91
Awards - Outstanding at beginning of period	800
Awards - Granted	366
Awards - Vested	(288)
Awards - Forfeited	(58)
Awards - Outstanding at end of period	820	800
Vesting period from date of grant, in years	3 years

Share-based Compensation - Weig

Share-based Compensation - Weighted Average Assumptions Utilized to Estimate the Fair Value of Stock Options (Detail) - Stock Options - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Risk free interest rate	1.77%	1.86%	0.00%
Stock price volatility	0.312%	0.363%	0.00%
Dividend yield	1.34%	1.24%	0.00%
Expected life in years	6 years	6 years	0 years
Weighted average fair value per option granted	$ 21	$ 26.46	$ 0

Share-based Compensation - We73

Share-based Compensation - Weighted Average Assumptions Utilized to Estimate Fair Value of PSU Awards (Detail) - Performance Share Units - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Risk free interest rate	1.02%	0.65%	0.36%
Stock price volatility	0.27%	0.359%	0.359%
Contractual term in years	3 years	3 years	3 years
Grant date price of Hess common stock	$ 74.49	$ 80.35	$ 69.49

Retirement Plans - Additional I

Retirement Plans - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Information on postretirement medical plan		Additionally, we maintain an unfunded postretirement medical plan that provides health benefits to certain qualified retirees from ages 55 through 65.
Net asset value per fund share related to short-term investment funds		$ 1
Short-term investment funds valued - NAV		short-term investment funds that provide for daily investments and redemptions and are valued and carried at a $1 net asset value (NAV) per fund share
Budgeted contributions to funded pension plans for next year		$ 27
Expense for defined contribution plans		$ 28	$ 32	$ 41
Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Current target allocations for plan assets		50.00%
Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Current target allocations for plan assets		25.00%
Other Types of Investments
Defined Benefit Plan Disclosure [Line Items]
Current target allocations for plan assets		25.00%
Scenario Forecast
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	$ 71
Amortization of unrecognized net actuarial losses	$ 64
Funded and Unfunded Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation		$ 2,223	2,325
Net periodic benefit cost		94	53	88
Amortization of unrecognized net actuarial losses		75	32	$ 61
Unfunded Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation		$ 196	$ 214

Retirement Plans - Change in Be

Retirement Plans - Change in Benefit Obligation, Fair Value of Plan Assets, and Funded Status of Pension Plans and Postretirement Medical Plan (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Change in fair value of plan assets
Beginning balance	$ 2,251
Ending balance	2,206	$ 2,251
Funded Pension Plans
Change in benefit obligation
Beginning balance	2,450	1,957
Service cost	51	45
Interest cost	93	91
Actuarial (gain) loss	(156)	470
Benefit payments	(85)	(77)
Plan curtailments	(4)	(3)
Special termination benefits	1	2
Foreign currency exchange rate changes	(29)	(35)
Ending balance	2,321	2,450	$ 1,957
Change in fair value of plan assets
Beginning balance	2,251	2,145
Actual return on plan assets	28	151
Employer contributions	44	68
Benefit payments	(85)	(77)
Foreign currency exchange rate changes	(32)	(36)
Ending balance	2,206	2,251	2,145
Funded status (plan assets greater (less) than benefit obligations) at December 31	(115)	(199)
Unrecognized net actuarial (gains) losses	775	859
Unfunded Pension Plan
Change in benefit obligation
Beginning balance	278	253
Service cost	16	12
Interest cost	9	9
Actuarial (gain) loss	(2)	61
Benefit payments	(42)	(57)
Plan curtailments	0	0
Special termination benefits	0	0
Foreign currency exchange rate changes	0	0
Ending balance	259	278	253
Change in fair value of plan assets
Beginning balance	0	0
Actual return on plan assets	0	0
Employer contributions	42	57
Benefit payments	(42)	(57)
Foreign currency exchange rate changes	0	0
Ending balance	0	0	0
Funded status (plan assets greater (less) than benefit obligations) at December 31	(259)	(278)
Unrecognized net actuarial (gains) losses	105	135
Postretirement Medical Plan
Change in benefit obligation
Beginning balance	94	97
Service cost	4	4	4
Interest cost	3	3	3
Actuarial (gain) loss	5	(4)
Benefit payments	(8)	(6)
Plan curtailments	0	0
Special termination benefits	0	0
Foreign currency exchange rate changes	0	0
Ending balance	98	94	97
Change in fair value of plan assets
Beginning balance	0	0
Actual return on plan assets	0	0
Employer contributions	8	6
Benefit payments	(8)	(6)
Foreign currency exchange rate changes	0	0
Ending balance	0	0	$ 0
Funded status (plan assets greater (less) than benefit obligations) at December 31	(98)	(94)
Unrecognized net actuarial (gains) losses	$ 0	$ (5)

Retirement Plans - Change in 76

Retirement Plans - Change in Benefit Obligation, Fair Value of Plan Assets, and Funded Status of Pension Plans and Postretirement Medical Plan (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Lump-sum settlement payment included in Benefit payments	$ 41	$ 55
Change in Discount Rate
Defined Benefit Plan Disclosure [Line Items]
Actuarial (gain) loss resulted from a change		330
Change in Mortality Assumptions
Defined Benefit Plan Disclosure [Line Items]
Actuarial (gain) loss resulted from a change		$ 125

Retirement Plans - Amounts Reco

Retirement Plans - Amounts Recognized in Consolidated Balance Sheet (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Funded Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Pension asset / (accrued benefit liability)	$ (115)	$ (199)
Accumulated other comprehensive (gain) loss, pre-tax	775	859
Unfunded Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Pension asset / (accrued benefit liability)	(259)	(278)
Accumulated other comprehensive (gain) loss, pre-tax	105	135
Postretirement Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Pension asset / (accrued benefit liability)	(98)	(94)
Accumulated other comprehensive (gain) loss, pre-tax	$ 0	$ (5)

Retirement Plans - Amounts Re78

Retirement Plans - Amounts Recognized in Consolidated Balance Sheet (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Compensation And Retirement Disclosure [Abstract]
Accumulated other comprehensive (gain) loss related to retirement plans, after-tax	$ 563	$ 652

Retirement Plans - Components o

Retirement Plans - Components of Net Periodic Benefit Cost (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 67	$ 57	$ 73
Interest cost	102	100	89
Expected return on plan assets	(168)	(161)	(141)
Amortization of unrecognized net actuarial losses	75	32	61
Settlement loss	17	24	0
Curtailment loss	0	0	1
Special termination benefit recognized	1	1	5
Net periodic benefit cost	94	53	88
Postretirement Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	4	4	4
Interest cost	3	3	3
Expected return on plan assets	0	0	0
Amortization of unrecognized net actuarial losses	0	0	1
Settlement loss	0	0	0
Curtailment loss	0	0	0
Special termination benefit recognized	0	0	0
Net periodic benefit cost	$ 7	$ 7	$ 8

Retirement Plans - Actuarial As

Retirement Plans - Actuarial Assumptions Used for Pension Plans & Postretirement Medical Plan (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plans
Weighted average assumptions used to determine benefit obligations at December 31
Discount rate	4.10%	3.80%	4.60%
Rate of compensation increase	4.50%	5.00%	4.40%
Weighted average assumptions used to determine net periodic benefit cost for the years ended December 31
Discount rate	3.80%	4.60%	4.00%
Expected return on plan assets	7.50%	7.50%	7.50%
Rate of compensation increase	5.00%	4.40%	4.30%
Postretirement Medical Plan
Weighted average assumptions used to determine benefit obligations at December 31
Discount rate	3.50%	3.10%	3.60%
Initial health care trend rate	6.70%	6.80%	7.10%
Ultimate trend rate	4.50%	4.50%	4.60%
Year in which ultimate trend rate is reached	2,038	2,029	2,027

Retirement Plans - Fair Value o

Retirement Plans - Fair Value of Financial Assets of Funded Pension Plans (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	$ 2,206	$ 2,251
Cash and Short-term Investment Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	34	53
U.S. Equities (domestic)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	556	719
International Equities (non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	425	249
Global Equities (domestic and non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	219	228
Treasury and Government Issued - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	213	222
Government Related - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	7	8
Mortgage-backed Securities - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	176	148
Corporate - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	157	140
Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	216	302
Private Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	122	105
Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	64	60
Diversified Commodities Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	17	17
Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	729	822
Level 1 | Cash and Short-term Investment Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	6
Level 1 | U.S. Equities (domestic)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	556	719
Level 1 | International Equities (non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	159	72
Level 1 | Global Equities (domestic and non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	2	10
Level 1 | Treasury and Government Issued - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 1 | Government Related - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 1 | Mortgage-backed Securities - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 1 | Corporate - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	3
Level 1 | Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 1 | Private Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 1 | Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	12	12
Level 1 | Diversified Commodities Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	1,084	972
Level 2 | Cash and Short-term Investment Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	34	47
Level 2 | U.S. Equities (domestic)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 2 | International Equities (non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	266	177
Level 2 | Global Equities (domestic and non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	217	218
Level 2 | Treasury and Government Issued - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	213	222
Level 2 | Government Related - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	6	7
Level 2 | Mortgage-backed Securities - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	174	147
Level 2 | Corporate - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	157	137
Level 2 | Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 2 | Private Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 2 | Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 2 | Diversified Commodities Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	17	17
Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	393	457
Level 3 | Cash and Short-term Investment Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3 | U.S. Equities (domestic)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3 | International Equities (non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3 | Global Equities (domestic and non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3 | Treasury and Government Issued - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3 | Government Related - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	1	1
Level 3 | Mortgage-backed Securities - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	2	1
Level 3 | Corporate - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3 | Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	216	302
Level 3 | Private Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	122	105
Level 3 | Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	52	48
Level 3 | Diversified Commodities Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	$ 0	$ 0

Retirement Plans - Changes in F

Retirement Plans - Changes in Financial Assets that are Measured at Fair Value Based on Level 3 Inputs that are held by Institutional Funds (Detail) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Beginning balance	$ 457	$ 430
Actual return on plan assets	22	24
Purchases, sales or other settlements	(86)	3
Net transfers in (out) of Level 3	0	0
Ending balance	393	457
Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Beginning balance	2	3
Actual return on plan assets	0	0
Purchases, sales or other settlements	1	(1)
Net transfers in (out) of Level 3	0	0
Ending balance	3	2
Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Beginning balance	302	291
Actual return on plan assets	(5)	9
Purchases, sales or other settlements	(81)	2
Net transfers in (out) of Level 3	0	0
Ending balance	216	302
Private Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Beginning balance	105	89
Actual return on plan assets	18	15
Purchases, sales or other settlements	(1)	1
Net transfers in (out) of Level 3	0	0
Ending balance	122	105
Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Beginning balance	48	47
Actual return on plan assets	9	0
Purchases, sales or other settlements	(5)	1
Net transfers in (out) of Level 3	0	0
Ending balance	$ 52	$ 48

Retirement Plans - Estimated Fu

Retirement Plans - Estimated Future Benefit Payments for Funded and Unfunded Pension Plans and Postretirement Medical Plan (Detail) $ in Millions	Dec. 31, 2015USD ($)
Compensation And Retirement Disclosure [Abstract]
2,016	$ 111
2,017	117
2,018	120
2,019	129
2,020	134
Years 2021 to 2025	$ 711

Exit and Disposal Costs - Addit

Exit and Disposal Costs - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restructuring And Related Activities [Abstract]
Severance expense	$ 13	$ 76	$ 252
Accrued severance costs paid	57	170	81
Exit related costs	15	65	220
Accrued facility and other exit costs paid	21	158	$ 102
Accrued exit related costs	19	25
Accrued severance costs	$ 33	$ 77
Expected period for all payments for severance cost	2,016
Expected period for all payments for facility and exit cost	Pay through 2027

Income Taxes - Components of In

Income Taxes - Components of Income Tax Provision (Benefit) for Continuing Operations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
United States - Federal, Current income tax expense (benefit)	$ (7)	$ (1)	$ 8
United States - Federal, Deferred income tax expense (benefit)	(995)	156	103
United States - State, Current & Deferred tax expense (benefit)	(61)	57	9
United States, Current & Deferred income tax expense (benefit)	(1,063)	212	120
Foreign, Current income tax expense (benefit)	4	453	941
Foreign, Deferred income tax expense (benefit)	(231)	79	186
Foreign, Current & Deferred income tax expense (benefit)	(227)	532	1,127
Provision (benefit) for income taxes - before adjustments due to income tax law changes	(1,290)	744	1,247
Adjustment of deferred taxes for foreign income tax law changes	(9)	0	(682)
Total provision (benefit) for income taxes	$ (1,299)	$ 744	$ 565

Income Taxes - Components of 86

Income Taxes - Components of Income Tax Provision (Benefit) for Continuing Operations (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Expense Benefit Continuing Operations [Line Items]
Effect of income tax law change	$ (9)	$ 0	$ (682)
Denmark
Income Tax Expense Benefit Continuing Operations [Line Items]
Effect of income tax law change			674
Norway
Income Tax Expense Benefit Continuing Operations [Line Items]
Effect of income tax law change	$ 9		$ 8

Income Taxes - Income (Loss) Fr

Income Taxes - Income (Loss) From Continuing Operations Before Income Taxes (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Income (Loss) From Continuing Operations Before Income Taxes - United States	$ (2,728)	$ 676	$ 580
Income (Loss) From Continuing Operations Before Income Taxes - Foreign	(1,530)	1,760	4,021
Income (Loss) From Continuing Operations Before Income Taxes	$ (4,258)	$ 2,436	$ 4,601

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Liabilities and Deferred Tax Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Deferred tax liabilities
Property, plant and equipment and investments	$ (3,743)	$ (4,226)
Other	(257)	(269)
Total deferred tax liabilities	(4,000)	(4,495)
Deferred tax assets
Net operating loss carryforwards	3,852	3,010
Tax credit carryforwards	188	193
Property, plant and equipment and investments	981	1,110
Accrued compensation, deferred credits and other liabilities	492	449
Asset retirement obligations	1,220	1,421
Other	165	261
Total deferred tax assets	6,898	6,444
Valuation allowances	(1,579)	(1,416)
Total deferred tax assets, net of valuation allowances	5,319	5,028
Net deferred tax assets	$ 1,319	$ 533

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Tax Examination [Line Items]
Gross deferred tax asset related to net operating loss carryforwards	$ 3,852	$ 3,010
Gross deferred tax asset related to foreign net operating loss carryforwards	$ 2,245
Year in which foreign net operating loss carryforwards begin to expire	2,025
Gross deferred tax asset related to net U.S. federal operating loss carryforwards	$ 1,394
Year in which U.S. federal net operating loss carryforwards begin to expire	2,020
Gross deferred tax asset related to net operating loss carryforwards for various U.S. states	$ 213
Year in which various U.S. states net operating loss carryforwards begin to expire	2,016
Deferred tax asset related to foreign net operating loss carryforwards, net of valuation allowance	$ 1,631
Deferred tax asset related to federal net operating loss carryforwards, net of valuation allowance	1,394
Deferred tax asset related to state net operating loss carryforwards, net of valuation allowance	63
Alternative minimum tax credit carryforwards	102
Other business credit carryforwards	1
Deferred tax asset related to business credit carryforwards, net of valuation allowance	54
Foreign tax credit carryforwards - Before valuation allowance	$ 85
Year in which foreign tax credit carryforwards begin to expire	2,016
Unrecognized tax benefits that would impact effective income tax rate	$ 529
Unrecognized tax benefits - Amounts due to lapses in statutes of limitation	4	0
Accrued interest and penalties	74	$ 62
Undistributed earnings from foreign subsidiaries expected to be indefinitely reinvested in foreign operations	7,700
Minimum
Income Tax Examination [Line Items]
Unrecognized tax benefits - Amounts due to lapses in statutes of limitation	109
Maximum
Income Tax Examination [Line Items]
Unrecognized tax benefits - Amounts due to lapses in statutes of limitation	$ 161

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Liabilities, Net (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Deferred income taxes (long-term asset)	$ 2,653	$ 2,371
Deferred income taxes (long-term liability)	(1,334)	(1,838)
Net deferred tax assets	$ 1,319	$ 533

Income Taxes - Effective Income

Income Taxes - Effective Income Tax Rate Reconciliation (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
U.S. statutory rate	35.00%	35.00%	35.00%
Effect of foreign operations	5.90%	0.70%	5.90%
State income taxes, net of Federal income tax	0.90%	1.50%	0.10%
Change in enacted tax laws	0.20%	0.00%	(14.80%)
Gains on asset sales, net	(0.20%)	(8.30%)	(15.60%)
Goodwill impairment	(12.20%)	0.00%	0.00%
Valuation allowance against previously benefitted deferred tax assets	(3.10%)	0.60%	1.00%
Benefit of legal entity restructuring	3.50%	0.00%	0.00%
Other	0.50%	1.00%	0.70%
Total	30.50%	30.50%	12.30%

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Beginning and Ending Amounts of Unrecognized Tax Benefits (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Balance at January 1	$ 603	$ 570
Additions based on tax positions taken in the current year	19	42
Additions based on tax positions of prior years	29	70
Reductions based on tax positions of prior years	(31)	(76)
Reductions due to settlements with taxing authorities	(12)	(3)
Reductions due to lapses in statutes of limitation	(4)	0
Balance at December 31	$ 604	$ 603

Outstanding and Weighted Aver93

Outstanding and Weighted Average Common Shares - Changes in Outstanding Common Shares (Detail) - shares	12 Months Ended			34 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015
Earnings Per Share [Abstract]
Balance at January 1	285,834,964	325,300,000	341,500,000
Activity related to restricted common stock awards, net	800,000	600,000	800,000
Stock options exercised	200,000	3,300,000	2,300,000
PSU vested	600,000	0	0
Shares repurchased	(1,450,000)	(43,350,000)	(19,310,000)	(64,110,000)
Balance at December 31	286,045,586	285,834,964	325,300,000	286,045,586

Outstanding and Weighted Aver94

Outstanding and Weighted Average Common Shares - Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Basic And Diluted Earnings Per Share [Line Items]
Income (loss) from continuing operations, net of income taxes	$ (2,959)	$ 1,692	$ 4,036
Less: Net income (loss) attributable to noncontrolling interests	49	0	176
Net income (loss) from continuing operations attributable to Hess Corporation	(3,008)	1,692	3,860
Income from discontinued operations, net of income taxes	(48)	682	1,186
Less: Net income (loss) attributable to noncontrolling interests	0	57	(6)
Income (loss) from discontinued operations attributable to Hess Corporation	(48)	625	1,192
Net Income (Loss) Attributable to Hess Corporation	$ (3,056)	$ 2,317	$ 5,052
Weighted Average Common Shares Outstanding:
Shares outstanding – Basic	283.6	303.7	336.6
Shares outstanding – Diluted	283.6	307.7	340.9
Net Income (Loss) Attributable to Hess Corporation Per Share – Basic :
Continuing operations	$ (10.61)	$ 5.57	$ 11.47
Discontinued operations	(0.17)	2.06	3.54
Net Income (Loss) Per Share	(10.78)	7.63	15.01
Net Income (Loss) Attributable to Hess Corporation Per Share – Diluted:
Continuing operations	(10.61)	5.50	11.33
Discontinued operations	(0.17)	2.03	3.49
Net Income (Loss) Per Share	$ (10.78)	$ 7.53	$ 14.82
Restricted Stock
Weighted Average Common Shares Outstanding:
Shares outstanding – Effect of dilutive securities	0	1.5	1.4
Antidilutive shares excluded from computation of diluted shares	2.9
Stock Options
Weighted Average Common Shares Outstanding:
Shares outstanding – Effect of dilutive securities	0	1.8	1.7
Antidilutive shares excluded from computation of diluted shares	6.9	1.4	4.4
Performance Share Units
Weighted Average Common Shares Outstanding:
Shares outstanding – Effect of dilutive securities	0	0.7	1.2
Antidilutive shares excluded from computation of diluted shares	1

Outstanding and Weighted Aver95

Outstanding and Weighted Average Common Shares - Additional Information (Detail) - $ / shares	3 Months Ended												12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Cash dividends on common stock	$ 0.25	$ 0.25	$ 0.25	$ 0.25	$ 0.25	$ 0.25	$ 0.25	$ 0.25	$ 0.25	$ 0.25	$ 0.10	$ 0.10	$ 1	$ 1	$ 0.70

Supplementary Cash Flow Infor96

Supplementary Cash Flow Information (Detail) - USD ($) $ in Millions	Jul. 02, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flows From Operating Activities
Interest paid		$ (331)	$ (326)	$ (408)
Income taxes paid, net of refunds		(140)	(455)	(1,353)
Cash Flows From Investing Activities
Capital expenditures incurred - E&P		(3,753)	(4,920)	(5,174)
(Increase) decrease in related liabilities – E&P		(203)	53	(239)
Additions to property, plant and equipment - E&P		(3,956)	(4,867)	(5,413)
Capital expenditures incurred - Bakken Midstream		(296)	(301)	(535)
(Increase) decrease in related liabilities – Bakken Midstream		(69)	(46)	11
Additions to property, plant and equipment - Bakken Midstream		(365)	(347)	(524)
Cash Flows From Financing Activities
Contribution from formation of Bakken Midstream joint venture	$ 2,628	2,628	0	0
Distributions to partner in Bakken Midstream joint venture		(332)	0	0
Noncontrolling interests, net related to Continuing operations		2,296	0	(182)
Significant Non-Cash Transactions
Increase in debt due to construction of a floating production system - Tubular Bells Field		0	68	116
Bakken Midstream
Cash Flows From Financing Activities
Noncontrolling interests, net related to Continuing operations		$ 2,296	$ 0	$ 0

Share Repurchase Plan - Additio

Share Repurchase Plan - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2015	May. 31, 2014	Dec. 31, 2013
Equity [Abstract]
Repurchase of outstanding common stock		$ 6,500	$ 4,000
Additional amount of common stock that may be repurchased	$ 1,150

Share Repurchase Plan - Schedul

Share Repurchase Plan - Schedule of Share Repurchases Under Share Repurchase Plan - (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended			34 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015
Equity [Abstract]
Total cost of shares repurchased	$ 91	$ 3,722	$ 1,538	$ 5,351
Total number of shares repurchased	1,450	43,350	19,310	64,110
Average cost per share (including transaction fees)	$ 62.76	$ 85.83	$ 79.65	$ 83.45

Leased Assets - Future Minimum

Leased Assets - Future Minimum Rental Payments (Detail) $ in Millions	Dec. 31, 2015USD ($)
Leases [Abstract]
2,016	$ 674
2,017	524
2,018	401
2,019	366
2,020	107
Remaining years	373
Total minimum lease payments	2,445
Less: Income from subleases	85
Net minimum lease payments	$ 2,360

Leased Assets - Rental Expense

Leased Assets - Rental Expense (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Leases [Abstract]
Total rental expense	$ 167	$ 248	$ 355
Less: Income from subleases	10	17	15
Net rental expense	$ 157	$ 231	$ 340

Guarantees, Contingencies an101

Guarantees, Contingencies and Commitments - Additional Information (Detail) - USD ($)	1 Months Ended		12 Months Ended
	Apr. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Jul. 25, 2011
Loss Contingencies [Line Items]
Contingent liabilities under letters of credit outstanding			$ 32,000,000	$ 54,000,000
N Y
Loss Contingencies [Line Items]
Estimated remedial design costs		$ 506,000,000
N J
Loss Contingencies [Line Items]
Estimated remedial design costs	$ 1,700,000,000
HOVENSA
Loss Contingencies [Line Items]
Interest in joint venture			50.00%
Settlement Agreement - U.S. Virgin Islands				3,500,000
Amount to be paid to U.S. Virgin Islands as per settlement agreement				$ 40,000,000
Debtor-in-possession, credit facility			$ 40,000,000
Claims settled as part of sale			40,000,000
Difference between estimated plan obligation and fair value of the asset plan			$ 30,000,000
Proposed total penalties related to violation of Virgin Islands Air Control laws					$ 210,000

Guarantees, Contingencies an102

Guarantees, Contingencies and Commitments - Schedule of Unconditional Purchase Obligations and Commitments (Detail) $ in Millions	Dec. 31, 2015USD ($)
Operating Expenses
Loss Contingencies [Line Items]
Total	$ 548
2,016	384
2017 and 2018	108
2019 and 2020	32
Thereafter	24
Capital Expenditures
Loss Contingencies [Line Items]
Total	1,750
2,016	1,503
2017 and 2018	247
Transportation and Related Contracts
Loss Contingencies [Line Items]
Total	1,598
2,016	121
2017 and 2018	453
2019 and 2020	433
Thereafter	$ 591

Segment Information - Additiona

Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015Segment
Segment Reporting [Abstract]
Number of operating segments for the Corporation	2

Segment Information - Financial

Segment Information - Financial Data by Operating Segment (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Operating Revenues	$ 6,636	$ 10,737	$ 11,905
Net income (loss) from continuing operations attributable to Hess Corporation	(3,008)	1,692	3,860
Interest expense	341	323	406
Depreciation, depletion and amortization	3,955	3,224	2,687
Impairment	1,616	0	289
Provision (benefit) for income taxes	(1,299)	744	565
Identifiable assets	34,195	38,407
Continuing Operations
Segment Reporting Information [Line Items]
Operating Revenues - Third parties	6,636	10,737	11,905
Intersegment Revenues	0	0	0
Operating Revenues	6,636	10,737	11,905
Net income (loss) from continuing operations attributable to Hess Corporation	(3,008)	1,692	3,860
Interest expense	341	323	406
Depreciation, depletion and amortization	3,955	3,224	2,687
Impairment	1,616		289
Provision (benefit) for income taxes	(1,299)	744	565
Investment in affiliates	154	151	506
Identifiable assets	34,195	37,249
Capital Expenditures	4,049	5,274	5,767
Continuing Operations | Exploration and Production
Segment Reporting Information [Line Items]
Operating Revenues - Third parties	6,636	10,737	11,762
Intersegment Revenues	0	0	125
Operating Revenues	6,636	10,737	11,887
Net income (loss) from continuing operations attributable to Hess Corporation	(2,717)	2,086	4,439
Interest expense	0	0	0
Depreciation, depletion and amortization	3,852	3,140	2,638
Impairment	1,616		289
Provision (benefit) for income taxes	(1,111)	989	912
Investment in affiliates	154	151	109
Identifiable assets	28,863	32,742
Capital Expenditures	3,753	4,920	5,174
Continuing Operations | Bakken Midstream
Segment Reporting Information [Line Items]
Operating Revenues - Third parties	0	0	143
Intersegment Revenues	564	319	127
Operating Revenues	564	319	270
Net income (loss) from continuing operations attributable to Hess Corporation	86	10	(136)
Interest expense	10	2	0
Depreciation, depletion and amortization	88	70	33
Impairment	0		0
Provision (benefit) for income taxes	52	7	(81)
Investment in affiliates	0	0	0
Identifiable assets	2,761	2,465
Capital Expenditures	296	301	535
Continuing Operations | Corporate, Interest and Other
Segment Reporting Information [Line Items]
Operating Revenues - Third parties	0	0	0
Intersegment Revenues	0	0	0
Operating Revenues	0	0	0
Net income (loss) from continuing operations attributable to Hess Corporation	(377)	(404)	(443)
Interest expense	331	321	406
Depreciation, depletion and amortization	15	14	16
Impairment	0		0
Provision (benefit) for income taxes	(240)	(252)	(266)
Investment in affiliates	0	0	397
Identifiable assets	2,571	2,042
Capital Expenditures	0	53	58
Continuing Operations | Eliminations
Segment Reporting Information [Line Items]
Operating Revenues - Third parties	0	0	0
Intersegment Revenues	(564)	(319)	(252)
Operating Revenues	(564)	(319)	(252)
Net income (loss) from continuing operations attributable to Hess Corporation	0	0	0
Interest expense	0	0	0
Depreciation, depletion and amortization	0	0	0
Impairment	0		0
Provision (benefit) for income taxes	0	0	0
Investment in affiliates	0	0	0
Identifiable assets	0	0
Capital Expenditures	$ 0	$ 0	$ 0

Segment Information - Financ105

Segment Information - Financial Information by Major Geographic Area (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Operating revenues		$ 6,636	$ 10,737	$ 11,905
Net income (loss) from continuing operations attributable to Hess Corporation		(3,008)	1,692	3,860
Depreciation, depletion and amortization		3,955	3,224	2,687
Impairments		1,616	0	289
Provision (benefit) for income taxes		(1,299)	744	565
Identifiable assets		34,195	38,407
Property, plant and equipment (net)		26,352	27,517
Continuing Operations
Segment Reporting Information [Line Items]
Operating revenues		6,636	10,737	11,905
Net income (loss) from continuing operations attributable to Hess Corporation		(3,008)	1,692	3,860
Depreciation, depletion and amortization		3,955	3,224	2,687
Impairments		1,616		289
Provision (benefit) for income taxes		(1,299)	744	565
Identifiable assets		34,195	37,249
Property, plant and equipment (net)	[1]	26,352	27,517
Capital expenditures		4,049	5,274	5,767
Continuing Operations | Corporate, Interest and Other
Segment Reporting Information [Line Items]
Operating revenues		0	0	0
Net income (loss) from continuing operations attributable to Hess Corporation		(377)	(404)	(443)
Depreciation, depletion and amortization		15	14	16
Impairments		0		0
Provision (benefit) for income taxes		(240)	(252)	(266)
Identifiable assets		2,571	2,042
Property, plant and equipment (net)	[1]	121	116
Capital expenditures		0	53	58
Continuing Operations | United States
Segment Reporting Information [Line Items]
Operating revenues		4,150	6,270	6,076
Net income (loss) from continuing operations attributable to Hess Corporation		(1,834)	654	777
Depreciation, depletion and amortization		2,449	1,751	1,393
Impairments		986		0
Provision (benefit) for income taxes		(522)	446	495
Identifiable assets		18,372	17,729
Property, plant and equipment (net)	[1]	15,729	15,595
Capital expenditures		2,727	3,467	3,613
Continuing Operations | Europe
Segment Reporting Information [Line Items]
Operating revenues		870	1,557	1,337
Net income (loss) from continuing operations attributable to Hess Corporation		(408)	226	2,051
Depreciation, depletion and amortization		635	683	484
Impairments		279		0
Provision (benefit) for income taxes		(84)	91	(646)
Identifiable assets		6,207	7,730
Property, plant and equipment (net)	[1]	5,300	6,339
Capital expenditures		297	524	689
Continuing Operations | Africa
Segment Reporting Information [Line Items]
Operating revenues		945	2,002	2,736
Net income (loss) from continuing operations attributable to Hess Corporation		(274)	545	594
Depreciation, depletion and amortization		539	487	518
Impairments		100		0
Provision (benefit) for income taxes		(48)	435	767
Identifiable assets		2,178	3,002
Property, plant and equipment (net)	[1]	1,682	2,235
Capital expenditures		160	399	578
Continuing Operations | Asia and Other Countries
Segment Reporting Information [Line Items]
Operating revenues		671	908	1,756
Net income (loss) from continuing operations attributable to Hess Corporation		(115)	671	881
Depreciation, depletion and amortization		317	289	276
Impairments		251		289
Provision (benefit) for income taxes		(405)	24	215
Identifiable assets		4,867	6,746
Property, plant and equipment (net)	[1]	3,520	3,232
Capital expenditures		$ 865	$ 831	$ 829
[1]	Of the total Europe, Property, plant and equipment (net), Norway represented $4,108 million in 2015 (2014: $5,246 million).

Segment Information - Financ106

Segment Information - Financial Information by Major Geographic Area (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Property, plant and equipment, net	$ 26,352	$ 27,517
Norway
Segment Reporting Information [Line Items]
Property, plant and equipment, net	$ 4,108	$ 5,246

Related Party Transactions - Re

Related Party Transactions - Related Party Transactions (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
HOVENSA
Related Party Transaction [Line Items]
Sales	$ 31	$ 90
Joint Venture Interest in Bayonne Energy Center
Related Party Transaction [Line Items]
Purchases		38
WilcoHess
Related Party Transaction [Line Items]
Sales	$ 211	$ 2,828

Related Party Transactions -108

Related Party Transactions - Related Party Transactions (Parenthetical) (Detail) - USD ($) $ in Millions	1 Months Ended
	Jan. 31, 2014	Dec. 31, 2014
Related Party Transactions [Abstract]
Percentage of interest in WilcoHess acquired for preparation of its subsequent sale with retail business	56.00%	56.00%
Cost of acquiring additional ownership interest in WilcoHess	$ 290

Financial Risk Management Ac109

Financial Risk Management Activities - Gross Notional Volumes of Derivative Contracts Outstanding (Detail) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Foreign Exchange
Derivative [Line Items]
Outstanding gross notional amount, in USD	$ 967,000,000	$ 1,189,000,000
Interest Rate Swaps
Derivative [Line Items]
Outstanding gross notional amount, in USD	$ 1,300,000,000	$ 1,300,000,000

Financial Risk Management Ac110

Financial Risk Management Activities - Gross and Net Fair Values (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accounts Receivable
Derivatives Fair Value [Line Items]
ASSETS – Gross fair value of derivative contracts	$ 22	$ 68
ASSETS – Master netting arrangements	(3)
ASSETS – Net fair value of derivative contracts	19	68
Accounts Receivable | Designated As Hedging Instrument
Derivatives Fair Value [Line Items]
ASSETS – Gross fair value of derivative contracts	3	39
Accounts Receivable | Designated As Hedging Instrument | Interest Rate Contract
Derivatives Fair Value [Line Items]
ASSETS – Gross fair value of derivative contracts	3	39
Accounts Receivable | Derivative Contracts Not Designated as Hedging Instruments
Derivatives Fair Value [Line Items]
ASSETS – Gross fair value of derivative contracts	19	29
Accounts Receivable | Derivative Contracts Not Designated as Hedging Instruments | Foreign Exchange
Derivatives Fair Value [Line Items]
ASSETS – Gross fair value of derivative contracts	19	29
Accounts Payable
Derivatives Fair Value [Line Items]
LIABILITIES – Gross fair value of derivative contracts	(3)	0
LIABILITIES – Master netting arrangements	3
LIABILITIES – Net fair value of derivative contracts	0	0
Accounts Payable | Designated As Hedging Instrument
Derivatives Fair Value [Line Items]
LIABILITIES – Gross fair value of derivative contracts	0	0
Accounts Payable | Designated As Hedging Instrument | Interest Rate Contract
Derivatives Fair Value [Line Items]
LIABILITIES – Gross fair value of derivative contracts	0	0
Accounts Payable | Derivative Contracts Not Designated as Hedging Instruments
Derivatives Fair Value [Line Items]
LIABILITIES – Gross fair value of derivative contracts	(3)	0
Accounts Payable | Derivative Contracts Not Designated as Hedging Instruments | Foreign Exchange
Derivatives Fair Value [Line Items]
LIABILITIES – Gross fair value of derivative contracts	$ (3)	$ 0

Financial Risk Management Ac111

Financial Risk Management Activities - Corporate Financial Risk Management Activities - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commodity
Derivative Instruments Gain Loss [Line Items]
Crude oil price hedging contracts increased (decreased) E&P sales and other operating revenues by this amount, pre-tax	$ 126,000,000	$ 193,000,000	$ 39,000,000
Other operating revenue, losses associated with changes in time value of crude oil collars	(48,000,000)
Interest Rate Swaps
Derivative Instruments Gain Loss [Line Items]
Outstanding gross notional amount, in USD	1,300,000,000	1,300,000,000
Amount of cash proceeds received from settled interest rate swaps	41,000,000
Change in the fair value of interest rate swaps - increase/(decrease)	4,000,000	1,000,000	(35,000,000)
Foreign Exchange
Derivative Instruments Gain Loss [Line Items]
Outstanding gross notional amount, in USD	967,000,000	1,189,000,000
Total foreign exchange gains and (losses) reported in Other, net in Revenues and Non-Operating Income in the Statement of Consolidated Income	(21,000,000)	(43,000,000)	(54,000,000)
Gain (Loss) on foreign exchange contracts not designated as hedging instruments	98,000,000	117,000,000	(39,000,000)
After tax foreign currency translation adjustments included in Accumulated other comprehensive income (loss)	(344,000,000)	(756,000,000)	$ (164,000,000)
Accumulated cumulative currency translation adjustment	$ (1,101,000,000)	$ (757,000,000)

Financial Risk Management Ac112

Financial Risk Management Activities - Trading Activities - Additional Information (Detail) $ in Millions	Dec. 31, 2015USD ($)
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Guarantee liability associated with HETCO - included in Other accrued liabilities	$ 10

Financial Risk Management Ac113

Financial Risk Management Activities - Credit Risk - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value Concentration Of Risk Financial Statement Captions [Line Items]
Outstanding letters of credit	$ 113	$ 397
Discontinued Operations
Fair Value Concentration Of Risk Financial Statement Captions [Line Items]
Outstanding letters of credit		$ 240
Government [Member] | Continuing Operations
Fair Value Concentration Of Risk Financial Statement Captions [Line Items]
Accounts receivable - Trade	18.00%
Other [Member] | Continuing Operations
Fair Value Concentration Of Risk Financial Statement Captions [Line Items]
Accounts receivable - Trade	14.00%
Integrated Oil Companies | Continuing Operations
Fair Value Concentration Of Risk Financial Statement Captions [Line Items]
Accounts receivable - Trade	58.00%
Financial Institutions | Continuing Operations
Fair Value Concentration Of Risk Financial Statement Captions [Line Items]
Accounts receivable - Trade	10.00%

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail) - USD ($)	1 Months Ended	12 Months Ended
	Feb. 29, 2016	Dec. 31, 2015
Subsequent Event
Subsequent Event [Line Items]
Net proceeds from issuance of common stock and Mandatory convertible preferred stock, after deducting underwriting discounts, commissions, and estimated offering expenses	$ 1,600,000,000
Subsequent Event | Minimum
Subsequent Event [Line Items]
Number of shares issued for each share of convertible preferred stock that is converted	21.822
Subsequent Event | Maximum
Subsequent Event [Line Items]
Number of shares issued for each share of convertible preferred stock that is converted	25.642
Subsequent Event | Final Average Price, $45.83 or less
Subsequent Event [Line Items]
Value of capped call transaction	$ 0
Subsequent Event | Final Average Price, $53.625 or higher
Subsequent Event [Line Items]
Value of capped call transaction	$ 98,000,000
Subsequent Event | Final Average Price between $45.83 and $53.625
Subsequent Event [Line Items]
Number of shares multiplied by difference between the Final Average Price	12,550,000
Subsequent Event | Common Stock
Subsequent Event [Line Items]
Shares of stock issued	28,750,000
Subsequent Event | Series A Mandatory Convertible Preferred Stock
Subsequent Event [Line Items]
Shares of stock issued	575,000
Preferred stock, dividend rate, percentage	8.00%
Preferred stock, par value	$ 1
Preferred stock, liquidation preference per share	$ 1,000
HOVENSA
Subsequent Event [Line Items]
Difference between estimated plan obligation and fair value of the asset plan		$ 30,000,000

Schedule - VALUATION AND QUALIF

Schedule - VALUATION AND QUALIFYING ACCOUNTS (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Losses on Receivables
Valuation and Qualifying Accounts Disclosure [Line Items]
Beginning Balance	$ 13	$ 27	$ 34
Charged to Costs and Expenses	32		10
Deductions from Reserves	2	14	17
Ending Balance	43	13	27
Deferred Income Tax Valuation
Valuation and Qualifying Accounts Disclosure [Line Items]
Beginning Balance	1,416	1,519	1,282
Charged to Costs and Expenses	280	142	383
Charged to Other Accounts		(1)	(17)
Deductions from Reserves	118	244	129
Ending Balance	$ 1,578	$ 1,416	$ 1,519