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Document and Entity Information	6 Months Ended
Document and Entity Information	Jun. 30, 2018 shares
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q2
Trading Symbol	HES
Entity Registrant Name	HESS CORP
Entity Central Index Key	0000004447
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	299,688,199

Consolidated Balance Sheet - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 2,908	$ 4,847
Accounts receivable:
From contracts with customers	784	677
Joint venture and other	291	347
Inventories	231	232
Assets held for sale	421	0
Other current assets	59	54
Total current assets	4,694	6,157
Property, plant and equipment:
Total — at cost	32,040	32,504
Less: Reserves for depreciation, depletion, amortization and lease impairment	16,171	16,312
Property, plant and equipment — net	15,869	16,192
Goodwill	360	360
Deferred income taxes	18	21
Other assets	523	382
Total Assets	21,464	23,112
Current Liabilities:
Accounts payable	363	435
Accrued liabilities	1,446	1,337
Taxes payable	49	83
Current maturities of long-term debt	87	580
Total current liabilities	1,945	2,435
Long-term debt	6,352	6,397
Deferred income taxes	424	429
Asset retirement obligations	773	753
Other liabilities and deferred credits	634	744
Total Liabilities	10,128	10,758
Hess Corporation stockholders’ equity:
Preferred stock, par value $1.00; Authorized — 20,000,000 shares, Series A 8% Cumulative Mandatory Convertible; $1,000 per share liquidation preference; Issued — 575,000 shares (2017: 575,000)	1	1
Common stock, par value $1.00; Authorized — 600,000,000 shares Issued — 299,688,199 shares (2017: 315,053,615)	300	315
Capital in excess of par value	5,501	5,824
Retained earnings	4,692	5,597
Accumulated other comprehensive income (loss)	(522)	(686)
Total Hess Corporation stockholders’ equity	9,972	11,051
Noncontrolling interests	1,364	1,303
Total equity	11,336	12,354
Total Liabilities and Equity	$ 21,464	$ 23,112

Consolidated Balance Sheet (Parenthetical) - $ / shares	6 Months Ended	12 Months Ended
Consolidated Balance Sheet (Parenthetical) - $ / shares	Jun. 30, 2018	Dec. 31, 2017
Statement Of Financial Position [Abstract]
Preferred stock, par value	$ 1.00	$ 1.00
Preferred stock, shares authorized	20,000,000	20,000,000
Preferred stock, shares issued	575,000	575,000
Preferred stock, liquidation preference per share	$ 1,000	$ 1,000
Series A, cumulative mandatory convertible preferred stock - dividend rate	8.00%	8.00%
Common stock, par value	$ 1.00	$ 1.00
Common stock, shares authorized	600,000,000	600,000,000
Common stock, shares issued	299,688,199	315,053,615

Statement of Consolidated Income - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenues and Non-Operating Income
Sales and other operating revenues	$ 1,534	$ 1,197	$ 2,880	$ 2,455
Gains on asset sales, net	11	2	18	2
Other, net	21	3	58	(1)
Total revenues and non-operating income	1,566	1,202	2,956	2,456
Costs and Expenses
Marketing, including purchased oil and gas	450	253	808	453
Operating costs and expenses	288	374	576	732
Production and severance taxes	42	30	81	61
Exploration expenses, including dry holes and lease impairment	62	52	102	110
General and administrative expenses	129	95	239	190
Interest expense	98	82	201	166
Loss on debt extinguishment	26	0	53	0
Depreciation, depletion and amortization	444	741	861	1,478
Total costs and expenses	1,539	1,627	2,921	3,190
Income (Loss) Before Income Taxes	27	(425)	35	(734)
Provision (benefit) for income taxes	114	(8)	187	(21)
Net Income (Loss)	(87)	(417)	(152)	(713)
Less: Net income (loss) attributable to noncontrolling interests	43	32	84	60
Net Income (Loss) Attributable to Hess Corporation	(130)	(449)	(236)	(773)
Less: Preferred stock dividends	12	11	23	23
Net Income (Loss) Attributable to Hess Corporation Common Stockholders	$ (142)	$ (460)	$ (259)	$ (796)
Net Income (Loss) Attributable to Hess Corporation Per Common Share:
Basic	$ (0.48)	$ (1.46)	$ (0.85)	$ (2.53)
Diluted	$ (0.48)	$ (1.46)	$ (0.85)	$ (2.53)
Weighted Average Number of Common Shares Outstanding (Diluted)	297.5	314.4	303.5	314.2
Common Stock Dividends Per Share	$ 0.25	$ 0.25	$ 0.50	$ 0.50

Statement of Consolidated Comprehensive Income - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Statement Of Income And Comprehensive Income [Abstract]
Net Income (Loss)	$ (87)	$ (417)	$ (152)	$ (713)
Derivatives designated as cash flow hedges
Effect of hedge (gains) losses reclassified to income	49	(20)	80	(20)
Income taxes on effect of hedge (gains) losses reclassified to income	0	0	0	0
Net effect of hedge (gains) losses reclassified to income	49	(20)	80	(20)
Change in fair value of cash flow hedges	(13)	72	(35)	76
Income taxes on change in fair value of cash flow hedges	0	2	0	0
Net change in fair value of cash flow hedges	(13)	74	(35)	76
Change in derivatives designated as cash flow hedges, after taxes	36	54	45	56
Pension and other postretirement plans
(Increase) reduction in unrecognized actuarial losses	5	(2)	130	5
Income taxes on actuarial changes in plan liabilities	(1)	1	(31)	(2)
(Increase) reduction in unrecognized actuarial losses, net	4	(1)	99	3
Amortization of net actuarial losses	9	23	21	40
Income taxes on amortization of net actuarial losses	0	0	0	0
Net effect of amortization of net actuarial losses	9	23	21	40
Change in pension and other postretirement plans, after taxes	13	22	120	43
Foreign currency translation adjustment
Foreign currency translation adjustment	0	73	0	87
Change in foreign currency translation adjustment	0	73	0	87
Other Comprehensive Income (Loss)	49	149	165	186
Comprehensive Income (Loss)	(38)	(268)	13	(527)
Less: Comprehensive income (loss) attributable to noncontrolling interests	43	32	84	60
Comprehensive Income (Loss) Attributable to Hess Corporation	$ (81)	$ (300)	$ (71)	$ (587)

Statement of Consolidated Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Cash Flows From Operating Activities
Net income (loss)	$ (152)	$ (713)
Adjustments to reconcile to net cash provided by (used in) operating activities
(Gains) losses on asset sales, net	(18)	(2)
Depreciation, depletion and amortization	861	1,478
Exploratory dry hole costs	13	0
Exploration lease and other impairment	20	15
Stock compensation expense	32	44
Noncash (gains) losses on commodity derivatives, net	85	30
Provision (benefit) for deferred income taxes and other tax accruals	(34)	(47)
Loss on debt extinguishment	53	0
Changes in operating assets and liabilities
(Increase) decrease in accounts receivable	(68)	119
(Increase) decrease in inventories	1	(52)
Increase (decrease) in accounts payable and accrued liabilities	(64)	(150)
Increase (decrease) in taxes payable	(34)	(35)
Changes in other operating assets and liabilities	(60)	(173)
Net cash provided by (used in) operating activities	635	514
Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P	(793)	(786)
Additions to property, plant and equipment - Midstream	(100)	(84)
Payments for Midstream equity investments	(41)	0
Proceeds from asset sales	33	179
Other, net	(5)	0
Net cash provided by (used in) investing activities	(906)	(691)
Cash Flows From Financing Activities
Net borrowings (repayments) of debt with maturities of 90 days or less	0	4
Debt with maturities of greater than 90 days – Borrowings	0	0
Debt with maturities of greater than 90 days – Repayments	(591)	(77)
Proceeds from issuance of Hess Midstream Partnership LP units	0	366
Common stock acquired and retired	(890)	0
Cash dividends paid	(176)	(182)
Noncontrolling interests, net	(23)	(175)
Other, net	12	1
Net cash provided by (used in) financing activities	(1,668)	(63)
Net Increase (Decrease) in Cash and Cash Equivalents	(1,939)	(240)
Cash and Cash Equivalents at Beginning of Year	4,847	2,732
Cash and Cash Equivalents at End of Period	$ 2,908	$ 2,492

Statement of Consolidated Equity - USD ($) $ in Millions	Total	Mandatory Convertible Preferred Stock	Common Stock	Capital in Excess of Par	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Total Hess Stockholders' Equity	Noncontrolling Interests
Balance at Dec. 31, 2016	$ 15,591	$ 1	$ 317	$ 5,773	$ 10,147	$ (1,704)	$ 14,534	$ 1,057
Cumulative effect of adoption of new accounting standards at Dec. 31, 2016	(37)	0	0	2	(39)	0	(37)	0
Net income (loss)	(713)	0	0	0	(773)	0	(773)	60
Other comprehensive income	186	0	0	0	0	186	186	0
Share-based compensation, including income taxes	52	0	1	51	0	0	52	0
Dividends on preferred stock	(23)	0	0	0	(23)	0	(23)	0
Dividends on common stock	(159)	0	0	0	(159)	0	(159)	0
Hess Midstream Partners LP units issuance	356	0	0	0	0	0	0	356
Noncontrolling interests, net	(175)	0	0	0	0	0	0	(175)
Balance at Jun. 30, 2017	15,078	1	318	5,826	9,153	(1,518)	13,780	1,298
Balance at Dec. 31, 2017	12,354	1	315	5,824	5,597	(686)	11,051	1,303
Cumulative effect of adoption of new accounting standards at Dec. 31, 2017	0	0	0	0	1	(1)	0	0
Net income (loss)	(152)	0	0	0	(236)	0	(236)	84
Other comprehensive income	165	0	0	0	0	165	165	0
Share-based compensation, including income taxes	48	0	1	47	0	0	48	0
Dividends on preferred stock	(23)	0	0	0	(23)	0	(23)	0
Dividends on common stock	(153)	0	0	0	(153)	0	(153)	0
Common stock acquired and retired	(880)	0	(16)	(370)	(494)	0	(880)	0
Noncontrolling interests, net	(23)	0	0	0	0	0	0	(23)
Balance at Jun. 30, 2018	$ 11,336	$ 1	$ 300	$ 5,501	$ 4,692	$ (522)	$ 9,972	$ 1,364

Basis of Presentation	6 Months Ended
Basis of Presentation	Jun. 30, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Basis of Presentation	1. Basis of Presentation The financial statements included in this report reflect all normal and recurring adjustments which, in the opinion of management, are necessary for a fair presentation of our consolidated financial position at June 30, 2018 and December 31, 2017, the consolidated results of operations for the three months and six months ended June 30, 2018 and 2017, and consolidated cash flows for the six months ended June 30, 2018 and 2017. The unaudited results of operations for the interim periods reported are not necessarily indicative of results to be expected for the full year. The financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (SEC) for interim reporting. As permitted under those rules, certain notes or other financial information that are normally required by generally accepted accounting principles (GAAP) in the United States have been condensed or omitted from these interim financial statements. These statements, therefore, should be read in conjunction with the consolidated financial statements and related notes included in the Corporation’s Annual Report on Form 10-K for the year ended December 31, 2017. In the first quarter of 2018, we adopted Accounting Standards Codification (ASC) Topic, ASC 606, Revenue from Contracts with Customers, using the modified retrospective method. The adoption of this standard did not affect the timing of revenue recognition for our uncompleted contracts at January 1, 2018, and as a result, no cumulative effect adjustment to Retained earnings was recognized. Accounts receivables from contracts with customers is presented separately in the Consolidated Balance Sheet with the prior year balance recast to conform to the current period presentation. In addition, as the adoption of ASC 606 did not affect previous conclusions regarding our involvement as a principal versus agent in contracts with customers, there were no changes in presentation to the Statement of Consolidated Income. In the first quarter of 2018, we adopted Accounting Standards Update (ASU) 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This ASU prohibits the capitalization of the non-service cost components of net periodic benefit cost in connection with the production or construction of an asset. This provision was applied prospectively effective January 1, 2018. The provision requiring that non-service cost components of net periodic benefit cost to be presented separately from the service cost component in the Statement of Consolidated Income was applied retrospectively. We elected the practical expedient allowing the use of the amounts previously disclosed in the notes to our consolidated financial statements as the basis for applying this provision retrospectively as the capitalization of the non-service cost components of net periodic benefit cost was not material during the comparative periods. This resulted in a reclassification of $7 million and $9 million of expense from Operating costs and expenses, and General and administrative expenses to Other, net for the three months ended and six months ended June 30, 2017, respectively. In the first quarter of 2018, we adopted ASU 2017-12, Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities. This ASU makes certain targeted improvements to simplify the application of the existing hedge accounting guidance. The adoption of this ASU resulted in an increase to Retained earnings and a decrease in Accumulated other comprehensive income (loss) of $1 million to remove the cumulative effect of hedging ineffectiveness previously recognized in earnings for contracts designated as hedging instruments that were outstanding at January 1, 2018. In the first quarter of 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force). This ASU requires that the total change in cash and cash equivalents and restricted cash be reflected on the statement of cash flows. A reconciliation to the balance sheet is also required when cash and cash equivalents and restricted cash are not separately presented on the balance sheet or are presented in more than one line item on the balance sheet. The adoption of this ASU did not have a material impact on our Statement of Consolidated Cash Flows. In the first quarter of 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the FASB Emerging Issues Task Force). This ASU is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific classification issues for which current guidance is either unclear or is non-specific. The requirement that fees paid to third-parties and premiums incurred in connection with the repayment of debt be classified as financing cash outflows is among the classification issues addressed by this ASU. The adoption of this ASU did not have a material impact on our Statement of Consolidated Cash Flows. To conform with the Statement of Consolidated Income presentation in our December 31, 2017 Form 10-K, we have revised the presentation of Sales and other operating revenues and Marketing, including purchased oil and gas for the three months and six months ended June 30, 2017 associated with the recovery of certain natural gas processing costs from third-parties, by reducing each by $19 million and $38 million, respectively. This revision did not impact net income, our Consolidated Balance Sheet, Statement of Consolidated Comprehensive Income, Statement of Consolidated Cash Flows, nor Statement of Consolidated Equity. Amounts reported as Sales and other operating revenue and Marketing, including purchased oil and gas (formerly Costs of products sold) in our June 30, 2017 Form 10-Q were $1,216 million and $272 million, respectively, for the second quarter of 2017 and $2,493 million and $491 million, respectively, for the six months ended June 30, 2017. New Accounting Pronouncements: In February 2016, the FASB issued ASU 2016-02, Leases, as a new Accounting Standards Codification (ASC) Topic, ASC 842. The new standard will require assets and liabilities to be reported on the Consolidated Balance Sheet for all leases with lease terms greater than one year, including leases currently treated as operating leases under the existing standard. This ASU is effective for us beginning in the first quarter of 2019, with early adoption permitted. We have developed and are executing a project plan for the implementation of ASC 842 in the first quarter of 2019. We are progressing our assessment of existing leases and evaluating our disclosure processes with reference to the requirements of the standard. We continue to assess the impact of the ASU on our consolidated financial statements. In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses. This ASU makes changes to the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standard requires the use of a forward-looking "expected loss" model compared to the current "incurred loss" model. This ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted beginning in the first quarter of 2019. We are currently assessing the impact of the ASU on our consolidated financial statements. In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment. This ASU modifies the concept of goodwill impairment from a condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of the reporting unit exceeds its fair value. Thus, an entity should recognize an impairment charge for the amount by which the carrying amount of a reporting unit exceeds its fair value. The impairment charge would be limited by the amount of goodwill allocated to the reporting unit. This ASU removes the requirement to determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if the reporting unit had been acquired in a business combination. This ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted. We are currently assessing the impact of the ASU on our consolidated financial statements.

Revenue

6 Months Ended

Jun. 30, 2018

Revenue From Contract With Customer [Abstract]

Revenue

2. Revenue

Revenue from contracts with customers on a disaggregated basis was as follows:

	Exploration and Production												Midstream		Eliminations			Total
	United States			Europe		Africa		Asia		E&P Total
For the Three Months Ended June 30, 2018	(In millions)
Sales of our net production volumes:
Crude oil revenue	$	692		$	19	$	110	$	28	$	849		$	—	$	—		$	849
Natural gas liquids revenue		75			—		—		—		75			—		—			75
Natural gas revenue		37			2		7		165		211			—		—			211
Sales of purchased oil and gas		424			—		22		—		446			—		—			446
Intercompany revenue		—			—		—		—		—			176		(176	)		—
Total revenues from contracts with customers		1,228			21		139		193		1,581			176		(176	)		1,581
Other operating revenue (a)		(47	)		—		—		—		(47	)		—		—			(47	)
Total sales and other operating revenues	$	1,181		$	21	$	139	$	193	$	1,534		$	176	$	(176	)	$	1,534

(a)	Includes gains (losses) on commodity derivatives.

	Exploration and Production												Midstream		Eliminations			Total
	United States			Europe		Africa		Asia		E&P Total
For the Six Months Ended June 30, 2018	(In millions)
Sales of our net production volumes:
Crude oil revenue	$	1,285		$	52	$	209	$	71	$	1,617		$	—	$	—		$	1,617
Natural gas liquids revenue		146			—		—		—		146			—		—			146
Natural gas revenue		76			5		15		293		389			—		—			389
Sales of purchased oil and gas		749			—		46		14		809			—		—			809
Intercompany revenue		—			—		—		—		—			343		(343	)		—
Total revenues from contracts with customers		2,256			57		270		378		2,961			343		(343	)		2,961
Other operating revenue (a)		(81	)		—		—		—		(81	)		—		—			(81	)
Total sales and other operating revenues	$	2,175		$	57	$	270	$	378	$	2,880		$	343	$	(343	)	$	2,880

(a)	Includes gains (losses) on commodity derivatives.

Exploration and Production

The E&P segment recognizes revenue from the sale of crude oil, natural gas liquids (NGLs), and natural gas as performance obligations under contracts with customers are satisfied. Our responsibilities to deliver each unit of quantity of crude oil, NGL, and natural gas under these contracts represent separate, distinct performance obligations. These performance obligations are satisfied at the point in time control of each unit of quantity transfers to the customer. Generally, the control of each unit of quantity transfers to the customer upon the transfer of legal title at the point of physical delivery. Pricing is variable and is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials.

Our responsibility to stand-ready to provide a minimum volume over each commitment period under long-term international gas contracts with take-or-pay provisions represent separate, distinct performance obligations. Shortfall payments received from customers that occur when volumes purchased are below the minimum volume commitment under contracts with customer make-up rights are deferred upon receipt as a contract liability. Revenue is recognized at the earlier of when we deliver the make-up volumes in subsequent periods or when it becomes remote that the customer will exercise their make-up rights. Price discounts owed against future deliveries of international natural gas due to delivery of natural gas volumes below customer nominations are recognized as reductions to revenue in the commitment period when the shortfall occurs.

Certain crude oil, NGL, and natural gas volumes are purchased by Hess from third-parties, including working interest partners and royalty owners in certain Hess-operated properties, before they are sold to customers. Where control over the crude oil, NGLs, or natural gas transfers to Hess before the volumes are transferred to the customer, revenue and the associated cost of purchased volumes are presented on a gross basis in the Statement of Consolidated Income within Sales and other operating revenues and Marketing, including purchased oil and gas, respectively. Where control of crude oil, NGLs, or natural gas is not transferred to Hess, revenue is presented net of the associated cost of purchased volumes within Sales and other operating revenues in the Statement of Consolidated Income.

Contract types

The following is a summary of contract types for our E&P segment:

Crude oil, NGLs, and natural gas – United States (U.S.): Contracts with customers for the sale of U.S. crude oil, NGLs, and natural gas primarily include those contracts that involve the short-term sale of volumes during a specified period, and those contracts that automatically renew on a periodic basis until either party cancels. We have certain long-term contracts with customers for the sale of U.S. natural gas and NGLs that have remaining durations of less than ten years. Contracts may specify a fixed volume for delivery subject to tolerance thresholds or may specify a percentage of production to be delivered from a particular location. Pricing is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials.

Crude oil – International: Contracts with customers for the sale of international crude oil involve the short-term sale of volumes during a specified period. These contracts specify a fixed volume for delivery subject to tolerance thresholds. Pricing is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials, shortly after control of the volumes transfers to the customer.

Natural gas – International: Contracts with customers for the sale of natural gas are in the form of natural gas sales agreements with government entities that have durations that are aligned with the durations of production sharing contracts or other contractual arrangements with host governments. Pricing is determined using contractual formulas that are based on the price of alternative fuels as obtained from price indices and other factors. These contracts also specify a minimum volume we are obligated to make available during specified periods within the contract term and may specify minimum volumes the customer is obligated to purchase during specified periods within the contract term. If we do not deliver the volume properly nominated by the customer, the customer is entitled to a price discount on future volumes equivalent to the shortfall delivery. Under certain international natural gas sales agreements, if the customer purchases natural gas volumes below the minimum volume commitment, the customer is required to pay us for the shortfall volumes and may receive make-up volumes in subsequent periods at no additional cost.

Revenue from sale of third-party purchased volumes: Crude oil, NGLs, and natural gas are purchased by Hess from third-parties, including working interest partners and royalty owners in certain Hess-operated properties, before they are sold to customers. The types of contracts with customers for the sale of third-party purchased volumes are the same as those described above.

Contract Balances

Our right to receive or collect payment from the customer is aligned with the timing of revenue recognition except in situations when we receive shortfall payments under contracts with take-or-pay provisions with customer make-up rights. Shortfall payments received from customers under contracts with take-or-pay provisions with customer make-up rights are deferred upon receipt and reflected as a contract liability. At June 30, 2018 and December 31, 2017, there were no contract assets or contract liabilities.

Generally, we receive payments from customers on a monthly basis, shortly after the physical delivery of the crude oil, NGLs, or natural gas. In the three months and six months ended June 30, 2018, we did not recognize any impairment losses on receivables arising from contracts with customers.

Transaction Price Allocated to Remaining Performance Obligations

The transaction price allocated to our wholly unsatisfied performance obligations on uncompleted contracts is variable. Further, many of our contracts with customers have durations of less than twelve months. Accordingly, we have elected under the provisions of ASC 606 the exemption from disclosure of revenue recognizable in future periods as these performance obligations are satisfied.

Sales-based Taxes

We exclude sales-based taxes that are collected from customers from the transaction price in our contracts with customers. Accordingly, revenue from contracts with customers is net of sales-based taxes that are collected from customers and remitted to taxing authorities.

Midstream

Our Midstream segment provides gathering, compression, processing, fractionation, storage, terminaling, loading and transportation services.

The Midstream segment has multiple long-term, fee-based commercial agreements with a marketing subsidiary of Hess, each with an initial ten-year term that can be extended for an additional ten-year term at the unilateral right of our Midstream segment. These contracts have minimum volumes the customer is obligated to provide each calendar quarter. The minimum volume commitments are subject to fluctuation based on nominations covering substantially all of our E&P segment’s production and projected third-party volumes that will be purchased in the Bakken. As the minimum volume commitments are subject to fluctuation, and as these contracts contain fee inflation escalators and fee recalculation mechanisms, substantially all of the transaction price at contract inception is variable.

The Midstream segment’s responsibilities to provide each of the above services for each year under each of the commercial agreements are considered separate, distinct performance obligations. Revenue is recognized for each performance obligation under these commercial agreements over-time as services are rendered using the output method, measured using the amount of volumes serviced during the period. The Midstream segment has elected the practical expedient under the provisions of ASC 606 to recognize revenue in the amount it is entitled to invoice. If the commercial agreements have take-or-pay provisions, the Midstream segment’s responsibility to stand-ready to service a minimum volume over each quarterly commitment period represent separate, distinct performance obligations. Shortfall payments received under take-or-pay provisions are recognized as revenue in the calendar quarter the shortfall occurs as the customer does not have make-up rights beyond the calendar quarter end of the quarterly commitment period. All revenues, receivables, and contract balances arising from the commercial agreements between the Midstream segment and the Hess marketing subsidiary that is the counterparty to the commercial agreements are eliminated upon consolidation.

Common Stock Repurchase Program	6 Months Ended
Common Stock Repurchase Program	Jun. 30, 2018
Equity [Abstract]
Common Stock Repurchase Program	3. Common Stock Repurchase Program In the first quarter, we repurchased $380 million of common stock as part of our $1.5 billion share repurchase program. In the second quarter of 2018, we repurchased $500 million of common stock, through an accelerated share repurchase transaction (ASR) with a financial institution. Under the terms of the ASR, we paid $500 million in cash to the financial institution and received approximately 8.5 million shares of our common stock as determined by the volume-weighted average price of the shares during the term of the agreement less an agreed settlement price adjustment. As of June 30, 2018, the Corporation has repurchased $1.0 billion of common stock (19.2 million shares) under its $1.5 billion share repurchase program. We plan to purchase the remaining $500 million of shares during the second half of 2018, and are targeting approximately $250 million of purchases in the third quarter and approximately $250 million in the fourth quarter.

Debt	6 Months Ended
Debt	Jun. 30, 2018
Debt Disclosure [Abstract]
Debt	4. Debt In the first quarter of 2018, we paid $415 million to redeem $350 million principal amount of 8.125% notes due 2019 and to purchase other notes with a carrying value of $38 million. Concurrent with the redemption of the 2019 notes, we terminated interest rate swaps with a notional amount of $350 million. In the second quarter of 2018, we paid $138 million to purchase notes with a carrying value of $112 million. As a result, we recorded losses on debt extinguishment of $26 million ($26 million after income taxes) and $53 million ($53 million after income taxes) in the three and six months ended June 30, 2018, respectively.

Inventories

6 Months Ended

Jun. 30, 2018

Inventory Disclosure [Abstract]

Inventories

5. Inventories

Inventories consisted of the following:

	June 30,		December 31,
	2018		2017
	(In millions)
Crude oil and natural gas liquids	$	58	$	59
Materials and supplies		173		173
Total Inventories	$	231	$	232

Property, Plant and Equipment

6 Months Ended

Jun. 30, 2018

Property Plant And Equipment [Abstract]

Property, Plant and Equipment

6. Property, Plant and Equipment

Assets Held For Sale: At June 30, 2018, assets classified as “held for sale”, which comprised primarily of net property, plant and equipment, totaled $421 million and related to our joint venture interests in the Utica shale play in eastern Ohio ($365 million) and non-core acreage in North Dakota ($56 million). In addition, liabilities associated with the Utica shale play, which amounted to $2 million, were reported in Accrued liabilities in the Consolidated Balance Sheet.

Capitalized Exploratory Well Costs: The following table discloses the net changes in capitalized exploratory well costs pending determination of proved reserves during the six months ended June 30, 2018 (in millions):

Balance at January 1, 2018	$	304
Additions to capitalized exploratory well costs pending the determination of proved reserves		127
Balance at June 30, 2018	$	431

We expensed $13 million of exploratory wells costs incurred during 2018 that are not reflected in the table above. These costs relate to the Sorubim-1 well on the Stabroek Block, offshore Guyana and the Bunga Teruntum-1 well in the North Malay Basin, where commercial quantities of hydrocarbons were not encountered. Capitalized exploratory well costs capitalized for greater than one year following completion of drilling were $239 million at June 30, 2018 and primarily related to:

Gulf of Mexico: Approximately 50% of the capitalized well costs in excess of one year relates to the appraisal of the northern portion of the Shenzi Field (Hess 28% participating interest) in the Gulf of Mexico, where hydrocarbons were encountered in the fourth quarter of 2015. The operator is conducting appraisal activities on adjacent acreage and is evaluating plans for development of the northern portion of the Shenzi Field.

Guyana: Approximately 30% of the capitalized well costs in excess of one year primarily relates to the Liza-4 and Payara-1 wells on the Stabroek Block, offshore Guyana (Hess 30% participating interest), where hydrocarbons were encountered. The operator plans to integrate the Liza-4 discovery into the second phase of development, which is expected to be sanctioned in 2018. The operator plans to integrate the Payara-1 discovery into the third phase of development, which is expected to be sanctioned in 2019.

JDA: Approximately 20% of the capitalized well costs in excess of one year relates to the JDA in the Gulf of Thailand (Hess 50%) where hydrocarbons were encountered in three successful exploration wells drilled in the western part of Block A-18. The operator is currently conducting subsurface evaluations and pre-development planning to facilitate commercial negotiations with the regulator for an extension of the existing gas sales contract to include development of the western part of the Block.

Hess Infrastructure Partners LP	6 Months Ended
Hess Infrastructure Partners LP	Jun. 30, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Hess Infrastructure Partners LP	7. Hess Infrastructure Partners LP We consolidate the activities of Hess Infrastructure Partners LP (HIP), a 50/50 joint venture between Hess Corporation and Global Infrastructure Partners (GIP), which qualifies as a variable interest entity (VIE) under U.S. GAAP. 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. HIP, which owns Bakken midstream assets, is a component of our Midstream segment. At June 30, 2018, HIP liabilities totaling $1,104 million (December 31, 2017: $1,065 million) are on a nonrecourse basis to Hess Corporation, while HIP assets available to settle the obligations of HIP include cash and cash equivalents totaling $420 million (December 31, 2017: $356 million) and property, plant and equipment with a carrying value of $2,578 million (December 31, 2017: $2,520 million).

Severance Costs	6 Months Ended
Severance Costs	Jun. 30, 2018
Restructuring And Related Activities [Abstract]
Severance Costs	8. Severance Costs In the first six months of 2018, we recorded severance expense of $39 million and paid severance costs of $34 million as part of our previously announced cost reduction program. At June 30, 2018, we have accrued severance cost of $11 million (December 31, 2017: $6 million), which we expect to pay in 2018.

Retirement Plans

6 Months Ended

Jun. 30, 2018

Compensation And Retirement Disclosure [Abstract]

Retirement Plans

9. Retirement Plans

Components of net periodic pension cost consisted of the following:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
	(In millions)
Service cost	$	10		$	14		$	24		$	28
Interest cost		24			26			47			52
Expected return on plan assets		(49	)		(42	)		(98	)		(83	)
Amortization of unrecognized net actuarial losses		9			16			21			33
Curtailment gains		—			—			(2	)		—
Settlement loss		—			7			—			7
Pension (income) expense	$	(6	)	$	21		$	(8	)	$	37

In the first quarter of 2018, we recorded curtailment gains of $18 million to Accumulated other comprehensive income (loss) and $2 million to the Statement of Consolidated Income following workforce reductions. In connection with this curtailment, as required under accounting standards, we remeasured our U.S. retirement plans and recorded a total decrease of $125 million in the Corporation’s U.S. pension liabilities. This reduction was primarily driven by a change in weighted average discount rates used to measure the liabilities. There was no change to the weighted average expected long-term rate of return on plan assets.

For the full year 2018, we now forecast pension service costs of approximately $45 million and net non-service pension costs of approximately $60 million of income, which is comprised of interest cost of approximately $95 million, amortization of unrecognized net actuarial losses of approximately $40 million and estimated expected return on plan assets of approximately $195 million.

Net non-service pension costs included in Other, net in the Statement of Consolidated Income for the three and six months ended June 30, 2018 was income of $16 million and $32 million, respectively, compared to expenses of $7 million and $9 million for the three and six months ended June 30, 2017, respectively.

In 2018, we expect to contribute $47 million to our funded pension plans. In the six months ended June 30, 2018, we have contributed $25 million to these plans.

Weighted Average Common Shares

6 Months Ended

Jun. 30, 2018

Earnings Per Share [Abstract]

Weighted Average Common Shares

10. Weighted Average Common Shares

The Net income (loss) and weighted average number of common shares used in the basic and diluted earnings per share computations were as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
	(In millions)
Net income (loss) attributable to Hess Corporation Common Stockholders:
Net income (loss)	$	(87	)	$	(417	)	$	(152	)	$	(713	)
Less: Net income (loss) attributable to noncontrolling interests		43			32			84			60
Less: Preferred stock dividends		12			11			23			23
Net income (loss) attributable to Hess Corporation Common Stockholders	$	(142	)	$	(460	)	$	(259	)	$	(796	)

Weighted average number of common shares outstanding:
Basic	297.5	314.4	303.5	314.2
Effect of dilutive securities
Restricted common stock	—	—	—	—
Stock options	—	—	—	—
Performance share units	—	—	—	—
Mandatory convertible preferred stock	—	—	—	—
Diluted	297.5	314.4	303.5	314.2

The following table summarizes the number of antidilutive shares excluded from the computation of diluted shares:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2018		2017		2018		2017
Restricted common stock		2,849,465		3,450,490		2,885,890		3,288,356
Stock options		5,623,004		6,550,253		5,715,292		6,424,574
Performance share units		1,072,395		522,280		847,741		417,642
Common shares from conversion of preferred stocks		12,547,650		12,734,069		12,566,312		12,640,859

During the six months ended June 30, 2018, we granted 1,081,923 shares of restricted stock (2017: 1,209,247), 278,003 performance share units (2017: 438,980) and 683,167 stock options (2017: 662,819).

Guarantees and Contingencies	6 Months Ended
Guarantees and Contingencies	Jun. 30, 2018
Commitments And Contingencies Disclosure [Abstract]
Guarantees and Contingencies	11. Guarantees and Contingencies 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. We, along with many companies that have been or continue to be 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 was a defective product and that these producers and refiners 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. There are four remaining active cases, filed by Pennsylvania, Vermont, Rhode Island, and Maryland. 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. In September 2016, the State of Rhode Island also filed a lawsuit alleging that we and other major oil companies damaged the groundwater in Rhode Island by introducing thereto gasoline with MTBE. The suit filed in Rhode Island is proceeding in Federal court. In December 2017, the State of Maryland filed a lawsuit alleging that we and other major oil companies damaged the groundwater in Maryland by introducing thereto gasoline with MTBE. The suit filed in Maryland state court, was served on us in January 2018 and has been removed to federal court by the defendants. In September 2003, we received a directive from the New Jersey Department of Environmental Protection (NJDEP) to remediate contamination in the sediments of the Lower Passaic River. 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. On March 4, 2016, the EPA issued a Record of Decision (ROD) in respect of the lower eight miles of the Lower Passaic River, selecting a remedy that includes bank-to-bank dredging at an estimated cost of $1.38 billion. The ROD does not address the upper nine miles of the Lower Passaic River or the Newark Bay, 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 that the EPA has not selected a remedy for the entirety of the Lower Passaic River or the Newark Bay, total remedial costs cannot be reliably estimated at this time. Based on currently known facts and circumstances, we do not believe that this matter will result in a significant liability to us because our former terminal did not store or use contaminants which are of concern in the river sediments and could not have contributed contamination along the river’s length. Further, there are numerous other parties who we expect will bear the cost of remediation and damages. 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 and connected ship-building and repair facility 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 a neutral expert selected by the parties will determine the final shares of the Remedial Design costs to be paid by each of the participants. On September 28, 2017, we received a general notice letter and offer to settle from the U.S. Environmental Protection Agency relating to Superfund claims for the Ector Drum, Inc. Superfund Site in Odessa, TX. The EPA and Texas Commission on Environmental Quality (TCEQ) took clean-up and response action at the site commencing in 2014 and concluded in December 2015. The site was determined to have improperly stored industrial waste, including drums with oily liquids. The total clean-up cost incurred by the EPA was approximately $3.5 million. We were invited to negotiate a voluntary settlement for our purported share of the clean-up costs. Our share, if any, is undetermined. 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 the aforementioned proceedings are not expected to have a material adverse effect on our financial condition, results of operations or cash flows.

Segment Information

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

Segment Information

12. Segment Information

We currently have two operating segments, Exploration and Production, and Midstream. All unallocated costs are reflected under Corporate, Interest and Other. The following table presents operating segment financial data:

	Exploration and Production			Midstream		Corporate, Interest and Other			Eliminations			Total
	(In millions)
For the Three Months Ended June 30, 2018
Sales and Other Operating Revenues - Third-parties	$	1,534		$	—	$	—		$	—		$	1,534
Intersegment Revenues		—			176		—			(176	)		—
Sales and Other Operating Revenues	$	1,534		$	176	$	—		$	(176	)	$	1,534

Net Income (Loss) attributable to Hess Corporation	$	31		$	30	$	(191	)	$	—		$	(130	)
Depreciation, Depletion and Amortization		407			31		6			—			444
Provision (Benefit) for Income Taxes		105			9		—			—			114
Capital Expenditures		486			84		—			—			570

For the Three Months Ended June 30, 2017
Sales and Other Operating Revenues - Third-parties	$	1,194		$	3	$	—		$	—		$	1,197
Intersegment Revenues		—			154		—			(154	)		—
Sales and Other Operating Revenues	$	1,194		$	157	$	—		$	(154	)	$	1,197

Net Income (Loss) attributable to Hess Corporation	$	(354	)	$	16	$	(111	)	$	—		$	(449	)
Depreciation, Depletion and Amortization		708			32		1			—			741
Provision (Benefit) for Income Taxes		(14	)		10		(4	)		—			(8	)
Capital Expenditures		483			20		—			—			503

For the Six Months Ended June 30, 2018
Sales and Other Operating Revenues - Third-parties	$	2,880		$	—	$	—		$	—		$	2,880
Intersegment Revenues		—			343		—			(343	)		—
Sales and Other Operating Revenues	$	2,880		$	343	$	—		$	(343	)	$	2,880

Net Income (Loss) attributable to Hess Corporation	$	6		$	58	$	(300	)	$	—		$	(236	)
Depreciation, Depletion and Amortization		792			62		7			—			861
Provision (Benefit) for Income Taxes		200			18		(31	)		—			187
Capital Expenditures		840			121		—			—			961

For the Six Months Ended June 30, 2017
Sales and Other Operating Revenues - Third-parties	$	2,450		$	5	$	—		$	—		$	2,455
Intersegment Revenues		—			301		—			(301	)		—
Sales and Other Operating Revenues	$	2,450		$	306	$	—		$	(301	)	$	2,455

Net Income (Loss) attributable to Hess Corporation	$	(587	)	$	34	$	(220	)	$	—		$	(773	)
Depreciation, Depletion and Amortization		1,411			64		3			—			1,478
Provision (Benefit) for Income Taxes		(34	)		21		(8	)		—			(21	)
Capital Expenditures		825			48		—			—			873

Identifiable assets by operating segment were as follows:

	June 30,		December 31,
	2018		2017
	(In millions)
Exploration and Production	$	15,907	$	15,613
Midstream		3,488		3,329
Corporate, Interest and Other		2,069		4,170
Total	$	21,464	$	23,112

Financial Risk Management Activities

6 Months Ended

Jun. 30, 2018

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Financial Risk Management Activities

13. 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. 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. At June 30, 2018, these forward contracts relate to the British Pound. Interest rate swaps may be used to convert interest payments on certain long-term debt from fixed to floating rates.

We present gross notional amounts of both long and short positions in the table 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 notional amounts of outstanding financial risk management derivative contracts related to West Texas Intermediate (WTI) instruments as of the dates shown below were as follows:

	June 30, 2018				December 31, 2017
Calendar year program	2018		2019		2018
Instrument type	Puts		Puts		Collars
Effective date	Jul. 1, 2018		Jan. 1, 2019		Jan. 1, 2018
End date	Dec. 31, 2018		Dec. 31, 2019		Dec. 31, 2018
Crude oil volumes (millions of barrels)		21.2		7.3		42.0
Ceiling price	N/A		N/A		$	65
Floor price	$	50	$	60	$	50

At December 31, 2017, we had WTI crude oil price collars with an average monthly floor price of $50 per barrel and an average monthly ceiling price of $65 per barrel with a notional amount of 115,000 bopd for the full year 2018. In the first quarter of 2018, we bought back the WTI $65 call options within the crude oil price collars for the period of May 1, 2018 through December 31, 2018. As a result, during this period we are able to realize average monthly WTI selling prices above $65 per barrel on the crude oil price collars covering the notional amount of 115,000 bopd. The put options within our crude oil collar contracts remain outstanding with a WTI average monthly floor price of $50 per barrel covering a notional amount of 115,000 bopd through December 31, 2018. In the second quarter of 2018, we purchased WTI put options with a notional amount of 20,000 bopd and a WTI average monthly floor price of $60 per barrel for calendar year 2019.

The gross notional amounts of outstanding financial risk management derivative contracts, excluding commodity contracts, were as follows:

	June 30, 2018		December 31, 2017
	(In millions)
Foreign exchange	$	16	$	52
Interest rate swaps	$	100	$	450

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:

	Assets		Liabilities
	(In millions)
June 30, 2018
Derivative Contracts Designated as Hedging Instruments
Commodity - Accounts receivable and Accounts payable	$	33	$	(31	)
Interest rate - Other liabilities and deferred credits (noncurrent)		—		(5	)
Total derivative contracts designated as hedging instruments		33		(36	)
Derivative Contracts Not Designated as Hedging Instruments
Commodity - Accounts receivable		—		—
Total derivative contracts not designated as hedging instruments		—		—
Gross fair value of derivative contracts		33		(36	)
Net Fair Value of Derivative Contracts	$	33	$	(36	)

December 31, 2017
Derivative Contracts Designated as Hedging Instruments
Commodity - Accounts payable	$	—	$	(7	)
Interest rate - Other assets (noncurrent) and Accounts payable		—		(4	)
Total derivative contracts designated as hedging instruments		—		(11	)
Derivative Contracts Not Designated as Hedging Instruments
Commodity - Accounts payable		—		(2	)
Foreign exchange		1		—
Total derivative contracts not designated as hedging instruments		1		(2	)
Gross fair value of derivative contracts		1		(13	)
Net Fair Value of Derivative Contracts	$	1	$	(13	)

Derivative contracts designated as hedging instruments:

Crude oil derivatives: Crude oil price hedging contracts for the three and six months ended June 30, 2018 decreased Sales and other operating revenues by $44 million and $74 million, respectively, and decreased Sales and other operating revenues by $12 million and $11 million for the three and six months ended June 30, 2017, respectively. At June 30, 2018, after-tax deferred losses in Accumulated other comprehensive income (loss) related to outstanding hedged crude oil collars were $89 million, of which all will be reclassified into earnings during the remainder of 2018 as the hedged crude oil sales are recognized in earnings.

Interest rate swaps designated as fair value hedges: At June 30, 2018 and December 31, 2017, we had interest rate swaps with gross notional amounts totaling $100 million and $450 million, respectively, which were designated as fair value hedges and relate to debt where we have converted interest payments on certain long-term debt from fixed to floating rates. Changes in the fair value of interest rate swaps and the hedged fixed-rate debt are recorded in Interest expense in the Statement of Consolidated Income. For the three and six months ended June 30, 2018, the change in fair value of interest rate swaps was an increase in the liability of $1 million and $4 million, respectively, compared with increase in liability of $2 million and $3 million in the second quarter and first six months of 2017, respectively, with a corresponding adjustment in the carrying value of the hedged fixed‑rate debt. In the first quarter of 2018, we paid $3 million, to terminate interest rate swaps with a gross notional amount of $350 million. See Note 4, Debt.

Interest rate swaps designated as cash flow hedges: There were no floating to fixed interest rate swap contracts in 2018. During the six months ended June 30, 2017, HIP had interest rate swaps with gross notional amounts totaling $545 million, which were designated as cash flow hedges and relates to debt in our Midstream operating segment where HIP converted interest payments on certain long-term debt from floating to fixed rates. For the three and six months ended June 30, 2017, the change in fair value of interest rate swaps was an increase to assets of $1 million.

Derivative contracts not designated as hedging instruments:

Crude oil collars: For the three and six months ended June 30, 2018, noncash adjustments to crude oil price hedging contracts, which were de-designated as cash flow hedges in the fourth quarter of 2017, decreased Sales and other operating revenues by $8 million and $16 million, respectively. At June 30, 2018, after-tax deferred losses in Accumulated other comprehensive income (loss) in connection with the de-designation, were $6 million, of which all will be reclassified into earnings during the remainder of 2018 as the originally hedged crude oil sales are recognized in earnings.

Foreign exchange: Foreign exchange gains and losses which are reported in Other, net in Revenues and non-operating income in the Statement of Consolidated Income were losses of $5 million and less than $1 million in the three months and six months ended June 30, 2018, respectively, compared with gains of $10 million and $9 million in the three months and six months ended June 30, 2017, respectively. A component of foreign exchange gain or loss is the result of foreign exchange derivative contracts that are not designated as hedges which amounted to losses of $3 million and $1 million in the three months and six months ended June 30, 2018, respectively, compared to gains of $2 million in both the second quarter and first six months of 2017, respectively.

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 June 30, 2018. Total long-term debt with a carrying value of $6,439 million at June 30, 2018, had a fair value of $6,925 million based on Level 2 inputs.

Subsequent Event	6 Months Ended
Subsequent Event	Jun. 30, 2018
Subsequent Events [Abstract]
Subsequent Event	14. Subsequent Event In July 2018, we entered into a sale and lease-back arrangement for a floating, storage and offloading vessel (FSO) that we will use at the North Malay Basin (Hess operated - 50%), in the Gulf of Thailand. Pursuant to the sale agreement, we and our partner expect to receive total proceeds of approximately $260 million in the third quarter of 2018. The lease agreement is for 16 years with four consecutive twelve-month renewal options to be exercised at our discretion.

Basis of Presentation (Policies)	6 Months Ended
Basis of Presentation (Policies)	Jun. 30, 2018
Accounting Policies [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements: In February 2016, the FASB issued ASU 2016-02, Leases, as a new Accounting Standards Codification (ASC) Topic, ASC 842. The new standard will require assets and liabilities to be reported on the Consolidated Balance Sheet for all leases with lease terms greater than one year, including leases currently treated as operating leases under the existing standard. This ASU is effective for us beginning in the first quarter of 2019, with early adoption permitted. We have developed and are executing a project plan for the implementation of ASC 842 in the first quarter of 2019. We are progressing our assessment of existing leases and evaluating our disclosure processes with reference to the requirements of the standard. We continue to assess the impact of the ASU on our consolidated financial statements. In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses. This ASU makes changes to the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standard requires the use of a forward-looking "expected loss" model compared to the current "incurred loss" model. This ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted beginning in the first quarter of 2019. We are currently assessing the impact of the ASU on our consolidated financial statements. In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment. This ASU modifies the concept of goodwill impairment from a condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of the reporting unit exceeds its fair value. Thus, an entity should recognize an impairment charge for the amount by which the carrying amount of a reporting unit exceeds its fair value. The impairment charge would be limited by the amount of goodwill allocated to the reporting unit. This ASU removes the requirement to determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if the reporting unit had been acquired in a business combination. This ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted. We are currently assessing the impact of the ASU on our consolidated financial statements.

Revenue (Tables)

6 Months Ended

Jun. 30, 2018

Revenue From Contract With Customer [Abstract]

Summary of Revenue from Contracts with Customers on a Disaggregated Basis

Revenue from contracts with customers on a disaggregated basis was as follows:

	Exploration and Production												Midstream		Eliminations			Total
	United States			Europe		Africa		Asia		E&P Total
For the Three Months Ended June 30, 2018	(In millions)
Sales of our net production volumes:
Crude oil revenue	$	692		$	19	$	110	$	28	$	849		$	—	$	—		$	849
Natural gas liquids revenue		75			—		—		—		75			—		—			75
Natural gas revenue		37			2		7		165		211			—		—			211
Sales of purchased oil and gas		424			—		22		—		446			—		—			446
Intercompany revenue		—			—		—		—		—			176		(176	)		—
Total revenues from contracts with customers		1,228			21		139		193		1,581			176		(176	)		1,581
Other operating revenue (a)		(47	)		—		—		—		(47	)		—		—			(47	)
Total sales and other operating revenues	$	1,181		$	21	$	139	$	193	$	1,534		$	176	$	(176	)	$	1,534

(a)	Includes gains (losses) on commodity derivatives.

	Exploration and Production												Midstream		Eliminations			Total
	United States			Europe		Africa		Asia		E&P Total
For the Six Months Ended June 30, 2018	(In millions)
Sales of our net production volumes:
Crude oil revenue	$	1,285		$	52	$	209	$	71	$	1,617		$	—	$	—		$	1,617
Natural gas liquids revenue		146			—		—		—		146			—		—			146
Natural gas revenue		76			5		15		293		389			—		—			389
Sales of purchased oil and gas		749			—		46		14		809			—		—			809
Intercompany revenue		—			—		—		—		—			343		(343	)		—
Total revenues from contracts with customers		2,256			57		270		378		2,961			343		(343	)		2,961
Other operating revenue (a)		(81	)		—		—		—		(81	)		—		—			(81	)
Total sales and other operating revenues	$	2,175		$	57	$	270	$	378	$	2,880		$	343	$	(343	)	$	2,880

(a)	Includes gains (losses) on commodity derivatives.

Inventories (Tables)

6 Months Ended

Jun. 30, 2018

Inventory Disclosure [Abstract]

Inventories

Inventories consisted of the following:

	June 30,		December 31,
	2018		2017
	(In millions)
Crude oil and natural gas liquids	$	58	$	59
Materials and supplies		173		173
Total Inventories	$	231	$	232

Property, Plant and Equipment (Tables)

6 Months Ended

Jun. 30, 2018

Property Plant And Equipment [Abstract]

Net Changes in Capitalized Exploratory Well Costs

Balance at January 1, 2018	$	304
Additions to capitalized exploratory well costs pending the determination of proved reserves		127
Balance at June 30, 2018	$	431

Retirement Plans (Tables)

6 Months Ended

Jun. 30, 2018

Compensation And Retirement Disclosure [Abstract]

Components of Net Periodic Pension Cost

Components of net periodic pension cost consisted of the following:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
	(In millions)
Service cost	$	10		$	14		$	24		$	28
Interest cost		24			26			47			52
Expected return on plan assets		(49	)		(42	)		(98	)		(83	)
Amortization of unrecognized net actuarial losses		9			16			21			33
Curtailment gains		—			—			(2	)		—
Settlement loss		—			7			—			7
Pension (income) expense	$	(6	)	$	21		$	(8	)	$	37

Weighted Average Common Shares (Tables)

6 Months Ended

Jun. 30, 2018

Earnings Per Share [Abstract]

Net Income (Loss) and Weighted Average Number of Common Shares Used in the Computation of Basic and Diluted Earnings Per Share

The Net income (loss) and weighted average number of common shares used in the basic and diluted earnings per share computations were as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
	(In millions)
Net income (loss) attributable to Hess Corporation Common Stockholders:
Net income (loss)	$	(87	)	$	(417	)	$	(152	)	$	(713	)
Less: Net income (loss) attributable to noncontrolling interests		43			32			84			60
Less: Preferred stock dividends		12			11			23			23
Net income (loss) attributable to Hess Corporation Common Stockholders	$	(142	)	$	(460	)	$	(259	)	$	(796	)

Weighted average number of common shares outstanding:
Basic	297.5	314.4	303.5	314.2
Effect of dilutive securities
Restricted common stock	—	—	—	—
Stock options	—	—	—	—
Performance share units	—	—	—	—
Mandatory convertible preferred stock	—	—	—	—
Diluted	297.5	314.4	303.5	314.2

Summary of Antidilutive Shares Excluded from Computation of Diluted Shares

The following table summarizes the number of antidilutive shares excluded from the computation of diluted shares:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2018		2017		2018		2017
Restricted common stock		2,849,465		3,450,490		2,885,890		3,288,356
Stock options		5,623,004		6,550,253		5,715,292		6,424,574
Performance share units		1,072,395		522,280		847,741		417,642
Common shares from conversion of preferred stocks		12,547,650		12,734,069		12,566,312		12,640,859

Segment Information (Tables)

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

Financial Data and Identifiable Assets by Operating Segment

	Exploration and Production			Midstream		Corporate, Interest and Other			Eliminations			Total
	(In millions)
For the Three Months Ended June 30, 2018
Sales and Other Operating Revenues - Third-parties	$	1,534		$	—	$	—		$	—		$	1,534
Intersegment Revenues		—			176		—			(176	)		—
Sales and Other Operating Revenues	$	1,534		$	176	$	—		$	(176	)	$	1,534

Net Income (Loss) attributable to Hess Corporation	$	31		$	30	$	(191	)	$	—		$	(130	)
Depreciation, Depletion and Amortization		407			31		6			—			444
Provision (Benefit) for Income Taxes		105			9		—			—			114
Capital Expenditures		486			84		—			—			570

For the Three Months Ended June 30, 2017
Sales and Other Operating Revenues - Third-parties	$	1,194		$	3	$	—		$	—		$	1,197
Intersegment Revenues		—			154		—			(154	)		—
Sales and Other Operating Revenues	$	1,194		$	157	$	—		$	(154	)	$	1,197

Net Income (Loss) attributable to Hess Corporation	$	(354	)	$	16	$	(111	)	$	—		$	(449	)
Depreciation, Depletion and Amortization		708			32		1			—			741
Provision (Benefit) for Income Taxes		(14	)		10		(4	)		—			(8	)
Capital Expenditures		483			20		—			—			503

For the Six Months Ended June 30, 2018
Sales and Other Operating Revenues - Third-parties	$	2,880		$	—	$	—		$	—		$	2,880
Intersegment Revenues		—			343		—			(343	)		—
Sales and Other Operating Revenues	$	2,880		$	343	$	—		$	(343	)	$	2,880

Net Income (Loss) attributable to Hess Corporation	$	6		$	58	$	(300	)	$	—		$	(236	)
Depreciation, Depletion and Amortization		792			62		7			—			861
Provision (Benefit) for Income Taxes		200			18		(31	)		—			187
Capital Expenditures		840			121		—			—			961

For the Six Months Ended June 30, 2017
Sales and Other Operating Revenues - Third-parties	$	2,450		$	5	$	—		$	—		$	2,455
Intersegment Revenues		—			301		—			(301	)		—
Sales and Other Operating Revenues	$	2,450		$	306	$	—		$	(301	)	$	2,455

Net Income (Loss) attributable to Hess Corporation	$	(587	)	$	34	$	(220	)	$	—		$	(773	)
Depreciation, Depletion and Amortization		1,411			64		3			—			1,478
Provision (Benefit) for Income Taxes		(34	)		21		(8	)		—			(21	)
Capital Expenditures		825			48		—			—			873

Identifiable assets by operating segment were as follows:

	June 30,		December 31,
	2018		2017
	(In millions)
Exploration and Production	$	15,907	$	15,613
Midstream		3,488		3,329
Corporate, Interest and Other		2,069		4,170
Total	$	21,464	$	23,112

Financial Risk Management Activities (Tables)

6 Months Ended

Jun. 30, 2018

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Gross Notional Amounts of Outstanding Financial Risk Management Derivative Contracts

The gross notional amounts of outstanding financial risk management derivative contracts related to West Texas Intermediate (WTI) instruments as of the dates shown below were as follows:

	June 30, 2018				December 31, 2017
Calendar year program	2018		2019		2018
Instrument type	Puts		Puts		Collars
Effective date	Jul. 1, 2018		Jan. 1, 2019		Jan. 1, 2018
End date	Dec. 31, 2018		Dec. 31, 2019		Dec. 31, 2018
Crude oil volumes (millions of barrels)		21.2		7.3		42.0
Ceiling price	N/A		N/A		$	65
Floor price	$	50	$	60	$	50

Gross Notional Amounts of Financial Risk Management Derivative Contracts Outstanding Excluding Commodity Contracts

The gross notional amounts of outstanding financial risk management derivative contracts, excluding commodity contracts, were as follows:

	June 30, 2018		December 31, 2017
	(In millions)
Foreign exchange	$	16	$	52
Interest rate swaps	$	100	$	450

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:

	Assets		Liabilities
	(In millions)
June 30, 2018
Derivative Contracts Designated as Hedging Instruments
Commodity - Accounts receivable and Accounts payable	$	33	$	(31	)
Interest rate - Other liabilities and deferred credits (noncurrent)		—		(5	)
Total derivative contracts designated as hedging instruments		33		(36	)
Derivative Contracts Not Designated as Hedging Instruments
Commodity - Accounts receivable		—		—
Total derivative contracts not designated as hedging instruments		—		—
Gross fair value of derivative contracts		33		(36	)
Net Fair Value of Derivative Contracts	$	33	$	(36	)

December 31, 2017
Derivative Contracts Designated as Hedging Instruments
Commodity - Accounts payable	$	—	$	(7	)
Interest rate - Other assets (noncurrent) and Accounts payable		—		(4	)
Total derivative contracts designated as hedging instruments		—		(11	)
Derivative Contracts Not Designated as Hedging Instruments
Commodity - Accounts payable		—		(2	)
Foreign exchange		1		—
Total derivative contracts not designated as hedging instruments		1		(2	)
Gross fair value of derivative contracts		1		(13	)
Net Fair Value of Derivative Contracts	$	1	$	(13	)

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

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Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
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+ Details

Basis of Presentation - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Reclassification of expense from Operating costs and expenses, Exploration expenses, and General and administrative expenses to Other, net due to adopting ASU 2017-07		$ 7		$ 9
Cumulative effect of hedging ineffectiveness					$ 0	$ (37)
Prior Period Adjustment [Abstract]
Sales and other operating revenue	$ 1,534	1,197	$ 2,880	2,455
Marketing, including purchased oil and gas	450	253	808	453
Restatement Adjustment
Prior Period Adjustment [Abstract]
Sales and other operating revenue		(19)		(38)
Marketing, including purchased oil and gas		(19)		(38)
Scenario Previously Reported
Prior Period Adjustment [Abstract]
Sales and other operating revenue		1,216		2,493
Marketing, including purchased oil and gas		$ 272		$ 491
Retained Earnings
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Cumulative effect of hedging ineffectiveness					1	(39)
Accumulated Other Comprehensive Income (Loss)
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Cumulative effect of hedging ineffectiveness					$ (1)	$ 0
ASU 2017-12 \| Retained Earnings
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Cumulative effect of hedging ineffectiveness	1		1
ASU 2017-12 \| Accumulated Other Comprehensive Income (Loss)
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Cumulative effect of hedging ineffectiveness	$ (1)		$ (1)

Revenue - Summary of Revenue from Contracts with Customers on a Disaggregated Basis (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	$ 1,581		$ 2,961
Other operating revenue, includes gains (losses) on commodity derivatives	(47)		(81)
Total sales and other operating revenues	1,534	$ 1,197	2,880	$ 2,455
Exploration and Production
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	1,581		2,961
Other operating revenue, includes gains (losses) on commodity derivatives	(47)		(81)
Total sales and other operating revenues	1,534		2,880
Exploration and Production \| United States
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	1,228		2,256
Other operating revenue, includes gains (losses) on commodity derivatives	(47)		(81)
Total sales and other operating revenues	1,181		2,175
Exploration and Production \| Europe
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	21		57
Other operating revenue, includes gains (losses) on commodity derivatives	0		0
Total sales and other operating revenues	21		57
Exploration and Production \| Africa
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	139		270
Other operating revenue, includes gains (losses) on commodity derivatives	0		0
Total sales and other operating revenues	139		270
Exploration and Production \| Asia
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	193		378
Other operating revenue, includes gains (losses) on commodity derivatives	0		0
Total sales and other operating revenues	193		378
Midstream
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	176		343
Other operating revenue, includes gains (losses) on commodity derivatives	0		0
Total sales and other operating revenues	176		343
Midstream \| Intercompany Revenue
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	176		343
Crude Oil Revenue
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	849		1,617
Crude Oil Revenue \| Exploration and Production
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	849		1,617
Crude Oil Revenue \| Exploration and Production \| United States
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	692		1,285
Crude Oil Revenue \| Exploration and Production \| Europe
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	19		52
Crude Oil Revenue \| Exploration and Production \| Africa
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	110		209
Crude Oil Revenue \| Exploration and Production \| Asia
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	28		71
Natural Gas Liquids Revenue
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	75		146
Natural Gas Liquids Revenue \| Exploration and Production
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	75		146
Natural Gas Liquids Revenue \| Exploration and Production \| United States
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	75		146
Natural Gas Liquids Revenue \| Exploration and Production \| Europe
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	0		0
Natural Gas Liquids Revenue \| Exploration and Production \| Africa
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	0		0
Natural Gas Liquids Revenue \| Exploration and Production \| Asia
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	0		0
Natural Gas Revenue
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	211		389
Natural Gas Revenue \| Exploration and Production
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	211		389
Natural Gas Revenue \| Exploration and Production \| United States
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	37		76
Natural Gas Revenue \| Exploration and Production \| Europe
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	2		5
Natural Gas Revenue \| Exploration and Production \| Africa
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	7		15
Natural Gas Revenue \| Exploration and Production \| Asia
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	165		293
Sales of Purchased Oil and Gas
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	446		809
Sales of Purchased Oil and Gas \| Exploration and Production
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	446		809
Sales of Purchased Oil and Gas \| Exploration and Production \| United States
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	424		749
Sales of Purchased Oil and Gas \| Exploration and Production \| Europe
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	0		0
Sales of Purchased Oil and Gas \| Exploration and Production \| Africa
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	22		46
Sales of Purchased Oil and Gas \| Exploration and Production \| Asia
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	0		14
Sales of Purchased Oil and Gas \| Midstream
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	0		0
Eliminations
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	(176)		(343)
Other operating revenue, includes gains (losses) on commodity derivatives	0		0
Total sales and other operating revenues	(176)	$ (154)	(343)	$ (301)
Eliminations \| Intercompany Revenue
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	(176)		(343)
Eliminations \| Sales of Purchased Oil and Gas
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	$ 0		$ 0

Revenue - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018	Dec. 31, 2017
Exploration and Production
Disaggregation Of Revenue [Line Items]
Contract assets	$ 0	$ 0	$ 0
Contract Liability	0	0	$ 0
Impairment losses on receivables arising from contracts with customers	$ 0	$ 0
Midstream
Disaggregation Of Revenue [Line Items]
Initial revenue contract period		10 years
Additional revenue contract period		10 years

Common Stock Repurchase Program - Additional Information (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2018	Dec. 31, 2018	Sep. 30, 2018
Common stock repurchased, share repurchase program		$ 380	$ 880
Share repurchase program, amount	$ 500	$ 1,500	500
Accelerated share repurchases, cash paid	$ 500		$ 500
Accelerated share repurchases, received of common stock	8.5		8.5
Accelerated share repurchase program, terms			We paid $500 million in cash to the financial institution and received approximately 8.5 million shares of our common stock as determined by the volume-weighted average price of the shares during the term of the agreement less an agreed settlement price adjustment.
Scenario Forecast
Share repurchase program, amount				$ 250	$ 250
Accelerated Share Repurchase Program [Member]
Common stock repurchased, share repurchase program	$ 500		$ 1,000
Common stock repurchased, share repurchase program, share			19.2
Share repurchase program, amount	$ 1,500		$ 1,500

Debt - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Debt Instrument Redemption [Line Items]
Debt instrument redemption amount	$ 138			$ 138
Current maturities of long-term debt	87			$ 87		$ 580
Redeemed and repurchased debt				terminated interest rate swaps with a notional amount of $350 million.
Loss on debt extinguishment	26		$ 0	$ 53	$ 0
Loss on debt extinguishment, after income tax	26			53
8.125% Notes Due 2019
Debt Instrument Redemption [Line Items]
Debt instrument redemption amount		$ 415
Debt instrument redemption of principal amount		$ 350
Debt instrument interest rate		8.125%
Debt instrument maturity year		2019
Other Notes
Debt Instrument Redemption [Line Items]
Current maturities of long-term debt		$ 38
Notes Payable
Debt Instrument Redemption [Line Items]
Current maturities of long-term debt	$ 112			$ 112

Inventories - Inventories (Detail) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Crude oil and natural gas liquids	$ 58	$ 59
Materials and supplies	173	173
Total Inventories	$ 231	$ 232

Property, Plant and Equipment - Additional Information (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Property Plant And Equipment [Line Items]
Assets held for sale	$ 421	$ 0
Expense of exploratory wells costs incurred	13
Capitalized exploratory well costs that have been capitalized for period greater than one year	$ 239
Northern Portion of Shenzi Field, Gulf of Mexico
Property Plant And Equipment [Line Items]
Capitalized well costs percentage	50.00%
Project interest percentage	28.00%
Liza-4 and Payara-1 Wells on the Stabroek Block, Offshore Guyana
Property Plant And Equipment [Line Items]
Capitalized well costs percentage	30.00%
Project interest percentage	30.00%
JDA, Gulf of Thailand
Property Plant And Equipment [Line Items]
Capitalized well costs percentage	20.00%
Project interest percentage	50.00%
Utica Shale Play, Eastern Ohio
Property Plant And Equipment [Line Items]
Assets held for sale	$ 365
Utica Shale Play, Eastern Ohio \| Accrued Liabilities
Property Plant And Equipment [Line Items]
Liabilities held for sale	2
Non-Core Acreage, North Dakota
Property Plant And Equipment [Line Items]
Assets held for sale	$ 56

Property, Plant and Equipment - Net Changes in Capitalized Exploratory Well Costs (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2018 USD ($)
Property Plant And Equipment [Abstract]
Beginning balance	$ 304
Additions to capitalized exploratory well costs pending the determination of proved reserves	127
Ending balance	$ 431

Hess Infrastructure Partners LP - Additional Information (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017	Dec. 31, 2016
Variable Interest Entity [Line Items]
Ownership percentage in Hess Infrastructure Partners LP (HIP) by Hess Corporation	50.00%
Noncontrolling interest ownership percentage in Hess Infrastructure Partners LP (HIP) by Global Infrastructure Partners (GIP)	50.00%
Cash and cash equivalents	$ 2,908	$ 4,847	$ 2,492	$ 2,732
Property, plant and equipment, net	15,869	16,192
Hess Infrastructure Partners LP (HIP)
Variable Interest Entity [Line Items]
Cash and cash equivalents	420	356
Property, plant and equipment, net	2,578	2,520
HIP's liabilities on a nonrecourse to Hess Corporation	$ 1,104	$ 1,065

Severance Costs - Additional Information (Detail) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Restructuring And Related Activities [Abstract]
Severance expense	$ 39
Severance costs paid as part of previously announced cost reduction program	34
Accrued severance cost	$ 11	$ 6
Expected period for payment for severance cost	We expect to pay in 2018.

Retirement Plans - Components of Net Periodic Pension Cost (Detail) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Compensation And Retirement Disclosure [Abstract]
Service cost	$ 10		$ 14	$ 24	$ 28
Interest cost	24		26	47	52
Expected return on plan assets	(49)		(42)	(98)	(83)
Amortization of unrecognized net actuarial losses	9		16	21	33
Curtailment gains	0	$ (2)	0	(2)	0
Settlement loss	0		7	0	7
Pension (income) expense	$ (6)		$ 21	$ (8)	$ 37

Retirement Plans - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended			6 Months Ended		12 Months Ended
	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Curtailment gains included in accumulated other comprehensive income (loss)		$ 18
Curtailment gain	$ 0	2	$ 0	$ 2	$ 0
Total service costs	10		14	24	28
Total interest costs	24		26	47	52
Total amortization of unrecognized net actuarial losses	(9)		(16)	(21)	(33)
Total expected return on plan assets	49		42	98	83
Net non-service pension (income) costs included in Other, net	(16)		$ 7	(32)	$ 9
Corporation's estimated contribution for funded pension plans during the current year	$ 47			47
Corporation's contribution for funded pension plan during the year to date				$ 25
U.S. Retirement Plans
Defined Benefit Plan Disclosure [Line Items]
Total decrease in pension liabilities		$ (125)
Scenario, Forecast
Defined Benefit Plan Disclosure [Line Items]
Total service costs						$ 45
Net non-service pension costs						60
Total interest costs						95
Total amortization of unrecognized net actuarial losses						40
Total expected return on plan assets						$ 195

Weighted Average Common Shares - Basic and Diluted Earnings Per Share (Detail) - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Net income (loss) attributable to Hess Corporation Common Stockholders:
Net Income (Loss)	$ (87)	$ (417)	$ (152)	$ (713)
Less: Net income (loss) attributable to noncontrolling interests	43	32	84	60
Less: Preferred stock dividends	12	11	23	23
Net Income (Loss) Attributable to Hess Corporation Common Stockholders	$ (142)	$ (460)	$ (259)	$ (796)
Weighted average number of common shares outstanding:
Shares outstanding – Basic	297.5	314.4	303.5	314.2
Diluted	297.5	314.4	303.5	314.2
Restricted Common Stock
Weighted average number of common shares outstanding:
Effect of dilutive securities	0.0	0.0
Stock Options
Weighted average number of common shares outstanding:
Effect of dilutive securities	0.0	0.0
Performance Share Units
Weighted average number of common shares outstanding:
Effect of dilutive securities	0.0	0.0
Mandatory Convertible Preferred Stock
Weighted average number of common shares outstanding:
Effect of dilutive securities	0.0	0.0

Weighted Average Common Shares - Antidilutive Shares Excluded from Computation of Diluted Shares (Detail) - shares	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Restricted Common Stock
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Antidilutive shares excluded from computation of diluted shares	2,849,465	3,450,490	2,885,890	3,288,356
Stock Options
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Antidilutive shares excluded from computation of diluted shares	5,623,004	6,550,253	5,715,292	6,424,574
Performance Share Units
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Antidilutive shares excluded from computation of diluted shares	1,072,395	522,280	847,741	417,642
Common Shares from Conversion of Preferred Stocks
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Antidilutive shares excluded from computation of diluted shares	12,547,650	12,734,069	12,566,312	12,640,859

Weighted Average Common Shares - Additional Information (Detail) - shares	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Equity [Abstract]
Shares granted, restricted stock	1,081,923	1,209,247
Shares granted, performance share units	278,003	438,980
Shares granted, stock options	683,167	662,819

Guarantees and Contingencies - Additional Information (Detail) $ in Millions			1 Months Ended
	Sep. 28, 2017 USD ($)	Mar. 04, 2016 USD ($)	Mar. 31, 2014 USD ($)	Jun. 30, 2018 Case
Loss Contingencies [Line Items]
Total number of remaining active cases filed \| Case				4
Lower Passaic River
Loss Contingencies [Line Items]
Estimated remediation cost		$ 1,380.0
Gowanus Canal Superfund Site
Loss Contingencies [Line Items]
Estimated remediation cost			$ 506.0
Ector Drum, Inc. Superfund Site
Loss Contingencies [Line Items]
Estimated remediation cost	$ 3.5

Segment Information - Additional Information (Detail)	6 Months Ended
Segment Information - Additional Information (Detail)	Jun. 30, 2018 Segment
Segment Reporting [Abstract]
Number of operating segments for the Corporation	2

Segment Information - Financial Data by Operating Segment (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Segment Reporting Information [Line Items]
Sales and other operating revenues - third-parties	$ 1,534	$ 1,197	$ 2,880	$ 2,455
Sales and other operating revenues	1,534	1,197	2,880	2,455
Net Income (Loss) attributable to Hess Corporation	(130)	(449)	(236)	(773)
Depreciation, depletion and amortization	444	741	861	1,478
Provision (benefit) for income taxes	114	(8)	187	(21)
Capital Expenditures	570	503	961	873
Identifiable assets	21,464		21,464		$ 23,112
Eliminations
Segment Reporting Information [Line Items]
Intersegment revenues	(176)	(154)	(343)	(301)
Sales and other operating revenues	(176)	(154)	(343)	(301)
Exploration and Production
Segment Reporting Information [Line Items]
Sales and other operating revenues	1,534		2,880
Exploration and Production \| Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues - third-parties	1,534	1,194	2,880	2,450
Sales and other operating revenues	1,534	1,194	2,880	2,450
Net Income (Loss) attributable to Hess Corporation	31	(354)	6	(587)
Depreciation, depletion and amortization	407	708	792	1,411
Provision (benefit) for income taxes	105	(14)	200	(34)
Capital Expenditures	486	483	840	825
Identifiable assets	15,907		15,907		15,613
Midstream
Segment Reporting Information [Line Items]
Sales and other operating revenues	176		343
Midstream \| Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues - third-parties		3		5
Intersegment revenues	176	154	343	301
Sales and other operating revenues	176	157	343	306
Net Income (Loss) attributable to Hess Corporation	30	16	58	34
Depreciation, depletion and amortization	31	32	62	64
Provision (benefit) for income taxes	9	10	18	21
Capital Expenditures	84	20	121	48
Identifiable assets	3,488		3,488		3,329
Corporate, Interest and Other \| Operating Segments
Segment Reporting Information [Line Items]
Net Income (Loss) attributable to Hess Corporation	(191)	(111)	(300)	(220)
Depreciation, depletion and amortization	6	1	7	3
Provision (benefit) for income taxes		$ (4)	(31)	$ (8)
Identifiable assets	$ 2,069		$ 2,069		$ 4,170

Financial Risk Management Activities - Gross Notional Amounts of Outstanding Financial Risk Management Derivative Contracts (Detail) - WTI	6 Months Ended	12 Months Ended
	Jun. 30, 2018 MMBbls $ / bbl	Dec. 31, 2017 MMBbls $ / bbl
2018
Derivative [Line Items]
Calendar year program	2018	2018
Instrument type	Puts	Collars
Effective date	Jul. 01, 2018	Jan. 01, 2018
End date	Dec. 31, 2018	Dec. 31, 2018
Crude oil volumes (millions of barrels) \| MMBbls	21.2	42.0
Ceiling price	0	65
Floor price	50	50
2019
Derivative [Line Items]
Calendar year program	2019
Instrument type	Puts
Effective date	Jan. 01, 2019
End date	Dec. 31, 2019
Crude oil volumes (millions of barrels) \| MMBbls	7.3
Ceiling price	0
Floor price	60

Financial Risk Management Activities - Additional Information (Detail)	3 Months Ended			6 Months Ended		12 Months Ended
	Jun. 30, 2018 USD ($) bbl / d $ / bbl	Mar. 31, 2018 USD ($) bbl / d	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) bbl / d $ / bbl	Jun. 30, 2017 USD ($)	Dec. 31, 2017 USD ($) bbl / d $ / bbl
Derivative Instruments Gain Loss [Line Items]
Redeemed and repurchased debt				terminated interest rate swaps with a notional amount of $350 million.
Designated as Fair Value Hedges
Derivative Instruments Gain Loss [Line Items]
Redeemed and repurchased debt				In the first quarter of 2018, we paid $3 million, to terminate interest rate swaps with a gross notional amount of $350 million. See Note 4, Debt.
Crude Oil \| Derivative Contracts Designated as Hedging Instruments
Derivative Instruments Gain Loss [Line Items]
Crude oil price hedging contracts increased (decreased) Sales and other operating revenues by this amount, pre-tax	$ (44,000,000)		$ (12,000,000)	$ (74,000,000)	$ (11,000,000)
Other operating revenue, losses associated with changes in time value of crude oil collars				(89,000,000)
Crude Oil \| Derivative Contracts Not Designated as Hedging Instruments
Derivative Instruments Gain Loss [Line Items]
Crude oil price hedging contracts increased (decreased) Sales and other operating revenues by this amount, pre-tax	$ (8,000,000)			(16,000,000)
After-tax deferred gain (losses) related to de-designation in Accumulated other comprehensive income (loss) to be reclassified into earnings				$ (6,000,000)
2018 \| West Texas Intermediate Crude Oil Price Collars
Derivative Instruments Gain Loss [Line Items]
Average monthly floor price \| $ / bbl	50			50		50
Average monthly ceiling price \| $ / bbl	0			0		65
Notional amount of outstanding average barrels of oil per day \| bbl / d		115,000		115,000		115,000
2018 \| West Texas Intermediate Crude Oil Price Collars \| Designated as Cash Flow Hedges
Derivative Instruments Gain Loss [Line Items]
Average monthly floor price \| $ / bbl	50			50		50
Average monthly ceiling price \| $ / bbl	0			0		65
2019 \| West Texas Intermediate Crude Oil Price Collars
Derivative Instruments Gain Loss [Line Items]
Average monthly floor price \| $ / bbl	60			60
Average monthly ceiling price \| $ / bbl	0			0
Notional amount of outstanding average barrels of oil per day \| bbl / d	20,000
Interest Rate Swaps \| Designated as Cash Flow Hedges
Derivative Instruments Gain Loss [Line Items]
Outstanding gross notional amount					545,000,000
Change in fair value of interest rate swaps - increase/(decrease)			1,000,000		1,000,000
Interest Rate Swaps \| Designated as Fair Value Hedges
Derivative Instruments Gain Loss [Line Items]
Outstanding gross notional amount	$ 100,000,000			$ 100,000,000		$ 450,000,000
Unrealized change in fair value of interest rate swaps - increase in derivative liability	1,000,000		2,000,000	4,000,000	3,000,000
Interest Rate Swaps \| Designated as Fair Value Hedges \| 8.125% Notes Due 2019
Derivative Instruments Gain Loss [Line Items]
Outstanding gross notional amount		$ 350,000,000
Payment to terminate interest rate swaps		$ 3,000,000
Foreign Exchange
Derivative Instruments Gain Loss [Line Items]
Outstanding gross notional amount	16,000,000			16,000,000		$ 52,000,000
Foreign Exchange \| Derivative Contracts Not Designated as Hedging Instruments
Derivative Instruments Gain Loss [Line Items]
Foreign exchange gains and (losses) reported in Other, net	(5,000,000)		10,000,000		9,000,000
Foreign exchange gains (losses) from foreign exchange derivative contracts that are not designated as hedges	$ (3,000,000)		$ 2,000,000	(1,000,000)	$ 2,000,000
Foreign Exchange \| Derivative Contracts Not Designated as Hedging Instruments \| Maximum
Derivative Instruments Gain Loss [Line Items]
Foreign exchange gains and (losses) reported in Other, net				$ (1,000,000)

Financial Risk Management Activities - Gross Notional Amounts of Derivative Contracts Outstanding Excluding Commodity Contracts (Detail) - USD ($)	Jun. 30, 2018	Dec. 31, 2017
Foreign Exchange
Derivative [Line Items]
Outstanding gross notional amount	$ 16,000,000	$ 52,000,000
Interest Rate Swaps \| Designated as Fair Value Hedges
Derivative [Line Items]
Outstanding gross notional amount	$ 100,000,000	$ 450,000,000

Financial Risk Management Activities - Gross and Net Fair Values (Detail) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Derivatives Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	$ 33	$ 1
Assets - Net Fair Value of Derivative Contracts	33	1
Liabilities - Gross fair value of derivative contracts	(36)	(13)
Liabilities - Net Fair Value of Derivative Contracts	(36)	(13)
Derivative Contracts Designated as Hedging Instruments
Derivatives Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	33
Liabilities - Gross fair value of derivative contracts	(36)	(11)
Derivative Contracts Designated as Hedging Instruments \| Commodity \| Accounts Receivable and Accounts Payable
Derivatives Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	33
Liabilities - Gross fair value of derivative contracts	(31)
Derivative Contracts Designated as Hedging Instruments \| Commodity \| Accounts Payable
Derivatives Fair Value [Line Items]
Liabilities - Gross fair value of derivative contracts		(7)
Derivative Contracts Designated as Hedging Instruments \| Interest Rate \| Other assets (noncurrent) and Accounts Payable
Derivatives Fair Value [Line Items]
Liabilities - Gross fair value of derivative contracts		(4)
Derivative Contracts Designated as Hedging Instruments \| Interest Rate \| Other Liabilities and Deferred Credits
Derivatives Fair Value [Line Items]
Liabilities - Gross fair value of derivative contracts	$ (5)
Derivative Contracts Not Designated as Hedging Instruments
Derivatives Fair Value [Line Items]
Assets - Gross fair value of derivative contracts		1
Liabilities - Gross fair value of derivative contracts		(2)
Derivative Contracts Not Designated as Hedging Instruments \| Commodity \| Accounts Payable
Derivatives Fair Value [Line Items]
Liabilities - Gross fair value of derivative contracts		(2)
Derivative Contracts Not Designated as Hedging Instruments \| Foreign Exchange
Derivatives Fair Value [Line Items]
Assets - Gross fair value of derivative contracts		$ 1

Financial Risk Management Activities - Fair Value Measurements - Additional Information (Detail) $ in Millions	Jun. 30, 2018 USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total long-term debt, carrying value	$ 6,439
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total long-term debt, fair value	$ 6,925

Subsequent Event - Additional Information (Details) - USD ($) $ in Millions	1 Months Ended	6 Months Ended
	Jul. 31, 2018	Jun. 30, 2018	Jun. 30, 2017
Subsequent Event [Line Items]
Proceeds from asset sales		$ 33	$ 179
Floating, Storage and Offloading Vessel \| Subsequent Event
Subsequent Event [Line Items]
North Malay Basin - Hess operated interest	50.00%
Proceeds from asset sales	$ 260
Lease description	The lease agreement is for 16 years with four consecutive twelve-month renewal options to be exercised at our discretion.