Hess (HES) 10-Q 9 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information	9 Months Ended
	Sep. 30, 2018shares
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Trading Symbol	HES
Entity Registrant Name	HESS CORP
Entity Central Index Key	4,447
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding	296,253,136

Consolidated Balance Sheet

Consolidated Balance Sheet - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 3,004	$ 4,847
Accounts receivable:
From contracts with customers	891	677
Joint venture and other	291	347
Inventories	263	232
Other current assets	52	54
Total current assets	4,501	6,157
Property, plant and equipment:
Total — at cost	32,619	32,504
Less: Reserves for depreciation, depletion, amortization and lease impairment	16,606	16,312
Property, plant and equipment — net	16,013	16,192
Goodwill	360	360
Deferred income taxes	10	21
Other assets	583	382
Total Assets	21,467	23,112
Current Liabilities:
Accounts payable	383	435
Accrued liabilities	1,394	1,337
Taxes payable	96	83
Current maturities of long-term debt	85	580
Total current liabilities	1,958	2,435
Long-term debt	6,609	6,397
Deferred income taxes	425	429
Asset retirement obligations	772	753
Other liabilities and deferred credits	657	744
Total Liabilities	10,421	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 — 296,253,136 shares (2017: 315,053,615)	296	315
Capital in excess of par value	5,445	5,824
Retained earnings	4,410	5,597
Accumulated other comprehensive income (loss)	(502)	(686)
Total Hess Corporation stockholders’ equity	9,650	11,051
Noncontrolling interests	1,396	1,303
Total equity	11,046	12,354
Total Liabilities and Equity	$ 21,467	$ 23,112

Consolidated Balance Sheet (Par

Consolidated Balance Sheet (Parenthetical) - $ / shares	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Statement Of Financial Position [Abstract]
Preferred stock, par value	$ 1	$ 1
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	$ 1
Common stock, shares authorized	600,000,000	600,000,000
Common stock, shares issued	296,253,136	315,053,615

Statement of Consolidated Incom

Statement of Consolidated Income - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues and Non-Operating Income
Sales and other operating revenues	$ 1,793	$ 1,348	$ 4,673	$ 3,803
Gains on asset sales, net	14	274	32	276
Other, net	21	22	79	21
Total revenues and non-operating income	1,828	1,644	4,784	4,100
Costs and Expenses
Marketing, including purchased oil and gas	491	338	1,299	791
Operating costs and expenses	266	353	842	1,085
Production and severance taxes	47	27	128	88
Exploration expenses, including dry holes and lease impairment	169	41	271	151
General and administrative expenses	143	111	382	301
Interest expense	99	79	300	245
Loss on debt extinguishment	0	0	53	0
Depreciation, depletion and amortization	489	759	1,350	2,237
Impairment	0	2,503	0	2,503
Total costs and expenses	1,704	4,211	4,625	7,401
Income (Loss) Before Income Taxes	124	(2,567)	159	(3,301)
Provision (benefit) for income taxes	121	(1,974)	308	(1,995)
Net Income (Loss)	3	(593)	(149)	(1,306)
Less: Net income (loss) attributable to noncontrolling interests	45	31	129	91
Net Income (Loss) Attributable to Hess Corporation	(42)	(624)	(278)	(1,397)
Less: Preferred stock dividends	11	11	34	34
Net Income (Loss) Attributable to Hess Corporation Common Stockholders	$ (53)	$ (635)	$ (312)	$ (1,431)
Net Income (Loss) Attributable to Hess Corporation Per Common Share:
Basic	$ (0.18)	$ (2.02)	$ (1.04)	$ (4.55)
Diluted	$ (0.18)	$ (2.02)	$ (1.04)	$ (4.55)
Weighted Average Number of Common Shares Outstanding (Diluted)	294.3	314.5	300.4	314.3
Common Stock Dividends Per Share	$ 0.25	$ 0.25	$ 0.75	$ 0.75

Statement of Consolidated Compr

Statement of Consolidated Comprehensive Income - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement Of Income And Comprehensive Income [Abstract]
Net Income (Loss)	$ 3	$ (593)	$ (149)	$ (1,306)
Derivatives designated as cash flow hedges
Effect of hedge (gains) losses reclassified to income	49	(18)	129	(38)
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	(18)	129	(38)
Change in fair value of cash flow hedges	(49)	(76)	(84)	0
Income taxes on change in fair value of cash flow hedges	12	0	12	0
Net change in fair value of cash flow hedges	(37)	(76)	(72)	0
Change in derivatives designated as cash flow hedges, after taxes	12	(94)	57	(38)
Pension and other postretirement plans
(Increase) reduction in unrecognized actuarial losses	0	0	130	5
Income taxes on actuarial changes in plan liabilities	0	2	(31)	0
(Increase) reduction in unrecognized actuarial losses, net	0	2	99	5
Amortization of net actuarial losses	8	17	29	57
Income taxes on amortization of net actuarial losses	0	0	0	0
Net effect of amortization of net actuarial losses	8	17	29	57
Change in pension and other postretirement plans, after taxes	8	19	128	62
Foreign currency translation adjustment
Foreign currency translation adjustment	0	121	0	208
Change in foreign currency translation adjustment	0	121	0	208
Other Comprehensive Income (Loss)	20	46	185	232
Comprehensive Income (Loss)	23	(547)	36	(1,074)
Less: Comprehensive income (loss) attributable to noncontrolling interests	45	31	129	91
Comprehensive Income (Loss) Attributable to Hess Corporation	$ (22)	$ (578)	$ (93)	$ (1,165)

Statement of Consolidated Cash

Statement of Consolidated Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash Flows From Operating Activities
Net income (loss)	$ (149)	$ (1,306)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
(Gains) losses on asset sales, net	(32)	(276)
Depreciation, depletion and amortization	1,350	2,237
Impairment	0	2,503
Exploratory dry hole costs	132	0
Exploration lease and other impairment	28	22
Stock compensation expense	53	65
Noncash (gains) losses on commodity derivatives, net	134	43
Provision (benefit) for deferred income taxes and other tax accruals	(28)	(2,055)
Loss on debt extinguishment	53	0
Changes in operating assets and liabilities
(Increase) decrease in accounts receivable	(247)	(88)
(Increase) decrease in inventories	(35)	(48)
Increase (decrease) in accounts payable and accrued liabilities	(140)	(189)
Increase (decrease) in taxes payable	9	3
Changes in other operating assets and liabilities	(70)	(309)
Net cash provided by (used in) operating activities	1,058	602
Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P	(1,265)	(1,275)
Additions to property, plant and equipment - Midstream	(168)	(108)
Payments for Midstream equity investments	(67)	0
Proceeds from asset sales, net of cash sold	607	783
Other, net	(8)	(1)
Net cash provided by (used in) investing activities	(901)	(601)
Cash Flows From Financing Activities
Net borrowings (repayments) of debt with maturities of 90 days or less	0	15
Debt with maturities of greater than 90 days – Borrowings	0	0
Debt with maturities of greater than 90 days – Repayments	(610)	(107)
Proceeds from issuance of Hess Midstream Partnership LP units	0	366
Common stock acquired and retired	(1,120)	0
Cash dividends paid	(262)	(273)
Noncontrolling interests, net	(36)	(208)
Other, net	28	0
Net cash provided by (used in) financing activities	(2,000)	(207)
Net Increase (Decrease) in Cash and Cash Equivalents	(1,843)	(206)
Cash and Cash Equivalents at Beginning of Year	4,847	2,732
Cash and Cash Equivalents at End of Period	$ 3,004	$ 2,526

Statement of Consolidated Equit

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)	(1,306)	0	0	0	(1,397)	0	(1,397)	91
Other comprehensive income	232	0	0	0	0	232	232	0
Share-based compensation, including income taxes	73	0	1	72	0	0	73	0
Dividends on preferred stock	(34)	0	0	0	(34)	0	(34)	0
Dividends on common stock	(239)	0	0	0	(239)	0	(239)	0
Hess Midstream Partners LP units issuance	356	0	0	0	0	0	0	356
Noncontrolling interests, net	(208)	0	0	0	0	0	0	(208)
Balance at Sep. 30, 2017	14,428	1	318	5,847	8,438	(1,472)	13,132	1,296
Common stock acquired and retired	(1,250)
Balance at Sep. 30, 2018	11,046	1	296	5,445	4,410	(502)	9,650	1,396
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)	(149)	0	0	0	(278)	0	(278)	129
Other comprehensive income	185	0	0	0	0	185	185	0
Share-based compensation, including income taxes	84	0	1	83	0	0	84	0
Dividends on preferred stock	(34)	0	0	0	(34)	0	(34)	0
Dividends on common stock	(228)	0	0	0	(228)	0	(228)	0
Common stock acquired and retired	(1,130)	0	(20)	(462)	(648)	0	(1,130)	0
Noncontrolling interests, net	(36)	0	0	0	0	0	0	(36)
Balance at Sep. 30, 2018	$ 11,046	$ 1	$ 296	$ 5,445	$ 4,410	$ (502)	$ 9,650	$ 1,396

Basis of Presentation

Basis of Presentation	9 Months Ended
	Sep. 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 September 30, 2018 and December 31, 2017, the consolidated results of operations for the three months and nine months ended September 30, 2018 and 2017, and consolidated cash flows for the nine months ended September 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 Retained earnings Accounts receivables from contracts with customers Consolidated Balance Sheet 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 Statement of Consolidated Income Operating costs and expenses General and administrative expenses Other, net In the first quarter of 2018, we adopted ASU 2017-12, Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities Retained earnings Accumulated other comprehensive income (loss) 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) 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) 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 Sales and other operating revenues Marketing, including purchased oil and gas Consolidated Balance Sheet Statement of Consolidated Comprehensive Income Statement of Consolidated Cash Flows Statement of Consolidated Equity Sales and other operating revenues Marketing, including purchased oil and gas 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 supersedes ASC 840 and will require the recognition of right-of-use assets and lease liabilities for all leases with lease terms greater than one year, including leases currently treated as operating leases under ASC 840. ASC 842 is effective for us beginning in the first quarter of 2019, with early adoption permitted. We have elected to adopt ASC 842 on January 1, 2019 using the modified retrospective method which allows application of the new standard prospectively from the date of adoption with a cumulative effect adjustment, if any, recorded to Retained Earnings at the date of adoption. Accordingly, comparative financial statements for periods prior to the adoption date of ASC 842 will not be affected. In addition, we have elected to apply the ‘package’ of practical expedients allowing us to avoid reassessing whether existing contracts are (or contain) leases, whether the lease classification for existing leases would differ under ASC 842, and whether initial direct costs incurred for existing leases are capitalizable under ASC 842. Finally, we have elected to apply the practical expedient allowing us to avoid reassessing land easements that were not previously accounted for as leases under ASC 840. We have not elected the ‘hindsight’ practical expedient when determining lease term. As part of our ASC 842 implementation project, we continue to evaluate contracts, monitor standard setting activity, and evaluate our internal controls to comply with the accounting and disclosure requirements of ASC 842. Although we cannot reasonably estimate the quantitative impact ASC 842 will have on our consolidated financial statements at the effective date, we believe adoption will have a material effect on our Consolidated Balance Sheet due to the recognition of right-of-use assets and lease liabilities for all leases with lease terms greater than one year. We enter into various leases in the normal course of business primarily for drilling rigs, a floating storage and offloading vessel, support vessels, and office space. In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment In February 2018, the FASB issued ASU 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income Accumulated other comprehensive income (loss) Retained earnings Accumulated other comprehensive income (loss)

Revenue

Revenue	9 Months Ended
	Sep. 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 Three Months Ended September 30, 2018 (In millions) Sales of our net production volumes: Crude oil revenue $ 826 $ 54 $ 108 $ 29 $ 1,017 $ — $ — $ 1,017 Natural gas liquids revenue 90 — — — 90 — — 90 Natural gas revenue 44 3 5 178 230 — — 230 Sales of purchased oil and gas 482 — 22 — 504 — — 504 Intercompany revenue — — — — — 184 (184 ) — Total revenues from contracts with customers 1,442 57 135 207 1,841 184 (184 ) 1,841 Other operating revenue (a) (48 ) — — — (48 ) — — (48 ) Total sales and other operating revenues $ 1,394 $ 57 $ 135 $ 207 $ 1,793 $ 184 $ (184 ) $ 1,793 (a) Includes gains (losses) on commodity derivatives. Exploration and Production Midstream Eliminations Total United States Europe Africa Asia E&P Total Nine Months Ended September 30, 2018 (In millions) Sales of our net production volumes: Crude oil revenue $ 2,111 $ 106 $ 317 $ 100 $ 2,634 $ — $ — $ 2,634 Natural gas liquids revenue 236 — — — 236 — — 236 Natural gas revenue 120 8 20 471 619 — — 619 Sales of purchased oil and gas 1,231 — 68 14 1,313 — — 1,313 Intercompany revenue — — — — — 527 (527 ) — Total revenues from contracts with customers 3,698 114 405 585 4,802 527 (527 ) 4,802 Other operating revenue (a) (129 ) — — — (129 ) — — (129 ) Total sales and other operating revenues $ 3,569 $ 114 $ 405 $ 585 $ 4,673 $ 527 $ (527 ) $ 4,673 (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 Sales and other operating revenues Marketing, including purchased oil and gas Sales and other operating revenues 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 September 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 nine months ended September 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 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 generally 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

Common Stock Repurchase Program

Common Stock Repurchase Program	9 Months Ended
	Sep. 30, 2018
Equity [Abstract]
Common Stock Repurchase Program	3. Common Stock Repurchase Program In the three and nine months ended September 30, 2018, we repurchased $250 million (3.8 million shares) and $1,130 million (20.4 million shares) of our common stock, respectively, bringing total repurchases under our $1.5 billion common stock repurchase program to $1.25 billion (23.0 million shares) as of September 30, 2018.

Debt

Debt	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Debt	4. Debt Debt extinguishment : 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 total losses on debt extinguishment totaling $53 million ($53 million after income taxes). Capital lease : In the third quarter of 2018, we entered into a sale and lease-back arrangement for a floating, storage and offloading vessel (FSO) to handle produced condensate at the North Malay Basin, offshore Peninsular Malaysia (Hess operated - 50%). Pursuant to the sale agreement, we received total proceeds of approximately $260 million, including our partner’s share of the proceeds which is reported in Accounts Payable on our Consolidated Balance Sheet. No gain or loss was recognized from the sale transaction. The lease agreement is for 16 years with four consecutive twelve-month renewal options that may be exercised at our discretion. At September 30, 2018, the carrying value of the lease obligation is $273 million, which represents 100% of the present value of future minimum lease payments, of which $15 million is included in Current maturities of long-term debt and $258 million is included in Long-term debt on our Consolidated Balance Sheet . As the payments under the lease agreement become due, we will bill our partner their proportionate share for reimbursement pursuant to the terms of our joint operating agreement.

Inventories

Inventories	9 Months Ended
	Sep. 30, 2018
Inventory Disclosure [Abstract]
Inventories	5. Inventories Inventories consisted of the following: September 30, December 31, 2018 2017 (In millions) Crude oil and natural gas liquids $ 81 $ 59 Materials and supplies 182 173 Total Inventories $ 263 $ 232

Capitalized Exploratory Well Co

Capitalized Exploratory Well Costs	9 Months Ended
	Sep. 30, 2018
Capitalized Exploratory Well Costs [Abstract]
Capitalized Exploratory Well Costs	6. Capitalized Exploratory Well Costs The following table discloses the net changes in capitalized exploratory well costs pending determination of proved reserves during the nine months ended September 30, 2018 (in millions): Balance at January 1, 2018 $ 304 Additions to capitalized exploratory well costs pending the determination of proved reserves 102 Capitalized exploratory well costs charged to expense (13 ) Balance at September 30, 2018 $ 393 The table above does not include well costs incurred and expensed during 2018 of $119 million associated with the Aspy well, offshore Nova Scotia, Canada, the Pontoenoe-1 well, offshore Suriname, the Sorubim-1 well on the Stabroek Block, offshore Guyana, and the Bunga Teruntum-1 well in the North Malay Basin. Capitalized exploratory well costs capitalized for greater than one year following completion of drilling were $251 million at September 30, 2018 and primarily related to: Gulf of Mexico: Approximately 45% 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 planning to acquire 3D seismic in 2019 for use in development planning of the northern portion of the Shenzi Field. Guyana: Approximately 35% of the capitalized well costs in excess of one year primarily relates to the Liza-4, Payara-1, Payara-2 and Snoek-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 commence production by mid-2022. The operator plans to integrate the Payara-1 and Payara-2 discoveries into the third phase of development, which is expected to commence production as early as 2023. JDA: Approximately 15% 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. Malaysia: Approximately 5% of the capitalized well costs in excess of one year relates to the North Malay Basin, offshore Peninsular Malaysia (Hess 50%), where hydrocarbons were encountered in one successful exploration well drilled in the fourth quarter of 2015. We are planning to conduct subsurface evaluations and evaluate whether to integrate this discovery into a future phase of field development.

Hess Infrastructure Partners LP

Hess Infrastructure Partners LP	9 Months Ended
	Sep. 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 September 30, 2018, HIP liabilities totaling $1,100 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 $395 million (December 31, 2017: $356 million) and property, plant and equipment with a carrying value of $2,630 million (December 31, 2017: $2,520 million).

Exit and Disposal Costs

Exit and Disposal Costs	9 Months Ended
	Sep. 30, 2018
Restructuring And Related Activities [Abstract]
Exit and Disposal Costs	8. Exit and Disposal Costs In the first nine months of 2018, we recorded severance expense of $39 million and paid severance costs of $39 million as part of our previously announced cost reduction program. At September 30, 2018, we have accrued severance cost of $6 million (December 31, 2017: $6 million), which we expect to pay in the fourth quarter of 2018. In the third quarters of 2018 and 2017, we recorded charges of $57 million and $11 million, respectively, in General and Administrative Expenses

Dispositions

Dispositions	9 Months Ended
	Sep. 30, 2018
Discontinued Operations And Disposal Groups [Abstract]
Dispositions	9. Dispositions In the third quarter of 2018, we completed the sale of our joint venture interests in the Utica shale play in eastern Ohio for proceeds of $396 million, after normal closing adjustments, and recognized a pre-tax gain of $14 million ($14 million after income taxes). In the third quarter of 2017, we completed the sale of our enhanced oil recovery assets in the Permian Basin for proceeds of $597 million, after normal closing adjustments, and recognized a pre-tax gain of $273 million ($280 million attributable to Hess Corporation after income taxes and noncontrolling interest). This sale transaction included both upstream and midstream assets resulting in an after-tax gain of $314 million allocated to the E&P segment, and an after-tax loss of $34 million allocated to the Midstream segment.

Impairment

Impairment	9 Months Ended
	Sep. 30, 2018
Asset Impairment Charges [Abstract]
Impairment	10. Impairment In the third quarter of 2017, we recorded a pre-tax impairment charge of $2,503 million ($550 million after income taxes) to impair the carrying value of our interests in Norway based on an anticipated sale of the asset using Level 3 inputs to determine fair value. The sale was completed in the fourth quarter of 2017.

Retirement Plans

Retirement Plans	9 Months Ended
	Sep. 30, 2018
Compensation And Retirement Disclosure [Abstract]
Retirement Plans	11. Retirement Plans Components of net periodic pension cost consisted of the following: Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (In millions) Service cost $ 10 $ 13 $ 34 $ 41 Interest cost 24 25 71 77 Expected return on plan assets (49 ) (42 ) (147 ) (125 ) Amortization of unrecognized net actuarial losses 8 13 29 46 Curtailment gains — — (2 ) — Settlement loss — 4 — 11 Pension (income) expense $ (7 ) $ 13 $ (15 ) $ 50 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 For the full year 2018, we 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 Statement of Consolidated Income In 2018, we expect to contribute $47 million to our funded pension plans. In the nine months ended September 30, 2018, we have contributed $35 million to these plans.

Weighted Average Common Shares

Weighted Average Common Shares	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Weighted Average Common Shares	12. 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 Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (In millions) Net income (loss) attributable to Hess Corporation Common Stockholders: Net income (loss) $ 3 $ (593 ) $ (149 ) $ (1,306 ) Less: Net income (loss) attributable to noncontrolling interests 45 31 129 91 Less: Preferred stock dividends 11 11 34 34 Net income (loss) attributable to Hess Corporation Common Stockholders $ (53 ) $ (635 ) $ (312 ) $ (1,431 ) Weighted average number of common shares outstanding: Basic 294.3 314.5 300.4 314.3 Effect of dilutive securities Restricted common stock — — — — Stock options — — — — Performance share units — — — — Mandatory convertible preferred stock — — — — Diluted 294.3 314.5 300.4 314.3 The following table summarizes the number of antidilutive shares excluded from the computation of diluted shares: Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 Restricted common stock 2,898,733 3,313,441 2,890,171 3,296,718 Stock options 5,324,682 6,509,214 5,585,088 6,452,788 Performance share units 1,301,604 709,445 999,029 514,910 Common shares from conversion of preferred stocks 12,547,650 13,400,515 12,560,091 12,894,078 During the nine months ended September 30, 2018, we granted 1,255,799 shares of restricted stock (2017: 1,214,460), 278,003 performance share units (2017: 438,980) and 683,167 stock options (2017: 662,819).

Guarantees and Contingencies

Guarantees and Contingencies	9 Months Ended
	Sep. 30, 2018
Commitments And Contingencies Disclosure [Abstract]
Guarantees and Contingencies	13. 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, Texas. 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 is not expected to have a material adverse effect on our financial condition, results of operations or cash flows.

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Segment Information	14. 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 September 30, 2018 Sales and Other Operating Revenues - Third-parties $ 1,793 $ — $ — $ — $ 1,793 Intersegment Revenues — 184 — (184 ) — Sales and Other Operating Revenues $ 1,793 $ 184 $ — $ (184 ) $ 1,793 Net Income (Loss) attributable to Hess Corporation $ 50 $ 30 $ (122 ) $ — $ (42 ) Depreciation, Depletion and Amortization 457 32 — — 489 Provision (Benefit) for Income Taxes 100 10 11 — 121 Capital Expenditures 500 83 — — 583 For the Three Months Ended September 30, 2017 Sales and Other Operating Revenues - Third-parties $ 1,347 $ 1 $ — $ — $ 1,348 Intersegment Revenues — 153 — (153 ) — Sales and Other Operating Revenues $ 1,347 $ 154 $ — $ (153 ) $ 1,348 Net Income (Loss) attributable to Hess Corporation $ (474 ) $ (12 ) $ (138 ) $ — $ (624 ) Depreciation, Depletion and Amortization 709 29 21 — 759 Impairment 2,503 — — — 2,503 Provision (Benefit) for Income Taxes (1,969 ) (3 ) (2 ) — (1,974 ) Capital Expenditures 526 27 — — 553 For the Nine Months Ended September 30, 2018 Sales and Other Operating Revenues - Third-parties $ 4,673 $ — $ — $ — $ 4,673 Intersegment Revenues — 527 — (527 ) — Sales and Other Operating Revenues $ 4,673 $ 527 $ — $ (527 ) $ 4,673 Net Income (Loss) attributable to Hess Corporation $ 56 $ 88 $ (422 ) $ — $ (278 ) Depreciation, Depletion and Amortization 1,249 94 7 — 1,350 Provision (Benefit) for Income Taxes 300 28 (20 ) — 308 Capital Expenditures 1,340 204 — — 1,544 For the Nine Months Ended September 30, 2017 Sales and Other Operating Revenues - Third-parties $ 3,797 $ 6 $ — $ — $ 3,803 Intersegment Revenues — 454 — (454 ) — Sales and Other Operating Revenues $ 3,797 $ 460 $ — $ (454 ) $ 3,803 Net Income (Loss) attributable to Hess Corporation $ (1,061 ) $ 22 $ (358 ) $ — $ (1,397 ) Depreciation, Depletion and Amortization 2,120 93 24 — 2,237 Impairment 2,503 — — — 2,503 Provision (Benefit) for Income Taxes (2,003 ) 18 (10 ) — (1,995 ) Capital Expenditures 1,351 75 — — 1,426 Identifiable assets by operating segment were as follows: September 30, December 31, 2018 2017 (In millions) Exploration and Production $ 16,387 $ 15,613 Midstream 3,540 3,329 Corporate, Interest and Other 1,540 4,170 Total $ 21,467 $ 23,112

Financial Risk Management Activ

Financial Risk Management Activities	9 Months Ended
	Sep. 30, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Financial Risk Management Activities	15. 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 September 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: September 30, 2018 December 31, 2017 Calendar year program 2018 2019 2018 Instrument type Puts Puts Collars Effective date Oct. 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) 10.6 32.9 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 a monthly floor price of $50 per barrel and a monthly ceiling price of $65 per barrel with a notional amount of 115,000 barrels of oil per day (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 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 monthly floor price of $50 per barrel covering a notional amount of 115,000 bopd through December 31, 2018. During the nine months ended September 30, 2018, The gross notional amounts of outstanding financial risk management derivative contracts, excluding commodity contracts, were as follows: September 30, 2018 December 31, 2017 (In millions) Foreign exchange $ 9 $ 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) September 30, 2018 Derivative Contracts Designated as Hedging Instruments Commodity - Accounts receivable and Accounts payable $ 66 $ (8 ) Interest rate - Other liabilities and deferred credits (noncurrent) — (5 ) Total derivative contracts designated as hedging instruments 66 (13 ) Gross fair value of derivative contracts 66 (13 ) Net Fair Value of Derivative Contracts $ 66 $ (13 ) 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 nine months ended September 30, 2018 decreased Sales and other operating revenues by $45 million and $119 million, respectively. I n the third quarter and nine months ended September 30, 2017, the impact from realized and unrealized movements in crude oil price collars on Sales and other operating revenues was an increase of $6 million and a reduction of $5 million, respectively. At September 30, 2018, after-tax deferred losses in related to outstanding crude oil price hedging contracts were $92 million, of which $90 million will be reclassified into earnings during the next 12 months as the hedged crude oil sales are recognized in earnings. Interest rate swaps designated as fair value hedges: At September 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 in the . For the three and nine months ended September 30, 2018, the change in fair value of interest rate swaps was an increase in the liability of less than $1 million and $4 million, respectively, compared with an increase in liability of less than $1 million and $3 million in the third quarter and first nine 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 nine months ended September 30, 2017, HIP had interest rate swaps with gross notional amounts totaling $459 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 nine months ended September 30, 2017, the change in fair value of interest rate swaps was an increase to assets of $1 million and $2 million, respectively. Derivative contracts not designated as hedging instruments: Crude oil collars: For the three and nine months ended September 30, 2018 , noncash adjustments to c rude 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 $4 million and $20 million, respectively. At September 30, 2018, after-tax deferred losses in in connection with the de-designation, were $3 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 in Revenues and non-operating income in the were losses of $4 million in the three months and nine months ended September 30, 2018, respectively, compared with gains of $17 million and $26 million in the three months and nine months ended September 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 less than $1 million and $1 million in the three months and nine months ended September 30, 2018, respectively, compared to gains of less than $1 million and $2 million in the third quarter and first nine 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 September 30, 2018. Total long-term debt, excluding capital leases, with a carrying value of $6,421 million at September 30, 2018, had a fair value of $6,925 million based on Level 2 inputs.

Subsequent Event

Subsequent Event	9 Months Ended
	Sep. 30, 2018
Subsequent Events [Abstract]
Subsequent Event	16. Subsequent Events In October, at Block 42, Offshore Suriname (Hess – 33%), the operator, Kosmos Energy Ltd, completed drilling operations on the Pontoenoe-1 exploration well. High-quality reservoir was encountered, but commercial quantities of hydrocarbons were not discovered. Third quarter results include $25 million in exploration expense for well costs incurred through September 30, 2018. We estimate approximately $10 million of exploration expense will be recognized in the fourth quarter of 2018 for well costs incurred after September 30, 2018. In early November, the operator, BP Canada, completed drilling of the Aspy exploration well, offshore Nova Scotia, Canada (Hess – 50%). The well did not encounter commercial quantities of hydrocarbons and third quarter results include $94 million in exploration expense for well costs incurred through September 30, 2018. We estimate approximately $30 million of exploration expense will be recognized in the fourth quarter of 2018 for well costs incurred after September 30, 2018.

Basis of Presentation (Policies

Basis of Presentation (Policies)	9 Months Ended
	Sep. 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 supersedes ASC 840 and will require the recognition of right-of-use assets and lease liabilities for all leases with lease terms greater than one year, including leases currently treated as operating leases under ASC 840. ASC 842 is effective for us beginning in the first quarter of 2019, with early adoption permitted. We have elected to adopt ASC 842 on January 1, 2019 using the modified retrospective method which allows application of the new standard prospectively from the date of adoption with a cumulative effect adjustment, if any, recorded to Retained Earnings at the date of adoption. Accordingly, comparative financial statements for periods prior to the adoption date of ASC 842 will not be affected. In addition, we have elected to apply the ‘package’ of practical expedients allowing us to avoid reassessing whether existing contracts are (or contain) leases, whether the lease classification for existing leases would differ under ASC 842, and whether initial direct costs incurred for existing leases are capitalizable under ASC 842. Finally, we have elected to apply the practical expedient allowing us to avoid reassessing land easements that were not previously accounted for as leases under ASC 840. We have not elected the ‘hindsight’ practical expedient when determining lease term. As part of our ASC 842 implementation project, we continue to evaluate contracts, monitor standard setting activity, and evaluate our internal controls to comply with the accounting and disclosure requirements of ASC 842. Although we cannot reasonably estimate the quantitative impact ASC 842 will have on our consolidated financial statements at the effective date, we believe adoption will have a material effect on our Consolidated Balance Sheet due to the recognition of right-of-use assets and lease liabilities for all leases with lease terms greater than one year. We enter into various leases in the normal course of business primarily for drilling rigs, a floating storage and offloading vessel, support vessels, and office space. In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment In February 2018, the FASB issued ASU 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income Accumulated other comprehensive income (loss) Retained earnings Accumulated other comprehensive income (loss)

Revenue (Tables)

Revenue (Tables)	9 Months Ended
	Sep. 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 Three Months Ended September 30, 2018 (In millions) Sales of our net production volumes: Crude oil revenue $ 826 $ 54 $ 108 $ 29 $ 1,017 $ — $ — $ 1,017 Natural gas liquids revenue 90 — — — 90 — — 90 Natural gas revenue 44 3 5 178 230 — — 230 Sales of purchased oil and gas 482 — 22 — 504 — — 504 Intercompany revenue — — — — — 184 (184 ) — Total revenues from contracts with customers 1,442 57 135 207 1,841 184 (184 ) 1,841 Other operating revenue (a) (48 ) — — — (48 ) — — (48 ) Total sales and other operating revenues $ 1,394 $ 57 $ 135 $ 207 $ 1,793 $ 184 $ (184 ) $ 1,793 (a) Includes gains (losses) on commodity derivatives. Exploration and Production Midstream Eliminations Total United States Europe Africa Asia E&P Total Nine Months Ended September 30, 2018 (In millions) Sales of our net production volumes: Crude oil revenue $ 2,111 $ 106 $ 317 $ 100 $ 2,634 $ — $ — $ 2,634 Natural gas liquids revenue 236 — — — 236 — — 236 Natural gas revenue 120 8 20 471 619 — — 619 Sales of purchased oil and gas 1,231 — 68 14 1,313 — — 1,313 Intercompany revenue — — — — — 527 (527 ) — Total revenues from contracts with customers 3,698 114 405 585 4,802 527 (527 ) 4,802 Other operating revenue (a) (129 ) — — — (129 ) — — (129 ) Total sales and other operating revenues $ 3,569 $ 114 $ 405 $ 585 $ 4,673 $ 527 $ (527 ) $ 4,673 (a) Includes gains (losses) on commodity derivatives.

Inventories (Tables)

Inventories (Tables)	9 Months Ended
	Sep. 30, 2018
Inventory Disclosure [Abstract]
Inventories	Inventories consisted of the following: September 30, December 31, 2018 2017 (In millions) Crude oil and natural gas liquids $ 81 $ 59 Materials and supplies 182 173 Total Inventories $ 263 $ 232

Capitalized Exploratory Well _2

Capitalized Exploratory Well Costs (Tables)	9 Months Ended
	Sep. 30, 2018
Capitalized Exploratory Well Costs [Abstract]
Net Changes in Capitalized Exploratory Well Costs	The following table discloses the net changes in capitalized exploratory well costs pending determination of proved reserves during the nine months ended September 30, 2018 (in millions): Balance at January 1, 2018 $ 304 Additions to capitalized exploratory well costs pending the determination of proved reserves 102 Capitalized exploratory well costs charged to expense (13 ) Balance at September 30, 2018 $ 393

Retirement Plans (Tables)

Retirement Plans (Tables)	9 Months Ended
	Sep. 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 Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (In millions) Service cost $ 10 $ 13 $ 34 $ 41 Interest cost 24 25 71 77 Expected return on plan assets (49 ) (42 ) (147 ) (125 ) Amortization of unrecognized net actuarial losses 8 13 29 46 Curtailment gains — — (2 ) — Settlement loss — 4 — 11 Pension (income) expense $ (7 ) $ 13 $ (15 ) $ 50

Weighted Average Common Shares

Weighted Average Common Shares (Tables)	9 Months Ended
	Sep. 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 Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (In millions) Net income (loss) attributable to Hess Corporation Common Stockholders: Net income (loss) $ 3 $ (593 ) $ (149 ) $ (1,306 ) Less: Net income (loss) attributable to noncontrolling interests 45 31 129 91 Less: Preferred stock dividends 11 11 34 34 Net income (loss) attributable to Hess Corporation Common Stockholders $ (53 ) $ (635 ) $ (312 ) $ (1,431 ) Weighted average number of common shares outstanding: Basic 294.3 314.5 300.4 314.3 Effect of dilutive securities Restricted common stock — — — — Stock options — — — — Performance share units — — — — Mandatory convertible preferred stock — — — — Diluted 294.3 314.5 300.4 314.3
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 Nine Months Ended September 30, September 30, 2018 2017 2018 2017 Restricted common stock 2,898,733 3,313,441 2,890,171 3,296,718 Stock options 5,324,682 6,509,214 5,585,088 6,452,788 Performance share units 1,301,604 709,445 999,029 514,910 Common shares from conversion of preferred stocks 12,547,650 13,400,515 12,560,091 12,894,078

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 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 September 30, 2018 Sales and Other Operating Revenues - Third-parties $ 1,793 $ — $ — $ — $ 1,793 Intersegment Revenues — 184 — (184 ) — Sales and Other Operating Revenues $ 1,793 $ 184 $ — $ (184 ) $ 1,793 Net Income (Loss) attributable to Hess Corporation $ 50 $ 30 $ (122 ) $ — $ (42 ) Depreciation, Depletion and Amortization 457 32 — — 489 Provision (Benefit) for Income Taxes 100 10 11 — 121 Capital Expenditures 500 83 — — 583 For the Three Months Ended September 30, 2017 Sales and Other Operating Revenues - Third-parties $ 1,347 $ 1 $ — $ — $ 1,348 Intersegment Revenues — 153 — (153 ) — Sales and Other Operating Revenues $ 1,347 $ 154 $ — $ (153 ) $ 1,348 Net Income (Loss) attributable to Hess Corporation $ (474 ) $ (12 ) $ (138 ) $ — $ (624 ) Depreciation, Depletion and Amortization 709 29 21 — 759 Impairment 2,503 — — — 2,503 Provision (Benefit) for Income Taxes (1,969 ) (3 ) (2 ) — (1,974 ) Capital Expenditures 526 27 — — 553 For the Nine Months Ended September 30, 2018 Sales and Other Operating Revenues - Third-parties $ 4,673 $ — $ — $ — $ 4,673 Intersegment Revenues — 527 — (527 ) — Sales and Other Operating Revenues $ 4,673 $ 527 $ — $ (527 ) $ 4,673 Net Income (Loss) attributable to Hess Corporation $ 56 $ 88 $ (422 ) $ — $ (278 ) Depreciation, Depletion and Amortization 1,249 94 7 — 1,350 Provision (Benefit) for Income Taxes 300 28 (20 ) — 308 Capital Expenditures 1,340 204 — — 1,544 For the Nine Months Ended September 30, 2017 Sales and Other Operating Revenues - Third-parties $ 3,797 $ 6 $ — $ — $ 3,803 Intersegment Revenues — 454 — (454 ) — Sales and Other Operating Revenues $ 3,797 $ 460 $ — $ (454 ) $ 3,803 Net Income (Loss) attributable to Hess Corporation $ (1,061 ) $ 22 $ (358 ) $ — $ (1,397 ) Depreciation, Depletion and Amortization 2,120 93 24 — 2,237 Impairment 2,503 — — — 2,503 Provision (Benefit) for Income Taxes (2,003 ) 18 (10 ) — (1,995 ) Capital Expenditures 1,351 75 — — 1,426 Identifiable assets by operating segment were as follows: September 30, December 31, 2018 2017 (In millions) Exploration and Production $ 16,387 $ 15,613 Midstream 3,540 3,329 Corporate, Interest and Other 1,540 4,170 Total $ 21,467 $ 23,112

Financial Risk Management Act_2

Financial Risk Management Activities (Tables)	9 Months Ended
	Sep. 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: September 30, 2018 December 31, 2017 Calendar year program 2018 2019 2018 Instrument type Puts Puts Collars Effective date Oct. 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) 10.6 32.9 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: September 30, 2018 December 31, 2017 (In millions) Foreign exchange $ 9 $ 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) September 30, 2018 Derivative Contracts Designated as Hedging Instruments Commodity - Accounts receivable and Accounts payable $ 66 $ (8 ) Interest rate - Other liabilities and deferred credits (noncurrent) — (5 ) Total derivative contracts designated as hedging instruments 66 (13 ) Gross fair value of derivative contracts 66 (13 ) Net Fair Value of Derivative Contracts $ 66 $ (13 ) 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 )

Basis of Presentation - Additio

Basis of Presentation - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 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		$ 0		$ 9
Cumulative effect of hedging ineffectiveness					$ 0	$ (37)
Lease, practical expedients, package			true
Lease, practical expedient, use of hindsight			false
Prior Period Adjustment [Abstract]
Sales and other operating revenue	$ 1,793	1,348	$ 4,673	3,803
Marketing, including purchased oil and gas	$ 491	338	$ 1,299	791
Restatement Adjustment
Prior Period Adjustment [Abstract]
Sales and other operating revenue		(22)		(60)
Marketing, including purchased oil and gas		(22)		(60)
Scenario Previously Reported
Prior Period Adjustment [Abstract]
Sales and other operating revenue		1,370		3,863
Marketing, including purchased oil and gas		$ 360		$ 851
Retained Earnings
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Cumulative effect of hedging ineffectiveness					1	(39)
Retained Earnings | ASU 2017-12
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Cumulative effect of hedging ineffectiveness					1
Accumulated Other Comprehensive Income (Loss)
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Cumulative effect of hedging ineffectiveness					(1)	$ 0
Accumulated Other Comprehensive Income (Loss) | ASU 2017-12
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Cumulative effect of hedging ineffectiveness					$ (1)

Revenue - Summary of Revenue fr

Revenue - Summary of Revenue from Contracts with Customers on a Disaggregated Basis (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	$ 1,841		$ 4,802
Other operating revenue, includes gains (losses) on commodity derivatives	(48)		(129)
Total sales and other operating revenues	1,793	$ 1,348	4,673	$ 3,803
Exploration and Production
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	1,841		4,802
Other operating revenue, includes gains (losses) on commodity derivatives	(48)		(129)
Total sales and other operating revenues	1,793		4,673
Exploration and Production | United States
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	1,442		3,698
Other operating revenue, includes gains (losses) on commodity derivatives	(48)		(129)
Total sales and other operating revenues	1,394		3,569
Exploration and Production | Europe
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	57		114
Other operating revenue, includes gains (losses) on commodity derivatives	0		0
Total sales and other operating revenues	57		114
Exploration and Production | Africa
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	135		405
Other operating revenue, includes gains (losses) on commodity derivatives	0		0
Total sales and other operating revenues	135		405
Exploration and Production | Asia
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	207		585
Other operating revenue, includes gains (losses) on commodity derivatives	0		0
Total sales and other operating revenues	207		585
Midstream
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	184		527
Other operating revenue, includes gains (losses) on commodity derivatives	0		0
Total sales and other operating revenues	184		527
Midstream | Intercompany Revenue
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	184		527
Crude Oil Revenue
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	1,017		2,634
Crude Oil Revenue | Exploration and Production
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	1,017		2,634
Crude Oil Revenue | Exploration and Production | United States
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	826		2,111
Crude Oil Revenue | Exploration and Production | Europe
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	54		106
Crude Oil Revenue | Exploration and Production | Africa
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	108		317
Crude Oil Revenue | Exploration and Production | Asia
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	29		100
Natural Gas Liquids Revenue
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	90		236
Natural Gas Liquids Revenue | Exploration and Production
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	90		236
Natural Gas Liquids Revenue | Exploration and Production | United States
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	90		236
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	230		619
Natural Gas Revenue | Exploration and Production
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	230		619
Natural Gas Revenue | Exploration and Production | United States
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	44		120
Natural Gas Revenue | Exploration and Production | Europe
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	3		8
Natural Gas Revenue | Exploration and Production | Africa
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	5		20
Natural Gas Revenue | Exploration and Production | Asia
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	178		471
Sales of Purchased Oil and Gas
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	504		1,313
Sales of Purchased Oil and Gas | Exploration and Production
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	504		1,313
Sales of Purchased Oil and Gas | Exploration and Production | United States
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	482		1,231
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		68
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	(184)		(527)
Other operating revenue, includes gains (losses) on commodity derivatives	0		0
Total sales and other operating revenues	(184)	$ (153)	(527)	$ (454)
Eliminations | Intercompany Revenue
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	(184)		(527)
Eliminations | Sales of Purchased Oil and Gas
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	$ 0		$ 0

Revenue - Additional Informatio

Revenue - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 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 Progr_2

Common Stock Repurchase Program - Additional Information (Details) shares in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2018USD ($)shares	Sep. 30, 2018USD ($)shares	Sep. 30, 2018USD ($)shares
Equity [Abstract]
Common stock repurchased, share repurchase program	$ 250,000,000	$ 1,130,000,000	$ 1,250,000,000
Common stock repurchased, share repurchase program, share | shares	3.8	20.4	23
Share repurchase program, amount	$ 1,500,000,000	$ 1,500,000,000	$ 1,500,000,000

Debt - Additional Information (

Debt - Additional Information (Detail) - USD ($)	3 Months Ended			9 Months Ended
	Sep. 30, 2018	Mar. 31, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Jun. 30, 2018	Dec. 31, 2017
Debt Instrument Redemption [Line Items]
Debt instrument redemption amount						$ 138,000,000
Current maturities of long-term debt	$ 85,000,000			$ 85,000,000			$ 580,000,000
Redeemed and repurchased debt				terminated interest rate swaps with a notional amount of $350 million.
Loss on debt extinguishment	$ 0		$ 0	$ 53,000,000	$ 0
Loss on debt extinguishment, after income tax				53,000,000
Proceeds from asset sales				$ 607,000,000	$ 783,000,000
Floating, Storage and Offloading Vessel
Debt Instrument Redemption [Line Items]
North Malay Basin, offshore Peninsular Malaysia - Hess operated interest	50.00%			50.00%
Proceeds from asset sales	$ 260,000,000
Lease description				The lease agreement is for 16 years with four consecutive twelve-month renewal options that may be exercised at our discretion.
Capital leases carrying value	$ 273,000,000			$ 273,000,000
Percentage of present value of future minimum lease payments equal to carrying value of lease obligations	100.00%			100.00%
Capital lease obligation included in current maturities of long-term debt	$ 15,000,000			$ 15,000,000
Capital lease obligation included in long-term debt	258,000,000			258,000,000
Gain or loss on sale of transaction	$ 0			$ 0
8.125% Notes Due 2019
Debt Instrument Redemption [Line Items]
Debt instrument redemption amount		$ 415,000,000
Debt instrument redemption of principal amount		$ 350,000,000
Debt instrument interest rate		8.125%
Debt instrument maturity year		2,019
Other Notes
Debt Instrument Redemption [Line Items]
Current maturities of long-term debt		$ 38,000,000
Notes Payable
Debt Instrument Redemption [Line Items]
Current maturities of long-term debt						$ 112,000,000

Inventories - Inventories (Deta

Inventories - Inventories (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Crude oil and natural gas liquids	$ 81	$ 59
Materials and supplies	182	173
Total Inventories	$ 263	$ 232

Capitalized Exploratory Well _3

Capitalized Exploratory Well Costs - Net Changes in Capitalized Exploratory Well Costs (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)
Capitalized Exploratory Well Costs [Abstract]
Beginning balance	$ 304
Additions to capitalized exploratory well costs pending the determination of proved reserves	102
Capitalized exploratory well costs charged to expense	(13)
Ending balance	$ 393

Capitalized Exploratory Well _4

Capitalized Exploratory Well Costs - Additional Information (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)
Capitalized Exploratory Well Costs [Line Items]
Cost incurred on unsuccessful exploration wells	$ 119
Capitalized exploratory well costs that have been capitalized for period greater than one year	$ 251
Northern Portion of Shenzi Field, Gulf of Mexico
Capitalized Exploratory Well Costs [Line Items]
Capitalized well costs percentage	45.00%
Project interest percentage	28.00%
Liza-4, Payara-1, Payara-2 and Snoek-1 Wells on the Stabroek Block, Offshore Guyana
Capitalized Exploratory Well Costs [Line Items]
Capitalized well costs percentage	35.00%
Project interest percentage	30.00%
JDA, Gulf of Thailand
Capitalized Exploratory Well Costs [Line Items]
Capitalized well costs percentage	15.00%
Project interest percentage	50.00%
North Malay Basin, offshore Peninsular Malaysia
Capitalized Exploratory Well Costs [Line Items]
Capitalized well costs percentage	5.00%
Project interest percentage	50.00%

Hess Infrastructure Partners _2

Hess Infrastructure Partners LP - Additional Information (Detail) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017	Sep. 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	$ 3,004	$ 4,847	$ 2,526	$ 2,732
Property, plant and equipment, net	16,013	16,192
Hess Infrastructure Partners LP (HIP)
Variable Interest Entity [Line Items]
Cash and cash equivalents	395	356
Property, plant and equipment, net	2,630	2,520
HIP's liabilities on a nonrecourse to Hess Corporation	$ 1,100	$ 1,065

Exit and Disposal Costs - Addit

Exit and Disposal Costs - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Dec. 31, 2017
Restructuring Cost And Reserve [Line Items]
Severance expense			$ 39
Severance costs paid as part of previously announced cost reduction program			39
Accrued severance cost	$ 6		$ 6	$ 6
Expected period for payment for severance cost			We expect to pay in the fourth quarter of 2018
General and Administrative Expenses
Restructuring Cost And Reserve [Line Items]
Charges in connection with vacated office space	$ 57	$ 11

Dispositions - Additional Infor

Dispositions - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from asset sales			$ 607	$ 783
Gain (loss) on asset sales, pre-tax	$ 14	$ 274	$ 32	$ 276
Utica Shale Play, Eastern Ohio
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from asset sales	396
Gain (loss) on asset sales, pre-tax	14
Gain (loss) on asset sales, after-tax	$ 14
Permian Basin
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from asset sales		597
Gain (loss) on asset sales, pre-tax		273
Gain (loss) on asset sales, after-tax		280
Exploration and Production | Permian Basin
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain (loss) on asset sales, after-tax		314
Midstream | Permian Basin
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Gain (loss) on asset sales, after-tax		$ (34)

Impairment - Additional Informa

Impairment - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Impairments [Line Items]
Impairment charge, pre-tax	$ 0	$ 2,503	$ 0	$ 2,503
Norway
Impairments [Line Items]
Impairment charge, pre-tax		2,503
Impairment charge, after-tax		$ 550

Retirement Plans - Components o

Retirement Plans - Components of Net Periodic Pension Cost (Detail) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2018	Mar. 31, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Compensation And Retirement Disclosure [Abstract]
Service cost	$ 10		$ 13	$ 34	$ 41
Interest cost	24		25	71	77
Expected return on plan assets	(49)		(42)	(147)	(125)
Amortization of unrecognized net actuarial losses	8		13	29	46
Curtailment gains	0	$ (2)	0	(2)	0
Settlement loss	0		4	0	11
Pension (income) expense	$ (7)		$ 13	$ (15)	$ 50

Retirement Plans - Additional I

Retirement Plans - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended			9 Months Ended		12 Months Ended
	Sep. 30, 2018	Mar. 31, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 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		13	34	41
Total interest costs	24		25	71	77
Total amortization of unrecognized net actuarial losses	(8)		(13)	(29)	(46)
Total expected return on plan assets	49		42	147	125
Net non-service pension (income) costs included in Other, net	(17)		$ 0	(49)	$ 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				$ 35
U.S. Retirement Plans
Defined Benefit Plan Disclosure [Line Items]
Total decrease in post retirement 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 Share_2

Weighted Average Common Shares - Basic and Diluted Earnings Per Share (Detail) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Net income (loss) attributable to Hess Corporation Common Stockholders:
Net Income (Loss)	$ 3	$ (593)	$ (149)	$ (1,306)
Less: Net income (loss) attributable to noncontrolling interests	45	31	129	91
Less: Preferred stock dividends	11	11	34	34
Net Income (Loss) Attributable to Hess Corporation Common Stockholders	$ (53)	$ (635)	$ (312)	$ (1,431)
Weighted average number of common shares outstanding:
Shares outstanding – Basic	294.3	314.5	300.4	314.3
Diluted	294.3	314.5	300.4	314.3
Restricted Common Stock
Weighted average number of common shares outstanding:
Effect of dilutive securities	0	0
Stock Options
Weighted average number of common shares outstanding:
Effect of dilutive securities	0	0
Performance Share Units
Weighted average number of common shares outstanding:
Effect of dilutive securities	0	0
Mandatory Convertible Preferred Stock
Weighted average number of common shares outstanding:
Effect of dilutive securities	0	0

Weighted Average Common Share_3

Weighted Average Common Shares - Antidilutive Shares Excluded from Computation of Diluted Shares (Detail) - shares	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Restricted Common Stock
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Antidilutive shares excluded from computation of diluted shares	2,898,733	3,313,441	2,890,171	3,296,718
Stock Options
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Antidilutive shares excluded from computation of diluted shares	5,324,682	6,509,214	5,585,088	6,452,788
Performance Share Units
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Antidilutive shares excluded from computation of diluted shares	1,301,604	709,445	999,029	514,910
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	13,400,515	12,560,091	12,894,078

Weighted Average Common Share_4

Weighted Average Common Shares - Additional Information (Detail) - shares	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Equity [Abstract]
Shares granted, restricted stock	1,255,799	1,214,460
Shares granted, performance share units	278,003	438,980
Shares granted, stock options	683,167	662,819

Guarantees and Contingencies -

Guarantees and Contingencies - Additional Information (Detail) $ in Millions	Sep. 28, 2017USD ($)	Mar. 04, 2016USD ($)	Mar. 31, 2014USD ($)	Sep. 30, 2018Case
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
Gowanus Canal Superfund Site
Loss Contingencies [Line Items]
Estimated remediation cost			$ 506
Ector Drum, Inc. Superfund Site
Loss Contingencies [Line Items]
Estimated remediation cost	$ 3.5

Segment Information - Additiona

Segment Information - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2018Segment
Segment Reporting [Abstract]
Number of operating segments for the Corporation	2

Segment Information - Financial

Segment Information - Financial Data by Operating Segment (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Segment Reporting Information [Line Items]
Sales and other operating revenues - third-parties	$ 1,793	$ 1,348	$ 4,673	$ 3,803
Total sales and other operating revenues	1,793	1,348	4,673	3,803
Net Income (Loss) attributable to Hess Corporation	(42)	(624)	(278)	(1,397)
Depreciation, depletion and amortization	489	759	1,350	2,237
Impairment	0	2,503	0	2,503
Provision (benefit) for income taxes	121	(1,974)	308	(1,995)
Capital Expenditures	583	553	1,544	1,426
Identifiable assets	21,467		21,467		$ 23,112
Eliminations
Segment Reporting Information [Line Items]
Intersegment revenues	(184)	(153)	(527)	(454)
Total sales and other operating revenues	(184)	(153)	(527)	(454)
Exploration and Production
Segment Reporting Information [Line Items]
Total sales and other operating revenues	1,793		4,673
Exploration and Production | Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues - third-parties	1,793	1,347	4,673	3,797
Total sales and other operating revenues	1,793	1,347	4,673	3,797
Net Income (Loss) attributable to Hess Corporation	50	(474)	56	(1,061)
Depreciation, depletion and amortization	457	709	1,249	2,120
Impairment		2,503		2,503
Provision (benefit) for income taxes	100	(1,969)	300	(2,003)
Capital Expenditures	500	526	1,340	1,351
Identifiable assets	16,387		16,387		15,613
Midstream
Segment Reporting Information [Line Items]
Total sales and other operating revenues	184		527
Midstream | Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues - third-parties		1		6
Intersegment revenues	184	153	527	454
Total sales and other operating revenues	184	154	527	460
Net Income (Loss) attributable to Hess Corporation	30	(12)	88	22
Depreciation, depletion and amortization	32	29	94	93
Provision (benefit) for income taxes	10	(3)	28	18
Capital Expenditures	83	27	204	75
Identifiable assets	3,540		3,540		3,329
Corporate, Interest and Other | Operating Segments
Segment Reporting Information [Line Items]
Net Income (Loss) attributable to Hess Corporation	(122)	(138)	(422)	(358)
Depreciation, depletion and amortization		21	7	24
Provision (benefit) for income taxes	11	$ (2)	(20)	$ (10)
Identifiable assets	$ 1,540		$ 1,540		$ 4,170

Financial Risk Management Act_3

Financial Risk Management Activities - Gross Notional Amounts of Outstanding Financial Risk Management Derivative Contracts (Detail) - WTI	9 Months Ended	12 Months Ended
	Sep. 30, 2018MMBbls$ / bbl	Dec. 31, 2017MMBbls$ / bbl
2,018
Derivative [Line Items]
Calendar year program	2,018	2,018
Instrument type	Puts	Collars
Effective date	Oct. 1, 2018	Jan. 1, 2018
End date	Dec. 31, 2018	Dec. 31, 2018
Crude oil volumes (millions of barrels) | MMBbls	10.6	42
Ceiling price	0	65
Floor price	50	50
2,019
Derivative [Line Items]
Calendar year program	2,019
Instrument type	Puts
Effective date	Jan. 1, 2019
End date	Dec. 31, 2019
Crude oil volumes (millions of barrels) | MMBbls	32.9
Ceiling price	0
Floor price	60

Financial Risk Management Act_4

Financial Risk Management Activities - Additional Information (Detail)	3 Months Ended			9 Months Ended		12 Months Ended
	Sep. 30, 2018USD ($)$ / bbl	Mar. 31, 2018USD ($)bbl / d	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)bbl / d$ / bbl	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)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	$ (45,000,000)			$ (119,000,000)
Increased (decreased) sales and other operating revenue			$ 6,000,000		$ (5,000,000)
After-tax deferred gain (losses) related to outstanding crude oil price hedging contracts Accumulated other comprehensive income (loss) to be reclassified into earnings	0		0	(92,000,000)	0
After-tax deferred losses related to outstanding crude oil price hedging contracts to be reclassified into earnings during the next twelve months				(90,000,000)
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	$ (4,000,000)			(20,000,000)
After-tax deferred gain (losses) related to outstanding crude oil price hedging contracts Accumulated other comprehensive income (loss) to be reclassified into earnings				$ (3,000,000)
2018 | West Texas Intermediate Crude Oil Price Hedging Contracts
Derivative Instruments Gain Loss [Line Items]
Monthly floor price | $ / bbl	50			50		50
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 Hedging Contracts | Designated as Cash Flow Hedges
Derivative Instruments Gain Loss [Line Items]
Monthly floor price | $ / bbl	50			50		50
Monthly ceiling price | $ / bbl						65
2019 | West Texas Intermediate Crude Oil Price Hedging Contracts
Derivative Instruments Gain Loss [Line Items]
Monthly floor price | $ / bbl	60			60
Monthly ceiling price | $ / bbl	0			0
2019 | West Texas Intermediate Crude Oil Price Hedging Contracts | Designated as Cash Flow Hedges
Derivative Instruments Gain Loss [Line Items]
Monthly floor price | $ / bbl	60			60
Notional amount of outstanding average barrels of oil per day | bbl / d				90,000
Interest Rate Swaps | Designated as Cash Flow Hedges
Derivative Instruments Gain Loss [Line Items]
Outstanding gross notional amount					459,000,000
Change in fair value of interest rate swaps - increase/(decrease)			1,000,000		2,000,000
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
Interest Rate Swaps | Designated as Fair Value Hedges | Maximum
Derivative Instruments Gain Loss [Line Items]
Unrealized change in fair value of interest rate swaps - increase in derivative liability	1,000,000		1,000,000	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	9,000,000			9,000,000		$ 52,000,000
Foreign exchange gains and (losses) reported in Other, net	(4,000,000)		17,000,000	(4,000,000)	26,000,000
Foreign Exchange | Derivative Contracts Not Designated as Hedging Instruments | Maximum
Derivative Instruments Gain Loss [Line Items]
Foreign exchange gains (losses) from foreign exchange derivative contracts that are not designated as hedges	$ (1,000,000)		$ 1,000,000	$ (1,000,000)	$ 2,000,000

Financial Risk Management Act_5

Financial Risk Management Activities - Gross Notional Amounts of Derivative Contracts Outstanding Excluding Commodity Contracts (Detail) - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Foreign Exchange
Derivative [Line Items]
Outstanding gross notional amount	$ 9,000,000	$ 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 Act_6

Financial Risk Management Activities - Gross and Net Fair Values (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivatives Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	$ 66	$ 1
Assets - Net Fair Value of Derivative Contracts	66	1
Liabilities - Gross fair value of derivative contracts	(13)	(13)
Liabilities - Net Fair Value of Derivative Contracts	(13)	(13)
Derivative Contracts Designated as Hedging Instruments
Derivatives Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	66	0
Liabilities - Gross fair value of derivative contracts	(13)	(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	66
Liabilities - Gross fair value of derivative contracts	(8)
Derivative Contracts Designated as Hedging Instruments | Commodity | Accounts Payable
Derivatives Fair Value [Line Items]
Assets - Gross fair value of derivative contracts		0
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]
Assets - Gross fair value of derivative contracts		0
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]
Assets - Gross fair value of derivative contracts	0
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]
Assets - Gross fair value of derivative contracts		0
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
Liabilities - Gross fair value of derivative contracts		$ 0

Financial Risk Management Act_7

Financial Risk Management Activities - Fair Value Measurements - Additional Information (Detail) $ in Millions	Sep. 30, 2018USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total long-term debt excluding capital lease, carrying value	$ 6,421
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total long-term debt excluding capital lease, fair value	$ 6,925

Subsequent Event - Additional I

Subsequent Event - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Sep. 30, 2018	Nov. 08, 2018	Oct. 31, 2018
Subsequent Event [Line Items]
Cost incurred on unsuccessful exploration wells			$ 13
Offshore Suriname
Subsequent Event [Line Items]
Cost incurred on unsuccessful exploration wells		$ 25
Offshore Suriname | Forecast
Subsequent Event [Line Items]
Cost incurred on unsuccessful exploration wells	$ 10
Offshore Nova Scotia, Canada
Subsequent Event [Line Items]
Cost incurred on unsuccessful exploration wells			$ 94
Offshore Nova Scotia, Canada | Forecast
Subsequent Event [Line Items]
Cost incurred on unsuccessful exploration wells	$ 30
Subsequent Event | Offshore Suriname
Subsequent Event [Line Items]
Project interest percentage					33.00%
Subsequent Event | Offshore Nova Scotia, Canada
Subsequent Event [Line Items]
Project interest percentage				50.00%