Hess (HES) 10-Q 1 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information	3 Months Ended
	Mar. 31, 2018shares
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1
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 Common Stock, Shares Outstanding	308,055,101

Consolidated Balance Sheet

Consolidated Balance Sheet - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 3,726	$ 4,847
Accounts receivable:
From contracts with customers	729	677
Joint venture and other	268	347
Inventories	239	232
Other current assets	52	54
Total current assets	5,014	6,157
Property, plant and equipment:
Total — at cost	32,906	32,504
Less: Reserves for depreciation, depletion, amortization and lease impairment	16,725	16,312
Property, plant and equipment — net	16,181	16,192
Goodwill	360	360
Deferred income taxes	22	21
Other assets	495	382
Total Assets	22,072	23,112
Current Liabilities:
Accounts payable	375	435
Accrued liabilities	1,251	1,337
Taxes payable	82	83
Current maturities of long-term debt	196	580
Total current liabilities	1,904	2,435
Long-term debt	6,372	6,397
Deferred income taxes	425	429
Asset retirement obligations	774	753
Other liabilities and deferred credits	660	744
Total Liabilities	10,135	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 — 308,055,101 shares (2017: 315,053,615)	308	315
Capital in excess of par value	5,701	5,824
Retained earnings	5,166	5,597
Accumulated other comprehensive income (loss)	(571)	(686)
Total Hess Corporation stockholders’ equity	10,605	11,051
Noncontrolling interests	1,332	1,303
Total equity	11,937	12,354
Total Liabilities and Equity	$ 22,072	$ 23,112

Consolidated Balance Sheet (Par

Consolidated Balance Sheet (Parenthetical) - $ / shares	3 Months Ended	12 Months Ended
	Mar. 31, 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	308,055,101	315,053,615

Statement of Consolidated Incom

Statement of Consolidated Income - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues and Non-Operating Income
Sales and other operating revenues	$ 1,346	$ 1,258
Gains on asset sales, net	7	0
Other, net	37	(4)
Total revenues and non-operating income	1,390	1,254
Costs and Expenses
Marketing, including purchased oil and gas	358	200
Operating costs and expenses	288	358
Production and severance taxes	39	31
Exploration expenses, including dry holes and lease impairment	40	58
General and administrative expenses	110	95
Interest expense	103	84
Loss on debt extinguishment	27	0
Depreciation, depletion and amortization	417	737
Total costs and expenses	1,382	1,563
Income (Loss) Before Income Taxes	8	(309)
Provision (benefit) for income taxes	73	(13)
Net Income (Loss)	(65)	(296)
Less: Net income (loss) attributable to noncontrolling interests	41	28
Net Income (Loss) Attributable to Hess Corporation	(106)	(324)
Less: Preferred stock dividends	11	12
Net Income (Loss) Attributable to Hess Corporation Common Stockholders	$ (117)	$ (336)
Net Income (Loss) Attributable to Hess Corporation Per Common Share:
Basic	$ (0.38)	$ (1.07)
Diluted	$ (0.38)	$ (1.07)
Weighted Average Number of Common Shares Outstanding (Diluted)	309.5	313.9
Common Stock Dividends Per Share	$ 0.25	$ 0.25

Statement of Consolidated Compr

Statement of Consolidated Comprehensive Income - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Statement Of Income And Comprehensive Income [Abstract]
Net Income (Loss)	$ (65)	$ (296)
Derivatives designated as cash flow hedges
Effect of hedge (gains) losses reclassified to income	31	0
Income taxes on effect of hedge (gains) losses reclassified to income	0	0
Net effect of hedge (gains) losses reclassified to income	31	0
Change in fair value of cash flow hedges	(22)	4
Income taxes on change in fair value of cash flow hedges	0	(2)
Net change in fair value of cash flow hedges	(22)	2
Change in derivatives designated as cash flow hedges, after taxes	9	2
Pension and other postretirement plans
(Increase) reduction in unrecognized actuarial losses	125	7
Income taxes on actuarial changes in plan liabilities	(30)	(3)
(Increase) reduction in unrecognized actuarial losses, net	95	4
Amortization of net actuarial losses	12	17
Income taxes on amortization of net actuarial losses	0	0
Net effect of amortization of net actuarial losses	12	17
Change in pension and other postretirement plans, after taxes	107	21
Foreign currency translation adjustment
Foreign currency translation adjustment	0	14
Change in foreign currency translation adjustment	0	14
Other Comprehensive Income	116	37
Comprehensive Income (Loss)	51	(259)
Less: Comprehensive income attributable to noncontrolling interests	41	28
Comprehensive Income (Loss) Attributable to Hess Corporation	$ 10	$ (287)

Statement of Consolidated Cash

Statement of Consolidated Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash Flows From Operating Activities
Net income (loss)	$ (65)	$ (296)
Adjustments to reconcile to net cash provided by (used in) operating activities
(Gains) losses on asset sales, net	(7)	0
Depreciation, depletion and amortization	417	737
Exploration lease and other impairment	10	7
Stock compensation expense	13	22
Non-cash (gains) losses on commodity derivatives, net	38	0
Provision (benefit) for deferred income taxes and other tax accruals	(36)	(27)
Loss on debt extinguishment	27	0
Changes in operating assets and liabilities
(Increase) decrease in accounts receivable	(11)	115
(Increase) decrease in inventories	(7)	(55)
Increase (decrease) in accounts payable and accrued liabilities	(135)	(115)
Increase (decrease) in taxes payable	(1)	6
Changes in other operating assets and liabilities	(33)	(45)
Net cash provided by (used in) operating activities	210	349
Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P	(363)	(340)
Additions to property, plant and equipment - Midstream	(37)	(50)
Payments for Midstream equity investments	(24)	0
Proceeds from asset sales	6	100
Other, net	(4)	0
Net cash provided by (used in) investing activities	(422)	(290)
Cash Flows From Financing Activities
Net borrowings (repayments) of debt with maturities of 90 days or less	0	5
Debt with maturities of greater than 90 days – Borrowings	0	0
Debt with maturities of greater than 90 days – Repayments	(434)	(26)
Common stock acquired and retired	(371)	0
Cash dividends paid	(89)	(92)
Noncontrolling interests, net	(12)	0
Other, net	(3)	8
Net cash provided by (used in) financing activities	(909)	(105)
Net Increase (Decrease) in Cash and Cash Equivalents	(1,121)	(46)
Cash and Cash Equivalents at Beginning of Year	4,847	2,732
Cash and Cash Equivalents at End of Period	$ 3,726	$ 2,686

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)	(296)	0	0	0	(324)	0	(324)	28
Other comprehensive income	37	0	0	0	0	37	37	0
Share-based compensation, including income taxes	30	0	1	29	0	0	30	0
Dividends on preferred stock	(12)	0	0	0	(12)	0	(12)	0
Dividends on common stock	(80)	0	0	0	(80)	0	(80)	0
Balance at Mar. 31, 2017	15,233	1	318	5,804	9,692	(1,667)	14,148	1,085
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)	(65)	0	0	0	(106)	0	(106)	41
Other comprehensive income	116	0	0	0	0	116	116	0
Share-based compensation, including income taxes	13	0	1	12	0	0	13	0
Dividends on preferred stock	(11)	0	0	0	(11)	0	(11)	0
Dividends on common stock	(78)	0	0	0	(78)	0	(78)	0
Common stock acquired and retired	(380)	0	(8)	(135)	(237)	0	(380)	0
Noncontrolling interests, net	(12)	0	0	0	0	0	0	(12)
Balance at Mar. 31, 2018	$ 11,937	$ 1	$ 308	$ 5,701	$ 5,166	$ (571)	$ 10,605	$ 1,332

Basis of Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 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 March 31, 2018 and December 31, 2017, the consolidated results of operations for the three months ended March 31, 2018 and 2017, and consolidated cash flows for the three months ended March 31, 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 Statements 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) Consolidated Statements of 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 Consolidated Statements of Cash Flows . To conform with the Statement of Consolidated Income Consolidated Balance Sheet Statement of Consolidated Comprehensive Income Statement of Consolidated Cash Flows Statement of Consolidated Equity New Accounting Pronouncements: In February 2016, the FASB issued ASU 2016-02, Leases , as a new Accounting Standards Codification (ASC) Topic, ASC 842. The new standard will require assets and liabilities to be reported on the Consolidated Balance Sheet for all leases with lease terms greater than one year, including leases currently treated as operating leases under the existing standard. This ASU is effective for us beginning in the first quarter of 2019, with early adoption permitted. We have developed and are executing a project plan for the implementation of ASC 842 in the first quarter of 2019. We are progressing our assessment of existing leases and evaluating our disclosure processes with reference to the requirements of the standard. We continue to assess the impact of the ASU on our consolidated financial statements. In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment

Revenue

Revenue	3 Months Ended
	Mar. 31, 2018
Revenue From Contract With Customer [Abstract]
Revenue	2. Revenue In the first quarter of 2018, 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 Revenues from sales of our net production volumes: Crude oil revenue $ 593 $ 33 $ 99 $ 43 $ 768 $ — $ — $ 768 Natural gas liquids revenue 71 — — — 71 — — 71 Natural gas revenue 39 3 8 128 178 — — 178 Revenue from sale of third-party purchased volumes 325 — 24 14 363 — — 363 Intercompany revenue — — — — — 167 (167 ) — Total revenues from contracts with customers 1,028 36 131 185 1,380 167 (167 ) 1,380 Other operating revenue (a) (34 ) — — — (34 ) — — (34 ) Total sales and other operating revenues $ 994 $ 36 $ 131 $ 185 $ 1,346 $ 167 $ (167 ) $ 1,346 (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. Pricing is determined subsequent to contract inception, but prior to the transfer of control or shortly thereafter if required per contractual terms, with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials. As a result, the entire transaction price at contract inception is variable. We do not apply a constraint to the transaction price at contract inception. 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 minimum volume commitments 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 Contract types The following is a summary of contract types for our E&P segment: Crude oil, natural gas liquids, and natural gas – 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, prior to transfer of control. 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, prior to the recognition of revenue, 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 March 31, 2018 and December 31, 2017, there were no contract assets or contract liabilities. In the three months ended March 31, 2018, there were no credit losses on receivables with customers. Transaction Price Allocated to Remaining Performance Obligations At March 31, 2018, the transaction price allocated to our unsatisfied performance obligations on uncompleted contracts was entirely variable. 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 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 The minimum volume commitments are subject to fluctuation based on 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. The Midstream segment has elected the practical expedient under the provisions of ASC 606

Debt

Debt	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Debt	3. Debt In the first quarter of 2018, we paid $415 million to redeem $350 million principal amount of 8.125% notes due 2019 with a carrying value of $349 million at December 31, 2017, and to purchase other notes with a carrying value of $38 million at December 31, 2017. Concurrent with the redemption of the 2019 notes, we terminated interest rate swaps with a notional amount of $350 million. First quarter 2018 results included a pre-tax charge of $27 million ($27 million after income taxes) for the loss on extinguishment of the redeemed and purchased notes.

Inventories

Inventories	3 Months Ended
	Mar. 31, 2018
Inventory Disclosure [Abstract]
Inventories	4. Inventories Inventories consisted of the following: March 31, December 31, 2018 2017 (In millions) Crude oil and natural gas liquids $ 64 $ 59 Materials and supplies 175 173 Total Inventories $ 239 $ 232

Capitalized Exploratory Well Co

Capitalized Exploratory Well Costs	3 Months Ended
	Mar. 31, 2018
Capitalized Exploratory Well Costs [Abstract]
Capitalized Exploratory Well Costs	5. Capitalized Exploratory Well Costs The following table discloses the net changes in capitalized exploratory well costs pending determination of proved reserves during the three months ended March 31, 2018 (in millions): Balance at January 1, 2018 $ 304 Additions to capitalized exploratory well costs pending the determination of proved reserves 42 Balance at March 31, 2018 $ 346 Capitalized exploratory well costs capitalized for greater than one year following completion of drilling were $211 million at March 31, 2018 and primarily related to: Gulf of Mexico: Approximately 55% of the capitalized well costs in excess of one year relates to the appraisal of the northern portion of the Shenzi Field (Hess 28% participating interest) in the Gulf of Mexico, where hydrocarbons were encountered in the fourth quarter of 2015. The operator is conducting appraisal activities on adjacent acreage and is evaluating plans for development of the northern portion of the Shenzi Field. Guyana: Approximately 20% of the capitalized well costs in excess of one year primarily relates to the Payara-1 well on the Stabroek Block, offshore Guyana (Hess 30% participating interest), where hydrocarbons were encountered. The operator plans to integrate this discovery into the third phase of development, with first production from this phase planned for late 2023 or early 2024. 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.

Hess Infrastructure Partners LP

Hess Infrastructure Partners LP	3 Months Ended
	Mar. 31, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Hess Infrastructure Partners LP	6. 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 March 31, 2018, HIP liabilities totaling $1,060 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 $375 million (December 31, 2017: $356 million) and property, plant and equipment with a carrying value of $2,527 million (December 31, 2017: $2,520 million).

Severance Costs

Severance Costs	3 Months Ended
	Mar. 31, 2018
Restructuring And Related Activities [Abstract]
Severance Costs	7. Severance Costs In the first quarter of 2018, we recorded severance expense of $46 million, and a reduction to expense of $9 million for stock-based compensation forfeitures, as part of the previously announced cost reduction program. During the first quarter of 2018, we paid severance costs of $21 million. At March 31, 2018, we have accrued severance cost of $31 million (December 31, 2017: $6 million), which we expect to pay in 2018.

Retirement Plans

Retirement Plans	3 Months Ended
	Mar. 31, 2018
Compensation And Retirement Disclosure [Abstract]
Retirement Plans	8. Retirement Plans Components of net periodic pension cost consisted of the following: Three Months Ended March 31, 2018 2017 (In millions) Service cost $ 14 $ 14 Interest cost 23 26 Expected return on plan assets (49 ) (41 ) Amortization of unrecognized net actuarial losses 12 17 Curtailment gains (2 ) — Pension (benefit) expense $ (2 ) $ 16 In 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 now forecast pension service costs of approximately $45 million, interest cost of approximately $95 million, amortization of unrecognized net actuarial losses of approximately $40 million, and estimated expected return on plan assets of approximately $195 million. Net non-service pension costs included in Other, net in the Statement of Consolidated Income for the three months ended March 31, 2018 and 2017, was income of $16 million and expense of $2 million, respectively. In 2018, we expect to contribute $44 million to our funded pension plans. Through March 31, 2018, we have contributed $14 million to these plans.

Weighted Average Common Shares

Weighted Average Common Shares	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Weighted Average Common Shares	9. 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 March 31, 2018 2017 (in millions) Net income (loss) attributable to Hess Corporation Common Stockholders: Net income (loss) $ (65 ) $ (296 ) Less: Net income (loss) attributable to noncontrolling interests 41 28 Less: Preferred stock dividends 11 12 Net income (loss) attributable to Hess Corporation Common Stockholders $ (117 ) $ (336 ) Weighted average common shares outstanding: Basic 309.5 313.9 Effect of dilutive securities Restricted common stock — — Stock options — — Performance share units — — Mandatory convertible preferred stock — — Diluted 309.5 313.9 The following table summarizes the number of antidilutive shares excluded from the computation of diluted shares: Three Months Ended March 31, 2018 2017 Restricted common stock 2,922,316 3,126,222 Stock options 5,807,579 6,298,896 Performance share units 623,088 313,004 Common shares upon conversion of Preferred stocks 12,584,974 12,547,650 During the three months ended March 31, 2018, we granted 1,081,923 shares of restricted stock (2017: 1,206,732), 278,003 performance share units (2017: 438,980) and 683,167 stock options (2017: 662,819).

Guarantees and Contingencies

Guarantees and Contingencies	3 Months Ended
	Mar. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
Guarantees and Contingencies	10. 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 is a defective product and that these parties are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE. The majority of the cases asserted against us have been settled. 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 was filed in state court, but has not been served to date. 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 there are numerous other parties who we expect will share in the cost of remediation and damages and our former terminal did not store or use contaminants which are of the greatest concern in the river sediments and could not have contributed contamination along most of the river’s length. In March 2014, we received an Administrative Order from EPA requiring us and 26 other parties to undertake the Remedial Design for the remedy selected by the EPA for the Gowanus Canal Superfund Site in Brooklyn, New York. The remedy includes dredging of surface sediments and the placement of a cap over the deeper sediments throughout the Canal and in-situ stabilization of certain contaminated sediments that will remain in place below the cap. EPA has estimated that this remedy will cost $506 million; however, the ultimate costs that will be incurred in connection with the design and implementation of the remedy remain uncertain. Our alleged liability derives from our former ownership and operation of a fuel oil terminal and connected ship-building and repair facility adjacent to the Canal. We indicated to EPA that we would comply with the Administrative Order and are currently contributing funding for the Remedial Design based on an interim allocation of costs among the parties. At the same time, we are participating in an allocation process whereby a neutral expert selected by the parties will determine the final shares of the Remedial Design costs to be paid by each of the participants. On September 28, 2017, we received a general notice letter and offer to settle from the U.S. Environmental Protection Agency relating to Superfund claims for the Ector Drum, Inc. Superfund Site in Odessa, TX. The EPA and Texas Commission on Environmental Quality (TCEQ) took clean-up and response action at the site commencing in 2014 and concluded in December 2015. The site was determined to have improperly stored industrial waste, including drums with oily liquids. The total clean-up cost incurred by the EPA was approximately $3.5 million. We were invited to negotiate a voluntary settlement for our purported share of the clean-up costs. Our share, if any, is undetermined. From time to time, we are involved in other judicial and administrative proceedings, including proceedings relating to other environmental matters. We cannot predict with certainty if, how or when such proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages. Numerous issues may need to be resolved, including through potentially lengthy discovery and determination of important factual matters before a loss or range of loss can be reasonably estimated for any proceeding. Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of the aforementioned proceedings are not expected to have a material adverse effect on our financial condition, results of operations or cash flows.

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Segment Information	11. Segment Information The Corporation has 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 March 31, 2018 Sales and Other Operating Revenues - Third-parties $ 1,346 $ — $ — $ — $ 1,346 Intersegment Revenues — 167 — (167 ) — Sales and Other Operating Revenues $ 1,346 $ 167 $ — $ (167 ) $ 1,346 Net Income (Loss) attributable to Hess Corporation $ (25 ) $ 28 $ (109 ) $ — $ (106 ) Depreciation, Depletion and Amortization 385 31 1 — 417 Provision (Benefit) for Income Taxes 95 9 (31 ) — 73 Capital Expenditures 354 37 — — 391 For the Three Months Ended March 31, 2017 Sales and Other Operating Revenues - Third-parties $ 1,256 $ 2 $ — $ — $ 1,258 Intersegment Revenues — 147 — (147 ) — Sales and Other Operating Revenues $ 1,256 $ 149 $ — $ (147 ) $ 1,258 Net Income (Loss) attributable to Hess Corporation $ (233 ) $ 18 $ (109 ) $ — $ (324 ) Depreciation, Depletion and Amortization 703 32 2 — 737 Provision (Benefit) for Income Taxes (20 ) 11 (4 ) — (13 ) Capital Expenditures 342 28 — — 370 Identifiable assets by operating segment were as follows: March 31, December 31, 2018 2017 (In millions) Exploration and Production $ 15,624 $ 15,613 Midstream 3,375 3,329 Corporate, Interest and Other 3,073 4,170 Total $ 22,072 $ 23,112

Financial Risk Management Activ

Financial Risk Management Activities	3 Months Ended
	Mar. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Financial Risk Management Activities	12. 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 March 31, 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 were as follows: March 31, 2018 December 31, 2017 Instrument type Puts Collars Effective date Apr. 1, 2018 Jan. 1, 2018 End date Dec. 31, 2018 Dec. 31, 2018 Crude oil volumes (millions of barrels) 31.6 42.0 Ceiling price N/A $ 65 Floor price $ 50 $ 50 At December 31, 2017, we had WTI crude oil price collars with an average monthly floor price of $50 per barrel and an average monthly ceiling price of $65 per barrel with a notional amount of 115,000 bopd for the full year 2018. In the first quarter of 2018, we bought back the WTI $65 call options within the crude oil price collars for the period of May 1, 2018 through December 31, 2018. As a result, during this period we are able to realize average monthly WTI selling prices above $65 per barrel on the crude oil price collars covering the notional amount of 115,000 bopd. The put options within our crude oil collar contracts remain outstanding with a WTI average monthly floor price of $50 per barrel covering a notional amount of 115,000 bopd through December 31, 2018. The gross notional amounts of outstanding financial risk management derivative contracts, excluding commodity contracts, were as follows: March 31, 2018 December 31, 2017 (In millions) Foreign exchange $ 31 $ 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) March 31, 2018 Derivative Contracts Designated as Hedging Instruments Commodity - Accounts receivable $ 10 $ — Interest rate - Other liabilities and deferred credits (noncurrent) — (4 ) Total derivative contracts designated as hedging instruments 10 (4 ) Derivative Contracts Not Designated as Hedging Instruments Commodity - Accounts receivable 3 — Total derivative contracts not designated as hedging instruments 3 — Gross fair value of derivative contracts 13 (4 ) Net Fair Value of Derivative Contracts $ 13 $ (4 ) 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 collars: Crude oil price hedging contracts decreased Sales and other operating revenues by $30 million in the first quarter of 2018 and decreased Sales and other operating revenues by $1 million in the first quarter of 2017. At March 31, 2018, after-tax deferred losses in related to outstanding hedged crude oil collars were $120 million, of which all will be reclassified into earnings during the remainder of 2018 as the hedged crude oil sales are recognized in earnings. Interest rate swaps designated as fair value hedges: At March 31, 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 . In the first quarter of 2018, the change in fair value of interest rate swaps was an increase in the liability of $3 million (2017 Q1: an increase in the liability of $1 million) 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 3, Debt . Derivative contracts not designated as hedging instruments: Crude oil collars: In the first quarter of 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 $8 million. At March 31, 2018, after-tax deferred losses in in connection with the de-designation, were $11 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 which are reported in in Revenues and non-operating income in the were $4 million in the first quarter of 2018 (2017 Q1: loss of $1 million). A component of foreign exchange gain (loss) is the result of foreign exchange derivative contracts that are not designated as hedges which amounted to a gain of $2 million in the first quarter of 2018 (2017 Q1: loss of less than $1 million). 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 March 31, 2018. Total long-term debt with a carrying value of $6,568 million at March 31, 2018, had a fair value of $7,058 million based on Level 2 inputs.

Subsequent Event

Subsequent Event	3 Months Ended
	Mar. 31, 2018
Subsequent Events [Abstract]
Subsequent Event	13. Subsequent Event In April 2018, we entered into an accelerated share repurchase program (ASR) with a financial institution to repurchase $500 million of our common stock as part of our $1.5 billion share repurchase program. Under the terms of the ASR, we paid $500 million in cash to the financial institution and received an initial delivery of approximately 8 million shares of our common stock with final settlement expected to be completed during the second quarter.

Basis of Presentation (Policies

Basis of Presentation (Policies)	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements: In February 2016, the FASB issued ASU 2016-02, Leases , as a new Accounting Standards Codification (ASC) Topic, ASC 842. The new standard will require assets and liabilities to be reported on the Consolidated Balance Sheet for all leases with lease terms greater than one year, including leases currently treated as operating leases under the existing standard. This ASU is effective for us beginning in the first quarter of 2019, with early adoption permitted. We have developed and are executing a project plan for the implementation of ASC 842 in the first quarter of 2019. We are progressing our assessment of existing leases and evaluating our disclosure processes with reference to the requirements of the standard. We continue to assess the impact of the ASU on our consolidated financial statements. In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment

Revenue (Tables)

Revenue (Tables)	3 Months Ended
	Mar. 31, 2018
Revenue From Contract With Customer [Abstract]
Summary of Revenue from Contracts with Customers on a Disaggregated Basis	In the first quarter of 2018, 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 Revenues from sales of our net production volumes: Crude oil revenue $ 593 $ 33 $ 99 $ 43 $ 768 $ — $ — $ 768 Natural gas liquids revenue 71 — — — 71 — — 71 Natural gas revenue 39 3 8 128 178 — — 178 Revenue from sale of third-party purchased volumes 325 — 24 14 363 — — 363 Intercompany revenue — — — — — 167 (167 ) — Total revenues from contracts with customers 1,028 36 131 185 1,380 167 (167 ) 1,380 Other operating revenue (a) (34 ) — — — (34 ) — — (34 ) Total sales and other operating revenues $ 994 $ 36 $ 131 $ 185 $ 1,346 $ 167 $ (167 ) $ 1,346 (a) Includes gains (losses) on commodity derivatives.

Inventories (Tables)

Inventories (Tables)	3 Months Ended
	Mar. 31, 2018
Inventory Disclosure [Abstract]
Inventories	Inventories consisted of the following: March 31, December 31, 2018 2017 (In millions) Crude oil and natural gas liquids $ 64 $ 59 Materials and supplies 175 173 Total Inventories $ 239 $ 232

Capitalized Exploratory Well 24

Capitalized Exploratory Well Costs (Tables)	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2018 (in millions): Balance at January 1, 2018 $ 304 Additions to capitalized exploratory well costs pending the determination of proved reserves 42 Balance at March 31, 2018 $ 346

Retirement Plans (Tables)

Retirement Plans (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2018 2017 (In millions) Service cost $ 14 $ 14 Interest cost 23 26 Expected return on plan assets (49 ) (41 ) Amortization of unrecognized net actuarial losses 12 17 Curtailment gains (2 ) — Pension (benefit) expense $ (2 ) $ 16

Weighted Average Common Shares

Weighted Average Common Shares (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2018 2017 (in millions) Net income (loss) attributable to Hess Corporation Common Stockholders: Net income (loss) $ (65 ) $ (296 ) Less: Net income (loss) attributable to noncontrolling interests 41 28 Less: Preferred stock dividends 11 12 Net income (loss) attributable to Hess Corporation Common Stockholders $ (117 ) $ (336 ) Weighted average common shares outstanding: Basic 309.5 313.9 Effect of dilutive securities Restricted common stock — — Stock options — — Performance share units — — Mandatory convertible preferred stock — — Diluted 309.5 313.9
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 March 31, 2018 2017 Restricted common stock 2,922,316 3,126,222 Stock options 5,807,579 6,298,896 Performance share units 623,088 313,004 Common shares upon conversion of Preferred stocks 12,584,974 12,547,650

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2018 Sales and Other Operating Revenues - Third-parties $ 1,346 $ — $ — $ — $ 1,346 Intersegment Revenues — 167 — (167 ) — Sales and Other Operating Revenues $ 1,346 $ 167 $ — $ (167 ) $ 1,346 Net Income (Loss) attributable to Hess Corporation $ (25 ) $ 28 $ (109 ) $ — $ (106 ) Depreciation, Depletion and Amortization 385 31 1 — 417 Provision (Benefit) for Income Taxes 95 9 (31 ) — 73 Capital Expenditures 354 37 — — 391 For the Three Months Ended March 31, 2017 Sales and Other Operating Revenues - Third-parties $ 1,256 $ 2 $ — $ — $ 1,258 Intersegment Revenues — 147 — (147 ) — Sales and Other Operating Revenues $ 1,256 $ 149 $ — $ (147 ) $ 1,258 Net Income (Loss) attributable to Hess Corporation $ (233 ) $ 18 $ (109 ) $ — $ (324 ) Depreciation, Depletion and Amortization 703 32 2 — 737 Provision (Benefit) for Income Taxes (20 ) 11 (4 ) — (13 ) Capital Expenditures 342 28 — — 370 Identifiable assets by operating segment were as follows: March 31, December 31, 2018 2017 (In millions) Exploration and Production $ 15,624 $ 15,613 Midstream 3,375 3,329 Corporate, Interest and Other 3,073 4,170 Total $ 22,072 $ 23,112

Financial Risk Management Act28

Financial Risk Management Activities (Tables)	3 Months Ended
	Mar. 31, 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 were as follows: March 31, 2018 December 31, 2017 Instrument type Puts Collars Effective date Apr. 1, 2018 Jan. 1, 2018 End date Dec. 31, 2018 Dec. 31, 2018 Crude oil volumes (millions of barrels) 31.6 42.0 Ceiling price N/A $ 65 Floor price $ 50 $ 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: March 31, 2018 December 31, 2017 (In millions) Foreign exchange $ 31 $ 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) March 31, 2018 Derivative Contracts Designated as Hedging Instruments Commodity - Accounts receivable $ 10 $ — Interest rate - Other liabilities and deferred credits (noncurrent) — (4 ) Total derivative contracts designated as hedging instruments 10 (4 ) Derivative Contracts Not Designated as Hedging Instruments Commodity - Accounts receivable 3 — Total derivative contracts not designated as hedging instruments 3 — Gross fair value of derivative contracts 13 (4 ) Net Fair Value of Derivative Contracts $ 13 $ (4 ) 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
	Mar. 31, 2018	Mar. 31, 2017
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		$ 2
Prior Period Adjustment [Abstract]
Sales and other operating revenues	$ 1,346	1,258
Marketing, including purchased oil and gas	358	200
Restatement Adjustment
Prior Period Adjustment [Abstract]
Sales and other operating revenues		(19)
Marketing, including purchased oil and gas		(19)
Scenario Previously Reported
Prior Period Adjustment [Abstract]
Sales and other operating revenues		1,277
Marketing, including purchased oil and gas		$ 219
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
	Mar. 31, 2018	Mar. 31, 2017
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	$ 1,380
Other operating revenue, includes gains (losses) on commodity derivatives	(34)
Total sales and other operating revenues	1,346	$ 1,258
Exploration and Production
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	1,380
Other operating revenue, includes gains (losses) on commodity derivatives	(34)
Total sales and other operating revenues	1,346
Exploration and Production | United States
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	1,028
Other operating revenue, includes gains (losses) on commodity derivatives	(34)
Total sales and other operating revenues	994
Exploration and Production | Europe
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	36
Total sales and other operating revenues	36
Exploration and Production | Africa
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	131
Total sales and other operating revenues	131
Exploration and Production | Asia
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	185
Total sales and other operating revenues	185
Midstream
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	167
Total sales and other operating revenues	167
Midstream | Intercompany Revenue
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	167
Crude Oil Revenue
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	768
Crude Oil Revenue | Exploration and Production
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	768
Crude Oil Revenue | Exploration and Production | United States
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	593
Crude Oil Revenue | Exploration and Production | Europe
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	33
Crude Oil Revenue | Exploration and Production | Africa
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	99
Crude Oil Revenue | Exploration and Production | Asia
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	43
Natural Gas Liquids Revenue
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	71
Natural Gas Liquids Revenue | Exploration and Production
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	71
Natural Gas Liquids Revenue | Exploration and Production | United States
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	71
Natural Gas Revenue
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	178
Natural Gas Revenue | Exploration and Production
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	178
Natural Gas Revenue | Exploration and Production | United States
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	39
Natural Gas Revenue | Exploration and Production | Europe
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	3
Natural Gas Revenue | Exploration and Production | Africa
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	8
Natural Gas Revenue | Exploration and Production | Asia
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	128
Revenue from Sale of Third Party Purchased Volumes
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	363
Revenue from Sale of Third Party Purchased Volumes | Exploration and Production
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	363
Revenue from Sale of Third Party Purchased Volumes | Exploration and Production | United States
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	325
Revenue from Sale of Third Party Purchased Volumes | Exploration and Production | Africa
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	24
Revenue from Sale of Third Party Purchased Volumes | Exploration and Production | Asia
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	14
Eliminations
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	(167)
Total sales and other operating revenues	(167)	$ (147)
Eliminations | Intercompany Revenue
Disaggregation Of Revenue [Line Items]
Total revenues from contracts with customers	$ (167)

Revenue - Additional Informatio

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

Debt - Additional Information (

Debt - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Debt Instrument Redemption [Line Items]
Current maturities of long-term debt	$ 196		$ 580
Redeemed and repurchased debt	terminated interest rate swaps with a notional amount of $350 million.
Loss on debt extinguishment	$ 27	$ 0
Loss on debt extinguishment, after income tax	27
8.125% Notes Due 2019
Debt Instrument Redemption [Line Items]
Debt instrument redemption amount	415
Debt instrument redemption of principal amount	$ 350
Debt instrument interest rate	8.125%
Debt instrument maturity year	2,019
Current maturities of long-term debt			349
Other Notes
Debt Instrument Redemption [Line Items]
Current maturities of long-term debt			$ 38

Inventories - Inventories (Deta

Inventories - Inventories (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Inventory Disclosure [Abstract]
Crude oil and natural gas liquids	$ 64	$ 59
Materials and supplies	175	173
Total Inventories	$ 239	$ 232

Capitalized Exploratory Well 34

Capitalized Exploratory Well Costs - Net Changes in Capitalized Exploratory Well Costs (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Capitalized Exploratory Well Costs [Abstract]
Beginning balance	$ 304
Additions to capitalized exploratory well costs pending the determination of proved reserves	42
Ending balance	$ 346

Capitalized Exploratory Well 35

Capitalized Exploratory Well Costs - Additional Information (Detail) $ in Millions	Mar. 31, 2018USD ($)
Capitalized Exploratory Well Costs [Line Items]
Capitalized exploratory well costs that have been capitalized for period greater than one year	$ 211
Northern Portion of Shenzi Field, Gulf of Mexico
Capitalized Exploratory Well Costs [Line Items]
Capitalized well costs percentage	55.00%
Project interest percentage	28.00%
Payara-1 Well on the Stabroek Block, Offshore Guyana
Capitalized Exploratory Well Costs [Line Items]
Capitalized well costs percentage	20.00%
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%

Hess Infrastructure Partners 36

Hess Infrastructure Partners LP - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 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	$ 3,726	$ 4,847	$ 2,686	$ 2,732
Property, plant and equipment, net	16,181	16,192
Hess Infrastructure Partners LP (HIP)
Variable Interest Entity [Line Items]
Cash and cash equivalents	375	356
Property, plant and equipment, net	2,527	2,520
HIP's liabilities on a nonrecourse to Hess Corporation	$ 1,060	$ 1,065

Severance Costs - Additional In

Severance Costs - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Restructuring And Related Activities [Abstract]
Severance expense	$ 46
Reduction to expense for stock-based compensation forfeitures	9
Severance cost paid	21
Accrued severance cost	$ 31	$ 6
Expected period for payment for severance cost	We expect to pay in 2018.

Retirement Plans - Components o

Retirement Plans - Components of Net Periodic Pension Cost (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Compensation And Retirement Disclosure [Abstract]
Service cost	$ 14	$ 14
Interest cost	23	26
Expected return on plan assets	(49)	(41)
Amortization of unrecognized net actuarial losses	12	17
Curtailment gains	(2)	0
Pension (benefit) expense	$ (2)	$ 16

Retirement Plans - Additional I

Retirement Plans - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Curtailment gains included in Accumulated other comprehensive income (loss)	$ 18
Curtailment gain	2	$ 0
Total service costs	14	14
Total interest costs	23	26
Total amortization of unrecognized net actuarial losses	(12)	(17)
Total expected return on plan assets	49	41
Net non-service pension (income) costs included in Other, net	(16)	$ 2
Corporation's estimated contribution for funded pension plans during the current year	44
Corporation's contribution for funded pension plan during the year to date	14
U.S. Retirement Plans
Defined Benefit Plan Disclosure [Line Items]
Total decrease in pension liabilities	$ (125)
Scenario, Forecast
Defined Benefit Plan Disclosure [Line Items]
Total service costs			$ 45
Total interest costs			95
Total amortization of unrecognized net actuarial losses			40
Total expected return on plan assets			$ 195

Weighted Average Common Share40

Weighted Average Common Shares - Basic and Diluted Earnings Per Share (Detail) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Net income (loss) attributable to Hess Corporation Common Stockholders:
Net Income (Loss)	$ (65)	$ (296)
Less: Net income (loss) attributable to noncontrolling interests	41	28
Less: Preferred stock dividends	11	12
Net Income (Loss) Attributable to Hess Corporation Common Stockholders	$ (117)	$ (336)
Weighted average common shares outstanding:
Shares outstanding – Basic	309.5	313.9
Diluted	309.5	313.9
Restricted Common Stock
Weighted average common shares outstanding:
Effect of dilutive securities	0	0
Stock Options
Weighted average common shares outstanding:
Effect of dilutive securities	0	0
Performance Share Units
Weighted average common shares outstanding:
Effect of dilutive securities	0	0
Mandatory convertible preferred stock
Weighted average common shares outstanding:
Effect of dilutive securities	0	0

Weighted Average Common Share41

Weighted Average Common Shares - Antidilutive Shares Excluded from Computation of Diluted Shares (Detail) - shares	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Restricted Common Stock
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Antidilutive shares excluded from computation of diluted shares	2,922,316	3,126,222
Stock Options
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Antidilutive shares excluded from computation of diluted shares	5,807,579	6,298,896
Performance Share Units
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items]
Antidilutive shares excluded from computation of diluted shares	623,088	313,004
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	12,584,974	12,547,650

Weighted Average Common Share42

Weighted Average Common Shares - Additional Information (Detail) - shares	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Equity [Abstract]
Shares granted, restricted stock	1,081,923	1,206,732
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 ($)	Mar. 31, 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)	3 Months Ended
	Mar. 31, 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
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Segment Reporting Information [Line Items]
Sales and Other Operating Revenues - Third-parties	$ 1,346	$ 1,258
Intersegment Revenues	0	0
Total sales and other operating revenues	1,346	1,258
Net Income (Loss) attributable to Hess Corporation	(106)	(324)
Depreciation, Depletion and Amortization	417	737
Provision (Benefit) for Income Taxes	73	(13)
Capital Expenditures	391	370
Identifiable assets	22,072		$ 23,112
Exploration and Production
Segment Reporting Information [Line Items]
Total sales and other operating revenues	1,346
Identifiable assets	15,624		15,613
Midstream
Segment Reporting Information [Line Items]
Total sales and other operating revenues	167
Identifiable assets	3,375		3,329
Corporate, Interest and Other
Segment Reporting Information [Line Items]
Identifiable assets	3,073		$ 4,170
Operating Segments | Exploration and Production
Segment Reporting Information [Line Items]
Sales and Other Operating Revenues - Third-parties	1,346	1,256
Intersegment Revenues	0	0
Total sales and other operating revenues	1,346	1,256
Net Income (Loss) attributable to Hess Corporation	(25)	(233)
Depreciation, Depletion and Amortization	385	703
Provision (Benefit) for Income Taxes	95	(20)
Capital Expenditures	354	342
Operating Segments | Midstream
Segment Reporting Information [Line Items]
Sales and Other Operating Revenues - Third-parties	0	2
Intersegment Revenues	167	147
Total sales and other operating revenues	167	149
Net Income (Loss) attributable to Hess Corporation	28	18
Depreciation, Depletion and Amortization	31	32
Provision (Benefit) for Income Taxes	9	11
Capital Expenditures	37	28
Operating Segments | Corporate, Interest and Other
Segment Reporting Information [Line Items]
Sales and Other Operating Revenues - Third-parties	0	0
Intersegment Revenues	0	0
Total sales and other operating revenues	0	0
Net Income (Loss) attributable to Hess Corporation	(109)	(109)
Depreciation, Depletion and Amortization	1	2
Provision (Benefit) for Income Taxes	(31)	(4)
Capital Expenditures	0	0
Eliminations
Segment Reporting Information [Line Items]
Sales and Other Operating Revenues - Third-parties	0	0
Intersegment Revenues	(167)	(147)
Total sales and other operating revenues	(167)	(147)
Net Income (Loss) attributable to Hess Corporation	0	0
Depreciation, Depletion and Amortization	0	0
Provision (Benefit) for Income Taxes	0	0
Capital Expenditures	$ 0	$ 0

Financial Risk Management Act46

Financial Risk Management Activities - Gross Notional Amounts of Outstanding Financial Risk Management Derivative Contracts (Detail) - WTI	3 Months Ended	12 Months Ended
	Mar. 31, 2018MMBbls$ / bbl	Dec. 31, 2017MMBbls$ / bbl
Derivative [Line Items]
Instrument type	Puts	Collars
Effective date	Apr. 1, 2018	Jan. 1, 2018
End date	Dec. 31, 2018	Dec. 31, 2018
Crude oil volumes (millions of barrels) | MMBbls	31.6	42
Ceiling price	0	65
Floor price	50	50

Financial Risk Management Act47

Financial Risk Management Activities - Additional Information (Detail)	3 Months Ended		12 Months Ended
	Mar. 31, 2018USD ($)bbl / d$ / bbl	Mar. 31, 2017USD ($)	Dec. 31, 2017USD ($)bbl / d$ / bbl
West Texas Intermediate Crude Oil Price Collars
Derivative Instruments Gain Loss [Line Items]
Average monthly floor price | $ / bbl	50		50
Average monthly ceiling price | $ / bbl	0		65
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	$ (30,000,000)	$ (1,000,000)
Other operating revenue, losses associated with changes in time value of crude oil collars	(120,000,000)	0
Crude Oil | Derivative Contracts Not Designated as Hedging Instruments
Derivative Instruments Gain Loss [Line Items]
Crude oil price hedging contracts increased (decreased) Sales and other operating revenues by this amount, pre-tax	(8,000,000)
After-tax deferred gain (losses) related to de-designation in Accumulated other comprehensive income (loss) to be reclassified into earnings	$ (11,000,000)
2018 | West Texas Intermediate Crude Oil Price Collars
Derivative Instruments Gain Loss [Line Items]
Notional amount of outstanding average barrels of oil per day | bbl / d	115,000		115,000
2018 | West Texas Intermediate Crude Oil Price Collars | Designated as Cash Flow Hedges
Derivative Instruments Gain Loss [Line Items]
Average monthly floor price | $ / bbl	50		50
Average monthly ceiling price | $ / bbl	0		65
Interest Rate Swaps
Derivative Instruments Gain Loss [Line Items]
Outstanding gross notional amount	$ 100,000,000		$ 450,000,000
Unrealized change in fair value of interest rate swaps - increase in derivative liability	3,000,000	1,000,000
Foreign Exchange
Derivative Instruments Gain Loss [Line Items]
Outstanding gross notional amount	31,000,000		$ 52,000,000
Foreign Exchange | Derivative Contracts Not Designated as Hedging Instruments
Derivative Instruments Gain Loss [Line Items]
Foreign exchange gains (losses) reported in Other, net	4,000,000	(1,000,000)
Foreign exchange gains (losses) from foreign exchange derivative contracts that are not designated as hedges	$ 2,000,000	$ (1,000,000)

Financial Risk Management Act48

Financial Risk Management Activities - Gross Notional Amounts of Derivative Contracts Outstanding Excluding Commodity Contracts (Detail) - USD ($)	Mar. 31, 2018	Dec. 31, 2017
Foreign Exchange
Derivative [Line Items]
Outstanding gross notional amount	$ 31,000,000	$ 52,000,000
Interest Rate Swaps
Derivative [Line Items]
Outstanding gross notional amount	$ 100,000,000	$ 450,000,000

Financial Risk Management Act49

Financial Risk Management Activities - Gross and Net Fair Values (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Derivatives Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	$ 13	$ 1
Assets - Net Fair Value of Derivative Contracts	13	1
Liabilities - Gross fair value of derivative contracts	(4)	(13)
Liabilities - Net Fair Value of Derivative Contracts	(4)	(13)
Derivative Contracts Designated as Hedging Instruments
Derivatives Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	10
Liabilities - Gross fair value of derivative contracts	(4)	(11)
Derivative Contracts Designated as Hedging Instruments | Commodity | Accounts Receivable
Derivatives Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	10
Derivative Contracts Designated as Hedging Instruments | Commodity | Accounts Payable
Derivatives Fair Value [Line Items]
Liabilities - Gross fair value of derivative contracts		(7)
Derivative Contracts Designated as Hedging Instruments | Interest Rate | Other Liabilities and Deferred Credits
Derivatives Fair Value [Line Items]
Liabilities - Gross fair value of derivative contracts	(4)
Derivative Contracts Designated as Hedging Instruments | Interest Rate | Accounts Payable
Derivatives Fair Value [Line Items]
Liabilities - Gross fair value of derivative contracts		(4)
Derivative Contracts Not Designated as Hedging Instruments
Derivatives Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	3	1
Liabilities - Gross fair value of derivative contracts		(2)
Derivative Contracts Not Designated as Hedging Instruments | Commodity | Accounts Receivable
Derivatives Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	$ 3
Derivative Contracts Not Designated as Hedging Instruments | Commodity | Accounts Payable
Derivatives Fair Value [Line Items]
Liabilities - Gross fair value of derivative contracts		(2)
Derivative Contracts Not Designated as Hedging Instruments | Foreign Exchange
Derivatives Fair Value [Line Items]
Assets - Gross fair value of derivative contracts		$ 1

Financial Risk Management Act50

Financial Risk Management Activities - Fair Value Measurements - Additional Information (Detail) $ in Millions	Mar. 31, 2018USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total long-term debt, carrying value	$ 6,568
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total long-term debt, fair value	$ 7,058

Subsequent Event - Additional I

Subsequent Event - Additional Information (Details) - USD ($) $ in Millions	Apr. 30, 2018	Mar. 31, 2018
Subsequent Event [Line Items]
Share repurchase program, amount		$ 1,500
Subsequent Event
Subsequent Event [Line Items]
Accelerated stock repurchase program of common stock	$ 500
Accelerated share repurchases, cash paid	500
Accelerated share repurchases, received of common stock	$ 8
Accelerated share repurchase program, terms	We paid $500 million in cash to the financial institution and received an initial delivery of approximately 8 million shares of our common stock with final settlement expected to be completed during the second quarter.