10-Q

.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarter ended September 30, 2018

or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-1204

HESS CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

DELAWARE

(State or Other Jurisdiction of Incorporation or Organization)

13-4921002

(I.R.S. Employer Identification Number)

1185 AVENUE OF THE AMERICAS, NEW YORK, N.Y.

(Address of Principal Executive Offices)

10036

(Zip Code)

(Registrant’s Telephone Number, Including Area Code is (212) 997-8500)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

At September 30, 2018, there were 296,253,136 shares of Common Stock outstanding.

HESS CORPORATION

Form 10-Q

TABLE OF CONTENTS

Item No.		Page Number
	PART I - FINANCIAL INFORMATION
1.	Financial Statements (Unaudited)
	Consolidated Balance Sheet at September 30, 2018, and December 31, 2017	2
	Statement of Consolidated Income for the Three and Nine Months Ended September 30, 2018, and 2017	3
	Statement of Consolidated Comprehensive Income for the Three and Nine Months Ended September 30, 2018, and 2017	4
	Statement of Consolidated Cash Flows for the Nine Months Ended September 30, 2018, and 2017	5
	Statement of Consolidated Equity for the Nine Months Ended September 30, 2018, and 2017	6
	Notes to Consolidated Financial Statements (Unaudited)	7
	Note 1 - Basis of Presentation	7
	Note 2 - Revenue	9
	Note 3 - Common Stock Repurchase Program	11
	Note 4 - Debt	11
	Note 5 - Inventories	11
	Note 6 - Capitalized Exploratory Well Costs	12
	Note 7 - Hess Infrastructure Partners LP	12
	Note 8 - Exit and Disposal Costs	12
	Note 9 - Dispositions	13
	Note 10 - Impairment	13
	Note 11 - Retirement Plans	13
	Note 12 - Weighted Average Common Shares	14
	Note 13 - Guarantees and Contingencies	14
	Note 14 - Segment Information	16
	Note 15 - Financial Risk Management Activities	17
	Note 16 - Subsequent Events	19
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
3.	Quantitative and Qualitative Disclosures about Market Risk	35
4.	Controls and Procedures	35
	PART II - OTHER INFORMATION
1.	Legal Proceedings	36
2.	Share Repurchase Activities	36
6.	Exhibits	37
	Signatures	38
	Certifications

Unless the context indicates otherwise, references to “Hess”, the “Corporation”, “Registrant”, “we”, “us”, “our” and “its” refer to the consolidated business operations of Hess Corporation and its subsidiaries.

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEET (UNAUDITED)

	September 30,			December 31,
	2018			2017
	(In millions,
	except share amounts)
Assets
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
Liabilities
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
Equity
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

See accompanying Notes to Consolidated Financial Statements.

2

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED INCOME (UNAUDITED)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
	(In millions, except per share amounts)
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		—			—			53			—
Depreciation, depletion and amortization		489			759			1,350			2,237
Impairment		—			2,503			—			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

See accompanying Notes to Consolidated Financial Statements.

3

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
	(In millions)
Net Income (Loss)	$	3		$	(593	)	$	(149	)	$	(1,306	)
Other Comprehensive Income (Loss):
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		—			—			—			—
Net effect of hedge (gains) losses reclassified to income		49			(18	)		129			(38	)
Change in fair value of cash flow hedges		(49	)		(76	)		(84	)		—
Income taxes on change in fair value of cash flow hedges		12			—			12			—
Net change in fair value of cash flow hedges		(37	)		(76	)		(72	)		—
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		—			—			130			5
Income taxes on actuarial changes in plan liabilities		—			2			(31	)		—
(Increase) reduction in unrecognized actuarial losses, net		—			2			99			5
Amortization of net actuarial losses		8			17			29			57
Income taxes on amortization of net actuarial losses		—			—			—			—
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		—			121			—			208
Change in foreign currency translation adjustment		—			121			—			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	)

See accompanying Notes to Consolidated Financial Statements.

4

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS (UNAUDITED)

	Nine Months Ended September 30,
	2018			2017
	(In millions)
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		—			2,503
Exploratory dry hole costs		132			—
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			—
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	)		—
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		—			15
Debt with maturities of greater than 90 days
Borrowings		—			—
Repayments		(610	)		(107	)
Proceeds from issuance of Hess Midstream Partnership LP units		—			366
Common stock acquired and retired		(1,120	)		—
Cash dividends paid		(262	)		(273	)
Noncontrolling interests, net		(36	)		(208	)
Other, net		28			—
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

See accompanying Notes to Consolidated Financial Statements.

5

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED EQUITY (UNAUDITED)

	Mandatory Convertible Preferred Stock		Common Stock			Capital in Excess of Par			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Hess Stockholders' Equity			Noncontrolling Interests			Total Equity
	(In millions)
Balance at January 1, 2018	$	1	$	315		$	5,824		$	5,597		$	(686	)	$	11,051		$	1,303		$	12,354
Cumulative effect of adoption of new accounting standards		—		—			—			1			(1	)		—			—			—
Net income (loss)		—		—			—			(278	)		—			(278	)		129			(149	)
Other comprehensive income		—		—			—			—			185			185			—			185
Share-based compensation, including income taxes		—		1			83			—			—			84			—			84
Dividends on preferred stock		—		—			—			(34	)		—			(34	)		—			(34	)
Dividends on common stock		—		—			—			(228	)		—			(228	)		—			(228	)
Common stock acquired and retired		—		(20	)		(462	)		(648	)		—			(1,130	)		—			(1,130	)
Noncontrolling interests, net		—		—			—			—			—			—			(36	)		(36	)
Balance at September 30, 2018	$	1	$	296		$	5,445		$	4,410		$	(502	)	$	9,650		$	1,396		$	11,046
Balance at January 1, 2017	$	1	$	317		$	5,773		$	10,147		$	(1,704	)	$	14,534		$	1,057		$	15,591
Cumulative effect of adoption of new accounting standards		—		—			2			(39	)		—			(37	)		—			(37	)
Net income (loss)		—		—			—			(1,397	)		—			(1,397	)		91			(1,306	)
Other comprehensive income		—		—			—			—			232			232			—			232
Share-based compensation, including income taxes		—		1			72			—			—			73			—			73
Dividends on preferred stock		—		—			—			(34	)		—			(34	)		—			(34	)
Dividends on common stock		—		—			—			(239	)		—			(239	)		—			(239	)
Hess Midstream Partners LP units issuance		—		—			—			—			—			—			356			356
Noncontrolling interests, net		—		—			—			—			—			—			(208	)		(208	)
Balance at September 30, 2017	$	1	$	318		$	5,847		$	8,438		$	(1,472	)	$	13,132		$	1,296		$	14,428

See accompanying Notes to Consolidated Financial Statements.

6

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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, using the modified retrospective method.  The adoption of this standard did not affect the timing of revenue recognition for our uncompleted contracts at January 1, 2018, and as a result, no cumulative effect adjustment to Retained earnings was recognized.  Accounts receivables from contracts with customers is presented separately in the Consolidated Balance Sheet with the prior year balance recast to conform to the current period presentation.  In addition, as the adoption of ASC 606 did not affect previous conclusions regarding our involvement as a principal versus agent in contracts with customers, there were no changes in presentation to the Statement of Consolidated Income.

In the first quarter of 2018, we adopted Accounting Standards Update (ASU) 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.  This ASU prohibits the capitalization of the non-service cost components of net periodic benefit cost in connection with the production or construction of an asset.  This provision was applied prospectively effective January 1, 2018.  The provision requiring that non-service cost components of net periodic benefit cost to be presented separately from the service cost component in the Statement of Consolidated Income was applied retrospectively.  We elected the practical expedient allowing the use of the amounts previously disclosed in the notes to our consolidated financial statements as the basis for applying this provision retrospectively as the capitalization of the non-service cost components of net periodic benefit cost was not material during the comparative periods.  This resulted in a reclassification of $- million and $9 million of expense from Operating costs and expenses, and General and administrative expenses to Other, net for the three months ended and nine months ended September 30, 2017, respectively.

In the first quarter of 2018, we adopted ASU 2017-12, Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities.  This ASU makes certain targeted improvements to simplify the application of the existing hedge accounting guidance.  The adoption of this ASU resulted in an increase to Retained earnings and a decrease in Accumulated other comprehensive income (loss) of $1 million to remove the cumulative effect of hedging ineffectiveness previously recognized in earnings for contracts designated as hedging instruments that were outstanding at January 1, 2018.  

In the first quarter of 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230):  Restricted Cash (a consensus of the FASB Emerging Issues Task Force).  This ASU requires that the total change in cash and cash equivalents and restricted cash be reflected on the statement of cash flows.  A reconciliation to the balance sheet is also required when cash and cash equivalents and restricted cash are not separately presented on the balance sheet or are presented in more than one financial statement line item on the balance sheet.  The adoption of this ASU did not have a material impact on our Statement of Consolidated Cash Flows.

In the first quarter of 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230):  Classification of Certain Cash Receipts and Cash Payments (a consensus of the FASB Emerging Issues Task Force).  This ASU is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows.  The guidance addresses eight specific classification issues for which current guidance is either unclear or is non-specific.  The requirement that fees paid to third-parties and premiums incurred in connection with the repayment of debt be classified as financing cash outflows is among the classification issues addressed by this ASU.  The adoption of this ASU did not have a material impact on our Statement of Consolidated Cash Flows.

7

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

To conform with the Statement of Consolidated Income presentation in our December 31, 2017 Form 10-K, we have revised the presentation of Sales and other operating revenues and Marketing, including purchased oil and gas for the three months and nine months ended September 30, 2017 associated with the recovery of certain natural gas processing costs from third-parties, by reducing each by $22 million and $60 million, respectively.  This revision did not impact net income, our Consolidated Balance Sheet, Statement of Consolidated Comprehensive Income, Statement of Consolidated Cash Flows, nor Statement of Consolidated Equity.  Amounts reported as Sales and other operating revenues and Marketing, including purchased oil and gas (formerly Costs of products sold) in our September 30, 2017 Form 10-Q were $1,370 million and $360 million, respectively, for the third quarter of 2017 and $3,863 million and $851 million, respectively, for the nine months ended September 30, 2017.

New Accounting Pronouncements:  In February 2016, the FASB issued ASU 2016-02, Leases, as a new Accounting Standards Codification (ASC) Topic, ASC 842.  The new standard 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.  This ASU makes changes to the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments.  The standard requires the use of a forward-looking "expected loss" model compared to the current "incurred loss" model.  This ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted beginning in the first quarter of 2019.  We are currently assessing the impact of the ASU on our consolidated financial statements.

In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment.  This ASU modifies the concept of goodwill impairment from a condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of the reporting unit exceeds its fair value.  Thus, an entity should recognize an impairment charge for the amount by which the carrying amount of a reporting unit exceeds its fair value.  The impairment charge would be limited by the amount of goodwill allocated to the reporting unit.  This ASU removes the requirement to determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if the reporting unit had been acquired in a business combination.  This ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted.  We are currently assessing the impact of the ASU on our consolidated financial statements.

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.  This ASU allows the reclassification of stranded income tax effects within Accumulated other comprehensive income (loss) to Retained earnings that resulted from the enactment of U.S. Federal income tax reform, commonly referred to as the U.S. Tax Cuts and Jobs Act (“Act”).  Specifically, this ASU provides entities the option to reclassify the stranded income tax effects resulting from the reduction to the corporate income tax rate from the Act upon adoption of this ASU, instead of upon liquidation of the individual items (or of the underlying portfolio of items) within Accumulated other comprehensive income (loss).  This ASU is effective for us beginning in the first quarter of 2019, with early adoption permitted.  We are currently assessing the impact of the ASU on our consolidated financial statements.

8

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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 within Sales and other operating revenues and Marketing, including purchased oil and gas, respectively.  Where control of crude oil,

9

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NGLs, or natural gas is not transferred to Hess, revenue is presented net of the associated cost of purchased volumes within Sales and other operating revenues in the Statement of Consolidated Income.

Contract types

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

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

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

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

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

Contract Balances

Our right to receive or collect payment from the customer is aligned with the timing of revenue recognition except in situations when we receive shortfall payments under contracts with take-or-pay provisions with customer make-up rights.  Shortfall payments received from customers under contracts with take-or-pay provisions with customer make-up rights are deferred upon receipt and reflected as a contract liability.  At 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 the exemption from disclosure of revenue recognizable in future periods as these performance obligations are satisfied.

Sales-based Taxes

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

10

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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 to recognize revenue in the amount it is entitled to invoice.  If the commercial agreements have take-or-pay provisions, the Midstream segment’s responsibility to stand-ready to service a minimum volume over each quarterly commitment period represent separate, distinct performance obligations.  Shortfall payments received under take-or-pay provisions are recognized as revenue in the calendar quarter the shortfall occurs as the customer does not have make-up rights beyond the calendar quarter end of the quarterly commitment period.  All revenues, receivables, and contract balances arising from the commercial agreements between the Midstream segment and the Hess marketing subsidiary that is the counterparty to the commercial agreements are eliminated upon consolidation.

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.  

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.

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

11

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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.

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).

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 in connection with vacated office space.

12

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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.

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.

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 following workforce reductions.  In connection with this curtailment, as required under accounting standards, we remeasured our U.S. retirement plans and recorded a total decrease of $125 million in the Corporation’s U.S. post retirement liabilities.  This reduction was primarily driven by a change in weighted average discount rates used to measure the liabilities.  There was no change to the weighted average expected long-term rate of return on plan assets.

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

Net non-service pension costs included in Other, net in the Statement of Consolidated Income for the three and nine months ended September 30, 2018 was income of $17 million and $49 million, respectively, compared to expenses of $0 million and $9 million for the three and nine months ended September 30, 2017, respectively.

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.

13

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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).

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

14

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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.

15

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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

16

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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

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, we purchased WTI put options with a notional amount of 90,000 bopd with a WTI monthly floor price of $60 per barrel for calendar year 2019.

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

	September 30, 2018		December 31, 2017
	(In millions)
Foreign exchange	$	9	$	52
Interest rate swaps	$	100	$	450

17

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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.  In 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 Accumulated other comprehensive income (loss) 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 Interest expense in the Statement of Consolidated Income.  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.

18

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Derivative contracts not designated as hedging instruments:

Crude oil collars:For the three and nine months ended September 30, 2018, noncash adjustments to crude oil price hedging contracts, which were de-designated as cash flow hedges in the fourth quarter of 2017, decreased Sales and other operating revenues by $4 million and $20 million, respectively.  At September 30, 2018, after-tax deferred losses in Accumulated other comprehensive income (loss) 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 Other, net in Revenues and non-operating income in the Statement of Consolidated Income 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.

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.

19

PART I - FINANCIAL INFORMATION (CONT’D.)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Overview

Hess Corporation is a global Exploration and Production (E&P) company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located primarily in the United States (U.S.), Denmark, the Malaysia/Thailand Joint Development Area (JDA) and Malaysia.  We conduct exploration activities primarily offshore Guyana, Suriname, Canada and in the Gulf of Mexico, including at the Stabroek Block, offshore Guyana, where we have participated in nine significant crude oil discoveries and sanctioned the first phase of a multi-phase development project at the Liza Field.

In the third quarter of 2018, we completed the sale of our joint venture interests in the Utica shale play in eastern Ohio for net cash consideration of $396 million, after closing adjustments.  This sale is consistent with our strategy to high grade and focus our portfolio by divesting lower return noncore assets to invest in higher return assets, primarily in Guyana and the Bakken.

Our Midstream operating segment provides fee-based services, including gathering, compressing and processing natural gas and fractionating natural gas liquids (NGLs); gathering, terminaling, loading and transporting crude oil and NGLs; and storing and terminaling propane, primarily in the Bakken and Three Forks Shale plays in the Williston Basin area of North Dakota.

Third Quarter Highlights and Outlook

Net cash provided by operating activities was $1,058 million in the first nine months of 2018, compared to $602 million in the first nine months of 2017, which includes uses of working capital of $483 million and $631 million, respectively.  Capital expenditures were $1,544 million in the first nine months of 2018 and $1,426 million in the first nine months of 2017.  In the third quarter of 2018, we repurchased $250 million of common stock, bringing total share repurchases under the Corporation’s $1.5 billion share repurchase program to $1.25 billion (23.0 million shares).  Excluding our Midstream segment, we ended the third quarter of 2018 with approximately $2.6 billion in cash and cash equivalents.  

Based on current forward strip crude oil prices for 2019, we expect cash flow from operating activities and cash and cash equivalents existing at September 30, 2018 will be sufficient to fund our capital investment program and dividends through the end of 2019, and the repurchase of $250 million of common stock remaining under our $1.5 billion stock repurchase program during the fourth quarter of 2018.

Third Quarter Results

In the third quarter of 2018, we recorded a net loss of $42 million, compared to a net loss of $624 million in the third quarter of 2017.  Excluding items affecting comparability of earnings between periods on pages 28 to 30, the adjusted net income for the third quarter of 2018 was $29 million, compared to an adjusted net loss of $324 million in the third quarter of 2017.  The improved adjusted third quarter 2018 results, compared to the prior year quarter, reflect higher realized crude oil selling prices combined with lower operating costs and depreciation, depletion and amortization expense, partially offset by lower production volumes due to asset sales and higher exploration expenses.

Exploration and Production Results

In the third quarter of 2018, E&P had net income of $50 million, compared with a net loss of $474 million in the third quarter of 2017.  Excluding items affecting comparability of earnings between periods, the adjusted net income for the third quarter of 2018 was $109 million, compared to an adjusted net loss of $238 million in 2017.  Total net production, excluding Libya, averaged 279,000 barrels of oil equivalent per day (boepd) in the third quarter of 2018, compared to 299,000 boepd in the third quarter of 2017.  Excluding assets sold in 2017 and Libya, third quarter 2017 net production was 249,000 boepd.  The average realized crude oil selling price, including hedging, was $66.08 per barrel, up from $46.97 in the third quarter of 2017.  The average realized natural gas liquids selling price in the third quarter of 2018 was $24.29 per barrel, up from $17.22 in the prior year quarter, while the average realized natural gas selling price was $4.11 per thousand cubic feet (mcf), up from $3.35 in the third quarter of 2017.  

We expect net production, excluding Libya, to average approximately 265,000 boepd in the fourth quarter of 2018, and to average approximately 255,000 boepd for full year 2018.  We project E&P capital and exploratory expenditures of $2.1 billion for full year 2018 and closer to $3.0 billion for 2019, with the incremental spend in 2019 directed to our Bakken and Guyana assets.

20

PART I - FINANCIAL INFORMATION (CONT’D.)

Overview (continued)

The following is an update of our ongoing E&P activities:

Producing E&P assets:

• In North Dakota, net production from the Bakken oil shale play averaged 118,000 boepd for the third quarter of 2018 (2017 Q3: 103,000 boepd), which reflects increased drilling activity, improved well performance, and the impact of severe weather in the prior year quarter.  In the third quarter of 2018, we operated an average of five rigs, drilled 34 wells, and brought 29 new wells on production.  The Corporation added a sixth rig and a third frac crew in the third quarter of this year.  For full year 2018, we expect to drill a total of 120 wells while bringing 100 new wells on production.  We are transitioning from our previous sliding sleeve completion design to a plug and perf completion design. Of the 100 wells to be brought online in 2018, approximately 30 wells are expected to use plug and perf completions.  For full year 2018, we forecast net production to be in the range of 115,000 boepd to 120,000 boepd.

• In the Gulf of Mexico, net production for the third quarter of 2018 averaged 71,000 boepd (2017 Q3: 59,000 boepd), reflecting higher production from the Penn State and Stampede fields.  Production from the Conger Field (Hess operated - 38%), which had been shut-in since the fourth quarter of 2017 due to the third-party operated Enchilada platform shutdown, resumed in mid-July.  In the fourth quarter, we forecast net production in the Gulf of Mexico to average approximately 65,000 boepd, which reflects 6,000 boepd of downtime, principally associated with a planned inspection of one of the risers at the Conger Field.

• At North Malay Basin (Hess operated - 50%), offshore Peninsular Malaysia, net production for the third quarter of 2018 averaged 31,000 boepd (2017 Q3: 14,000 boepd).  Production from full-field development commenced in July 2017.  In July 2018, we entered into a sale and lease-back arrangement for a floating, storage and offloading vessel (FSO) to handle produced condensate from the field and received net proceeds of approximately $130 million.  See Note 4, Debt, in the Notes to Consolidated Financial Statements.

Other E&P assets:

• At the Stabroek Block (Hess - 30%), offshore Guyana, the operator, Esso Exploration and Production Guyana Limited, announced a ninth discovery on the Block at the Hammerhead-1 exploration well, which encountered approximately 197 feet of high-quality, oil-bearing sandstone reservoir.  The well, located approximately 13 miles southwest of the Liza-1 well, targeted Miocene aged reservoir and proves a new play concept for potential development on the Block.  The Hammerhead discovery adds to the eight previous discoveries that have established the potential for up to five floating, production, storage and offloading (FPSO) vessels producing over 750,000 gross barrels of oil per day (bopd) by 2025.  

The Liza Phase 1 development, which is expected to begin producing oil by early 2020, will use the Liza Destiny FPSO to produce up to 120,000 gross bopd.  Construction of the FPSO and subsea equipment is well advanced.  Phase 2 of the Liza development will use a second FPSO designed to produce up to 220,000 gross bopd and is expected to be producing by mid-2022.  A third phase of development at the Payara Field is targeted to use an FPSO designed to produce approximately 180,000 gross bopd, with first production expected as early as 2023.

A second exploration vessel, the Noble Tom Madden drillship, has arrived in Guyana to accelerate exploration of high potential opportunities and will commence drilling at the Pluma prospect, which is located approximately 17 miles south of the Turbot discovery, in November.  The Stena Caron drillship will leave the Block for recertification and is expected to return to the Block in late December when we expect it will spud the Aimara prospect, which is located 24 miles southeast of the Turbot discovery.

• At the Block 42 contract area (Hess - 33%), offshore Suriname, the operator, Kosmos Energy Ltd., completed drilling operations on the Pontoenoe-1 exploration well in October.  A 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.  Well results will be integrated in the ongoing evaluation to inform future exploration on the Block.  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 Canada, offshore Nova Scotia (Hess - 50%), the operator, BP Canada, completed drilling of the Aspy exploration well in early November.  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.

21

PART I - FINANCIAL INFORMATION (CONT’D.)

Consolidated Results of Operations

The after-tax income (loss) by major operating activity is summarized below:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
	(In millions, except per share amounts)
Net Income (Loss) Attributable to Hess Corporation:
Exploration and Production	$	50		$	(474	)	$	56		$	(1,061	)
Midstream		30			(12	)		88			22
Corporate, Interest and Other		(122	)		(138	)		(422	)		(358	)
Total	$	(42	)	$	(624	)	$	(278	)	$	(1,397	)
Net Income (Loss) Attributable to Hess Corporation Per Common Share - Diluted (a)	$	(0.18	)	$	(2.02	)	$	(1.04	)	$	(4.55	)

(a) Calculated as net income (loss) attributable to Hess Corporation less preferred stock dividends, divided by weighted average number of diluted shares.

Items Affecting Comparability of Earnings Between Periods

The following table summarizes, on an after-tax basis, items of income (expense) that are included in net income (loss) and affect comparability of earnings between periods: 

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
	(In millions)
Exploration and Production	$	(59	)	$	(236	)	$	(86	)	$	(236	)
Midstream		—			(34	)		—			(34	)
Corporate, Interest and Other		(12	)		(30	)		(93	)		(30	)
Total Items Affecting Comparability of Earnings Between Periods, After-Tax	$	(71	)	$	(300	)	$	(179	)	$	(300	)

The items in the table above are explained on pages 28 to 30.

Reconciliations of GAAP and non-GAAP measures

The following table reconciles reported net income (loss) attributable to Hess Corporation and adjusted net income (loss) attributable to Hess Corporation:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
	(In millions)
Net income (loss) attributable to Hess Corporation	$	(42	)	$	(624	)	$	(278	)	$	(1,397	)
Less: Total items affecting comparability of earnings between periods, after-tax		(71	)		(300	)		(179	)		(300	)
Adjusted Net Income (Loss) Attributable to Hess Corporation	$	29		$	(324	)	$	(99	)	$	(1,097	)

Adjusted net income (loss) attributable to Hess Corporation presented in this report is a non-GAAP financial measure, which we define as reported net income (loss) attributable to Hess Corporation excluding items identified as affecting comparability of earnings between periods.  Management uses adjusted net income (loss) to evaluate the Corporation’s operating performance and believes that investors’ understanding of our performance is enhanced by disclosing this measure, which excludes certain items that management believes are not directly related to ongoing operations and are not indicative of future business trends and operations.  This measure is not, and should not be viewed as, a substitute for U.S. GAAP net income (loss).

In the following discussion and elsewhere in this report, the financial effects of certain transactions are disclosed on an after-tax basis.  Management reviews segment earnings on an after-tax basis and uses after-tax amounts in its review of variances in segment earnings.  Management believes that after-tax amounts are a preferable method of explaining variances in earnings, since they show the entire effect of a transaction rather than only the pre-tax amount.  After-tax amounts are determined by applying the income tax rate in each tax jurisdiction to pre-tax amounts. 

22

PART I - FINANCIAL INFORMATION (CONT’D.)

Consolidated Results of Operations (continued)

Comparison of Results

Exploration and Production

Following is a summarized income statement of our E&P operations:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2018		2017			2018		2017
	(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues	$	1,793	$	1,347		$	4,673	$	3,797
Gains on asset sales, net		14		330			27		330
Other, net		12		18			36		17
Total revenues and non-operating income		1,819		1,695			4,736		4,144
Costs and Expenses
Marketing, including purchased oil and gas		506		351			1,343		846
Operating costs and expenses		215		311			703		935
Production and severance taxes		47		27			128		88
Midstream tariffs		169		140			483		399
Exploration expenses, including dry holes and lease impairment		169		41			271		151
General and administrative expenses		106		56			203		166
Depreciation, depletion and amortization		457		709			1,249		2,120
Impairment		—		2,503			—		2,503
Total costs and expenses		1,669		4,138			4,380		7,208
Results of Operations Before Income Taxes		150		(2,443	)		356		(3,064	)
Provision (benefit) for income taxes		100		(1,969	)		300		(2,003	)
Net Income (Loss) Attributable to Hess Corporation	$	50	$	(474	)	$	56	$	(1,061	)

Excluding the E&P Items affecting comparability of earnings between periods detailed on page 28, the changes in E&P earnings are primarily attributable to changes in selling prices, production and sales volumes, marketing expenses, cash operating costs, Midstream tariffs, depreciation, depletion and amortization, exploration expenses and income taxes, as discussed below.

23

PART I - FINANCIAL INFORMATION (CONT’D.)

Consolidated Results of Operations (continued)

Selling Prices:  Higher realized selling prices in the third quarter and first nine months of 2018, improved after-tax results by approximately $290 million and $655 million, respectively, compared to the same periods in 2017.  Average selling prices were as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
Average Selling Prices (a)
Crude Oil - Per Barrel (Including Hedging)
United States
Onshore	$	62.92	$	42.14	$	59.54	$	44.20
Offshore		66.62		46.11		63.49		46.04
Total United States		64.38		43.66		60.90		44.88
Europe		74.71		53.89		72.37		52.68
Africa		73.34		51.62		71.14		50.51
Asia		73.67		—		70.68		52.83
Worldwide		66.08		46.97		62.89		47.16
Crude Oil - Per Barrel (Excluding Hedging)
United States
Onshore	$	66.76	$	42.85	$	63.38	$	44.38
Offshore		70.44		46.72		67.29		46.24
Total United States		68.22		44.33		64.72		45.06
Europe		74.71		53.77		72.37		52.49
Africa		73.34		51.51		71.14		50.36
Asia		73.67		—		70.68		52.83
Worldwide		69.22		47.36		65.98		47.22
Natural Gas Liquids - Per Barrel
United States
Onshore	$	22.99	$	16.56	$	21.27	$	16.22
Offshore		31.27		20.41		27.63		19.95
Total United States		24.29		17.04		22.01		16.67
Europe		—		26.44		—		26.26
Worldwide		24.29		17.22		22.01		16.89
Natural Gas - Per Mcf
United States
Onshore	$	1.99	$	1.58	$	2.14	$	2.04
Offshore		2.22		2.26		2.18		2.32
Total United States		2.09		1.80		2.15		2.12
Europe		3.55		4.58		3.50		4.24
Asia and other		5.22		4.34		4.96		4.12
Worldwide		4.11		3.35		4.00		3.25

(a) Selling prices in the United States are adjusted for certain processing and distribution fees included in Marketing expenses.  Excluding these fees Worldwide selling prices for the third quarter of 2018 would be $69.06 per barrel for crude oil (including hedging), $72.20 per barrel for crude oil (excluding hedging), $24.45 per barrel for natural gas liquids and $4.17 per mcf for natural gas.  Excluding these fees Worldwide selling prices for the first nine months of 2018 would be $65.93 per barrel for crude oil (including hedging), $69.02 per barrel for crude oil (excluding hedging), $22.21 per barrel for natural gas liquids and $4.07 per mcf for natural gas.

The decrease in Sales and other operating revenues from crude oil price derivatives was $49 million and $139 million in the third quarter and first nine months of 2018, respectively.  Realized and unrealized results from crude oil price derivatives amounted to an increase of $6 million and a decrease of $5 million in Sales and other operating revenues in the third quarter and first nine months of 2017, respectively.

24

PART I - FINANCIAL INFORMATION (CONT’D.)

Consolidated Results of Operations (continued)

At December 31, 2017, we had West Texas Intermediate (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 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, we purchased WTI put options with a notional amount of 90,000 bopd with a WTI monthly floor price of $60 per barrel for calendar year 2019.  In October we purchased additional WTI put options with a notional amount of 5,000 bopd and an average floor price of $60 per barrel for calendar year 2019.

Production Volumes:  Our daily worldwide net production was as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
	(In thousands)
Crude Oil - Barrels
United States
Bakken		76			63			73			66
Other Onshore (b)		2			4			1			7
Total Onshore		78			67			74			73
Offshore		50			43			39			43
Total United States		128			110			113			116
Europe (c)		7			25			6			28
Africa (d) (e)		16			39			18			35
Asia		4			2			4			2
Worldwide		155			176			141			181
Natural Gas Liquids - Barrels
United States
Bakken		30			29			29			27
Other Onshore (b)		4			8			5			9
Total Onshore		34			37			34			36
Offshore		6			5			5			4
Total United States		40			42			39			40
Europe (c)		—			1			—			1
Worldwide		40			43			39			41
Natural Gas - Mcf
United States
Bakken		72			63			69			61
Other Onshore (b)		47			85			58			97
Total Onshore		119			148			127			158
Offshore		89			69			59			65
Total United States		208			217			186			223
Europe (c)		8			29			8			33
Asia and other (e)		395			306			363			252
Worldwide		611			552			557			508
Barrels of Oil Equivalent (a)		297			311			273			307
Crude oil and natural gas liquids as a share of total production		66	%		70	%		66	%		72	%

(a) Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel).  Barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past.  In addition, natural gas liquids do not sell at prices equivalent to crude oil.  See the average selling prices in the table on page 24.

(b) We sold our Permian assets in August 2017.  Net production averaged 3,000 boepd in the third quarter of 2017 and 6,000 boepd in the first nine months of 2017.  In addition, we sold our Utica assets in August 2018.  Net production averaged 10,000 boepd and 12,000 boepd in the third quarter and first nine months of 2018, respectively, and 17,000 boepd and 20,000 boepd in the third quarter and first nine months of 2017, respectively.

25

PART I - FINANCIAL INFORMATION (CONT’D.)

Consolidated Results of Operations (continued)

(c) We sold our Norway assets in December 2017.  Net production averaged 20,000 boepd in the third quarter of 2017 and 24,000 boepd in the first nine months of 2017.

(d) We sold our Equatorial Guinea assets in November 2017. Net production averaged 27,000 boepd in the third quarter of 2017 and 28,000 boepd in the first nine months of 2017.

(e) Net production from Libya averaged 18,000 boepd and 20,000 boepd in the third quarter and first nine months of 2018, respectively, and 12,000 boepd and 7,000 boepd in the third quarter and first nine months of 2017, respectively.

We forecast net production for 2018 to average approximately 255,000 boepd excluding Libya.  

United States:  Bakken net production was higher in the third quarter and first nine months of 2018, compared to the corresponding periods in 2017, primarily due to ongoing drilling activity and improved well performance in the current year, and the impact of reduced field availability due to adverse weather in the third quarter of 2017.  Excluding Bakken, net U.S. onshore total production was lower in the third quarter and first nine months of 2018, compared to the corresponding periods in 2017, due to the sale of our interests in the Utica shale play in August 2018, and the sale of our Permian assets in August 2017.  Total U.S. offshore oil production was higher in the third quarter of 2018, compared to the corresponding period in 2017, primarily due to higher production from the Stampede and Penn State fields, partially offset by natural decline.  Total U.S. offshore oil production was lower in the first nine months of 2018, compared to the corresponding period in 2017, primarily due to the 2018 impact of the shutdown at the third-party operated Enchilada platform and downtime from a second quarter 2018 planned well workover at the Tubular Bells Field, partially offset by higher production from the Stampede and Penn State fields.

International:  Net production was lower in the third quarter and first nine months of 2018, compared to the corresponding periods in 2017, primarily due to the sale of our assets in Equatorial Guinea and Norway, partially offset by higher production from the North Malay Basin full-field development and Libya.

Sales Volumes:  Worldwide sales volumes from Hess net production, excluding sales volumes of crude oil, natural gas liquids and natural gas purchased from third-parties, were as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
	(In thousands)
Crude oil - barrels		14,085		15,897		38,155		47,398
Natural gas liquids - barrels		3,696		3,920		10,624		11,391
Natural gas - mcf		56,251		50,808		151,946		138,742
Barrels of Oil Equivalent (a)		27,156		28,285		74,103		81,913
Crude oil - barrels per day		153		172		139		174
Natural gas liquids - barrels per day		40		43		39		41
Natural gas - mcf per day		611		552		557		508
Barrels of Oil Equivalent Per Day (a)		295		307		271		300

(a) Reflects natural gas production converted on the basis of relative energy content (six mcf equals one barrel).  Barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past.  In addition, natural gas liquids do not sell at prices equivalent to crude oil.  See the average selling prices in the table on page 24.

Marketing, including purchased oil and gas:  Marketing expense is mainly comprised of costs to purchase crude oil, natural gas liquids and natural gas from our partners in Hess operated wells or other third-parties, primarily in the U.S., and transportation costs for U.S. marketing activities.  The increase in the third quarter and first nine months of 2018, compared to the same periods in 2017, primarily reflects the impact of higher benchmark crude oil prices on the cost of purchased volumes.

Cash Operating Costs:  Cash operating costs, consisting of operating costs and expenses, production and severance taxes and E&P general and administrative expenses, were lower in the third quarter and first nine months of 2018 on an absolute and per-unit basis, compared to the same periods in 2017, primarily due to the impact of increased low-cost production from North Malay Basin, cost reduction efforts, and sales of higher cost assets in the second half of 2017.

Depreciation, Depletion and Amortization:  Depreciation, depletion and amortization (DD&A) expenses were lower in the third quarter and first nine months of 2018 on an absolute and per-unit basis, compared to the same periods in 2017, primarily due to the sale of assets which had higher DD&A rates than the portfolio average, a lower DD&A rate at the Bakken due to year-end 2017 proved reserve additions, and the impact of prior year asset impairments.

26

PART I - FINANCIAL INFORMATION (CONT’D.)

Consolidated Results of Operations (continued)

Unit Costs:  Unit cost per barrel of oil equivalent (boe) information is based on total E&P production volumes and excludes items affecting comparability of earnings as disclosed below.  Actual and forecast unit costs per boe are as follows:

	Actual								Forecast range (a)
	Three Months Ended				Nine Months Ended				Three Months Ended	Twelve Months Ended
	September 30,				September 30,				December 31,	December 31,
	2018		2017		2018		2017		2018	2018
Cash operating costs (b)	$	11.41	$	13.77	$	12.68	$	14.17	$12.50  — $13.50	$12.50  — $13.50
DD&A (c)		16.14		24.79		16.57		25.26	18.00  —  19.00	17.00  —  18.00
Total Production Unit Costs	$	27.55	$	38.56	$	29.25	$	39.43	$30.50 — $32.50	$29.50 — $31.50

(a) Forecast information excludes any contribution from Libya and items affecting comparability of earnings.

(b) Excluding items affecting comparability of earnings and Libya, cash operating costs per boe were $11.87 and $13.34 in the third quarter and first nine months of 2018, respectively, compared to $14.13 and $14.30 in the third quarter and first nine months of 2017, respectively.  

(c) Excluding items affecting comparability of earnings and Libya, DD&A per boe was $17.03 and $17.66 in the third quarter and first nine months of 2018, respectively, compared to $25.68 and $25.83 in the third quarter and first nine months of 2017, respectively.

Exploration Expenses:  Exploration expenses were as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
	(In millions)
Exploratory dry hole costs	$	119	$	—	$	132	$	—
Exploration lease and other impairment		8		7		28		22
Geological and geophysical expense and exploration overhead		42		34		111		129
	$	169	$	41	$	271	$	151

Exploratory dry hole costs in the third quarter of 2018 relate to the Aspy well, offshore Nova Scotia, Canada and the Pontoenoe-1 well at Block 42, offshore Suriname.  Exploratory dry hole costs in the first nine months of 2018 include the Aspy and Pontoenoe-1 wells, as well as the Sorubim-1 well on the Stabroek Block, offshore Guyana and the Bunga Teruntum-1 well in the North Malay Basin.

Exploration expenses, excluding dry hole expense, are estimated to be in the range of $55 million to $65 million in the fourth quarter of 2018 and $190 million to $200 million for the full year of 2018.

Income Taxes:  Excluding items affecting comparability of earnings between periods and Libyan operations, the effective income tax rate for E&P operations in the third quarter and first nine months of 2018 was a benefit of 11% and 22%, respectively, compared to a benefit of 18% and 12%, in the third quarter and first nine months of 2017, respectively.Excluding items affecting comparability of earnings between periods and Libyan operations, the E&P effective income tax rate is expected to be a benefit in the range of 0% to 4% in the fourth quarter of 2018, and a benefit in the range of 7% to 11% for the full year of 2018.

The enactment of U.S. Federal tax reform, commonly referred to as the U.S. Tax Cuts and Jobs Act (“Act”), provided for broad changes to the taxation of both domestic and foreign operations.  The financial statement impact of the Act was provisionally accounted for in the period ending December 31, 2017 and there have been no changes to such accounting to date.  The provisions of the Act, including its extensive transition rules, are complex and interpretive guidance continues to develop.  The Company has included reasonable estimates of the impact of the Act on its 2018 tax provision in accordance with SAB 118.  However, the Company’s evaluation is ongoing, and final application of the Act to our operations and financial results may differ from that for which we have provisionally provided.  Changes could arise as regulatory and interpretive action continues to clarify aspects of the Act and as changes are made to estimates that the Corporation has utilized in calculating the transition impacts.  

27

PART I - FINANCIAL INFORMATION (CONT’D.)

Consolidated Results of Operations (continued)

Items Affecting Comparability of Earnings Between Periods:

The following table summarizes, on an after-tax basis, income (expense) items affecting comparability of E&P earnings between periods:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
	(In millions)
Gain on asset sales, net	$	14		$	314		$	24		$	314
Vacated office space		(73	)		—			(73	)		—
Employee severance		—			—			(37	)		—
Impairment		—			(550	)		—			(550	)
	$	(59	)	$	(236	)	$	(86	)	$	(236	)

The following table summarizes, on a pre-tax basis, income (expense) items that affect comparability of E&P earnings between periods:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
	(In millions)
Gain on asset sales, net	$	14		$	330		$	24		$	330
Vacated office space		(73	)		—			(73	)		—
Employee severance		—			—			(37	)		—
Impairment		—			(2,503	)		—			(2,503	)
	$	(59	)	$	(2,173	)		(86	)		(2,173	)

Gain on asset sales, net:  In the third quarter of 2018, we recorded a pre-tax gain of $14 million ($14 million after income taxes) associated with the sale of our interests in the Utica shale play in eastern Ohio.  In the second quarter of 2018, we recorded a pre-tax gain of $10 million ($10 million after income taxes) associated with the sale of our interests in Ghana.  In the third quarter of 2017, we recorded a pre-tax gain of $330 million ($314 million after income taxes) associated with the sale of our enhanced oil recovery assets in the Permian Basin related to our E&P operations.

Vacated office space:  In the third quarter of 2018,we incurred noncash pre-tax charges of $73 million ($73 million after income taxes) in connection with vacated office space, of which $57 million is included in General and administrative expenses and $16 million is included in Depreciation, depletion and amortization in the Statement of Consolidated Income.

Employee severance:  In the first quarter of 2018, we recorded a net after-tax severance charge of $37 million related to a previously disclosed cost reduction program.  The pre-tax amounts are reported in Operating costs and expenses ($19 million), Exploration expenses, including dry holes and lease impairment ($3 million) and General and administrative expenses ($15 million), in the Statement of Consolidated Income.  

Impairment:  In the third quarter of 2017, we recorded a noncash impairment charge totaling $2,503 million pre-tax ($550 million after income taxes) associated with the anticipated sale of our interests in Norway, which closed in the fourth quarter of 2017.  See Note 10, Impairment in the Notes to Consolidated Financial Statements.

28

PART I - FINANCIAL INFORMATION (CONT’D.)

Consolidated Results of Operations (continued)

Midstream

Following is a summarized income statement of our Midstream operations:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2018		2017			2018		2017
	(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues	$	184	$	154		$	527	$	460
Loss on asset sale, net		—		(57	)		—		(57	)
Other, net		2		—			5		—
Total revenues and non-operating income		186		97			532		403
Costs and Expenses
Operating costs and expenses		51		42			139		150
General and administrative expenses		3		3			9		11
Interest expense		15		7			45		18
Depreciation, depletion and amortization		32		29			94		93
Total costs and expenses		101		81			287		272
Results of Operations Before Income Taxes		85		16			245		131
Provision (benefit) for income taxes (a)		10		(3	)		28		18
Net Income (Loss)		75		19			217		113
Less: Net income (loss) attributable to noncontrolling interests (b)		45		31			129		91
Net Income (Loss) Attributable to Hess Corporation	$	30	$	(12	)	$	88	$	22

(a) The provision for income taxes in the Midstream segment is presented before consolidating its operations with other U.S. activities of the Company and prior to evaluating realizability of net U.S. deferred taxes.  An offsetting impact is presented in the E&P segment.

(b) The noncontrolling interests’ share of income is not subject to tax and, therefore, is a pre-tax amount.

Total revenues and non-operating income for the third quarter and first nine months of 2018 increased, compared to the corresponding periods in 2017, primarily due to higher throughput volumes, partially offset by prior year activity associated with our former Permian assets that were sold in August 2017.

Operating costs and expenses for the third quarter of 2018 increased, compared to the prior year quarter due to higher activity related to produced water disposal services.  The decrease in Operating costs and expenses for the first nine months of 2018, compared to the corresponding period in 2017, was primarily due to the sale of our former Permian assets, partially offset by higher activity related to produced water disposal services.  The increase in interest expense in the third quarter and first nine months of 2018, compared to the corresponding periods in 2017, reflects higher borrowings by Hess Infrastructure Partners L.P. (HIP) following HIP’s issuance of fixed-rate notes in the fourth quarter of 2017.

Net income attributable to Hess Corporation from the Midstreamsegment is estimated to be approximately $30 million in the fourth quarter of 2018 and approximately $115 million for the full year of 2018.

Items Affecting Comparability of Earnings Between Periods:  In the third quarter of 2017, we recorded a pre-tax loss of $57 million ($34 million after income taxes and noncontrolling interest) associated with the sale of our Midstream assets in the Permian Basin.

29

PART I - FINANCIAL INFORMATION (CONT’D.)

Consolidated Results of Operations (continued)

Corporate, Interest and Other

The following table summarizes Corporate, Interest and Other expenses:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
	(In millions)
Corporate and other expenses (excluding items affecting comparability)	$	27		$	38		$	76		$	111
Interest expense		89			95			269			288
Less: Capitalized interest		(5	)		(23	)		(14	)		(61	)
Interest expense, net		84			72			255			227
Corporate, Interest and Other expenses before income taxes		111			110			331			338
Provision (benefit) for income taxes		(1	)		(2	)		(2	)		(10	)
Net Corporate, Interest and Other expenses after income taxes		110			108			329			328
Items affecting comparability of earnings between periods, after-tax		12			30			93			30
Total Corporate, Interest and Other Expenses After Income Taxes	$	122		$	138		$	422		$	358

Corporate and other expenses, excluding items affecting comparability, were lower in the third quarter and first nine months of 2018, compared with the corresponding periods in 2017, primarily due to lower employee related costs in the current year.  Interest expense was lower in the third quarter and first nine months of 2018, compared with the corresponding periods in 2017, primarily due to lower average borrowings.  Capitalized interest was lower in the third quarter and first nine months of 2018, compared with the corresponding periods in 2017, primarily due to the Stampede Field that commenced production in January 2018.

Fourth quarter 2018 corporate expenses are expected to be in the range of $25 million to $30 million, and interest expense is expected to be approximately $85 million.  We estimate corporate expenses for full year 2018 to be in the range of $100 million to $105 million, and interest expense to be approximately $340 million.  

Items Affecting Comparability of Earnings Between Periods:  In the third quarter of 2018, Corporate expenses include an allocation of noncash income tax expense of $12 million to offset the recognition of a noncash income tax benefit recorded in other comprehensive income resulting from changes in fair value of our 2019 crude oil hedging program, as required under accounting standards.  In the nine months ended September 30, 2018, we also recognized pre-tax charges totaling $53 million ($53 million after income taxes) related to the premium paid for debt repurchases, a pre-tax charge of $58 million ($58 million after income taxes) resulting from the settlement of legal claims related to former downstream interests, and, as required under accounting standards, we recognized an allocation of noncash income tax benefit of $30 million to offset the recognition of a noncash income tax expense recorded in other comprehensive income, resulting from a reduction in our pension liabilities.  In the third quarter of 2017, we incurred pre-tax charges of $30 million ($30 million after income taxes) in connection with vacated office space, of which, $11 million is included in General and administrative expenses and $19 million is included in Depreciation, depletion and amortization in the Statement of Consolidated Income.

Other Items Potentially Affecting Future Results

Our future results may be impacted by a variety of factors, including but not limited to, volatility in the selling prices of crude oil, natural gas liquids and natural gas, reserve and production changes, asset sales, impairment charges and exploration expenses, industry cost inflation and/or deflation, changes in foreign exchange rates and income tax rates, changes in deferred tax asset valuation allowances, the effects of weather, political risk, environmental risk and catastrophic risk.  For a more comprehensive description of the risks that may affect our business, see Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2017.

30

PART I - FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources

The following table sets forth certain relevant measures of our liquidity and capital resources:

	September 30,			December 31,
	2018			2017
	(In millions, except ratio)
Cash and cash equivalents (a)	$	3,004		$	4,847
Current maturities of long-term debt		85			580
Total debt (b)		6,694			6,977
Total equity		11,046			12,354
Debt to capitalization ratio (c)		37.7	%		36.1	%

(a) Includes $395 million of cash attributable to HIP, our 50/50 Midstream joint venture, at September 30, 2018 (December 31, 2017: $356 million).

(b) Includes $983 million of debt outstanding at September 30, 2018 from HIP that is non-recourse to Hess Corporation (December 31, 2017: $980 million).

(c) Total debt as a percentage of the sum of total debt plus equity.

Cash Flows

The following table summarizes our cash flows:

	Nine Months Ended, September 30,
	2018			2017
	(In millions)
Net cash provided by (used in):
Operating activities	$	1,058		$	602
Investing activities		(901	)		(601	)
Financing activities		(2,000	)		(207	)
Net Increase (Decrease) in Cash and Cash Equivalents	$	(1,843	)	$	(206	)

Operating activities:Net cash provided by operating activities was $1,058 million in the first nine months of 2018, compared to $602million in the first nine months of 2017.  The increase in 2018 operating cash flows primarily reflects higher benchmark crude oil prices, and lower operating costs, partially offset by lower production volumes due to asset sales.  Changes in working capital was a use of cash of $483 million in the first nine months of 2018, and a use of cash of $631 million in the first nine months of 2017.  Changes in working capital during 2018 primarily relate to an increase in accounts receivable, which reflects higher realized sales prices, a reduction in accounts payable and accrued liabilities, and premiums paid on commodity contracts.

Investing activities:Cash outflows from investing activities increased in the first nine months of 2018 compared to the prior year period.  Additions to property, plant and equipment were up $50 million, compared to the same period in 2017, primarily reflecting increased Midstream expenditures, increased drilling activity in the Bakken, increased activity at the Liza Phase 1 development, exploratory drilling offshore Nova Scotia, Canada, and lower activity in the Gulf of Mexico in 2018.  The Midstream segment invested $67 million in its 50/50 joint venture with Targa Resources, which was formed in 2018.  Proceeds received from assets sales were $607 million in the first nine months of 2018 down from $783 million in the first nine months of 2017.  Proceeds from asset sales in 2018 include the sale of our joint venture interests in the Utica shale play in eastern Ohio, and our share of proceeds from the sale and lease-back transaction of the floating, storage, and offloading vessel in the North Malay Basin.

The following table reconciles capital expenditures incurred on an accrual basis to Additions to property, plant and equipment:  

	Nine Months Ended, September 30,
	2018			2017
	(In millions)
Capital expenditures incurred - E&P	$	(1,340	)	$	(1,351	)
Increase (decrease) in related liabilities		75			76
Additions to property, plant and equipment - E&P	$	(1,265	)	$	(1,275	)
Capital expenditures incurred - Midstream	$	(204	)	$	(75	)
Increase (decrease) in related liabilities		36			(33	)
Additions to property, plant and equipment - Midstream	$	(168	)	$	(108	)

31

PART I - FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources (continued)

Financing activities: In the first nine months of 2018, net debt repayments totaled $610 million including the redemption of 8.125% notes due 2019, compared to $92 million in the first nine months of 2017.  In the first nine months of 2018, we also cash settled the repurchase of $1,120 million of common stock (2017: $- million).  In addition, we paid common and preferred stock dividends totaling $262 million in the first nine months of 2018, compared to $273 million in the first nine months of 2017.  In the first nine months of 2017, Hess Midstream Partners LP received $365.5 million from the issuance of common units in an initial public offering, of which $350 million was distributed 50/50 to Hess Corporation and GIP.  

Future Capital Requirements and Resources

Excluding our Midstream segment, we ended the third quarter of 2018 with approximately $2.6 billion in cash and cash equivalents, total liquidity including available committed credit facilities of approximately $7.0 billion and no significant near-term debt maturities.

Net cash provided by operating activities was $1,058 million in the first nine months of 2018, compared to $602 million in the first nine months of 2017, which includes uses of working capital of $483 million and $631 million, respectively.  Capital expenditures were $1,544 million in the first nine months of 2018 and $1,426 million in the first nine months of 2017.  Based on current forward strip crude oil prices for 2019, we expect cash flow from operating activities and cash and cash equivalents existing at September 30, 2018 will be sufficient to fund our capital investment program and dividends through the end of 2019, and the repurchase of $250 million of common stock remaining under our $1.5 billion stock repurchase program in the fourth quarter of 2018.

The table below summarizes the capacity, usage and available capacity of our borrowings and letter of credit facilities at September 30, 2018:

						Letters of
	Expiration					Credit		Total		Available
	Date	Capacity		Borrowings		Issued		Used		Capacity
		(In millions)
Hess Corporation
Revolving credit facility - Hess Corporation (a)	January2021	$	4,000	$	—	$	—	$	—	$	4,000
Committed lines	Various (b)		445		—		29		29		416
Uncommitted lines	Various (b)		266		—		266		266		—
Total - Hess Corporation		$	4,711	$	—	$	295	$	295	$	4,416
Midstream
Revolving credit facility - HIP (c)	November 2022	$	600	$	—	$	—	$	—	$	600
Revolving credit facility - Hess Midstream Partners LP (HESM) (d)	March 2021		300		—		—		—		300
Total -  Midstream		$	900	$	—	$	—	$	—	$	900

(a) In January 2020, the capacity reduces to $3.7 billion.

(b) Committed and uncommitted lines have expiration dates through 2019 and 2018, respectively.

(c) This facility may only be utilized by HIP and is non-recourse to Hess Corporation.

(d) This facility may only be utilized by HESM and is non-recourse to Hess Corporation.

Hess Corporation’s $4.0 billion syndicated revolving credit facility expires in January 2021, with commitments of $3.7 billion available for the final year.  Borrowings on the facility will generally bear interest at 1.30% above the London Interbank Offered Rate (LIBOR).  The interest rate will be higher if our credit rating is lowered.  The facility contains a financial covenant that limits the amount of the total borrowings on the last day of each fiscal quarter to 60% of the Corporation’s total capitalization, defined as total debt plus stockholders’ equity.  As of September 30, 2018, Hess Corporation had no outstanding borrowings under this facility and was in compliance with this financial covenant.  

We also have a shelf registration under which we may issue additional debt securities, warrants, common stock or preferred stock.

32

PART I - FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources (continued)

HIP has $800 million of senior secured syndicated credit facilities, consisting of a $600 million 5-year revolving credit facility and a $200 million 5-year Term Loan A facility.  The revolving credit facility can be used for borrowings and letters of credit to fund the joint venture’s operating activities and capital expenditures.  Borrowings under the 5-year Term Loan A facility will generally bear interest at LIBOR plus an applicable margin ranging from 1.55% to 2.50%, while the applicable margin for the 5-year syndicated revolving credit facility ranges from 1.275% to 2.000%.  The interest rate is subject to adjustment based on HIP’s leverage ratio, which is calculated as total debt to Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA).  If HIP obtains an investment grade credit rating, as defined in the amended credit agreement, pricing levels will be based on the credit ratings in effect from time to time.  The credit facilities contain financial covenants that generally require a leverage ratio of no more than 5.0 to 1.0 for the prior four fiscal quarters and an interest coverage ratio, which is calculated as EBITDA to cash interest expense, of no less than 2.25 to 1.0 for the prior four fiscal quarters.  The credit agreement includes a secured leverage ratio test not to exceed 3.75 to 1.00 for so long as the facilities remain secured.  HIP was in compliance with these financial covenants at September 30, 2018.  Outstanding borrowings under this credit facility are non-recourse to Hess Corporation.  At September 30, 2018, HIP’s revolving credit facility was undrawn and borrowings under the Term Loan A facility amounted to $200 million, excluding deferred issuance costs.  The credit facilities are secured by first priority perfected liens on substantially all of HIP’s and certain of its wholly-owned subsidiaries’ directly owned assets, including its equity interests in certain subsidiaries, subject to customary exclusions.

Hess Midstream Partners LP (the “Partnership”) has a $300 million 4-year senior secured syndicated revolving credit facility through March 2021 that can be used for borrowings and letters of credit to fund operating activities and capital expenditures of the Partnership.  Borrowings on the credit facility will generally bear interest at LIBOR plus an applicable margin of 1.275%.  The interest rate is subject to adjustment based on the Partnership’s leverage ratio, which is calculated as total debt to EBITDA.  If the Partnership obtains credit ratings, pricing levels will be based on the credit ratings in effect from time to time.  The Partnership is subject to customary covenants in the credit agreement, including financial covenants that generally require a leverage ratio of no more than 4.5 to 1.0 for the prior four fiscal quarters.  The credit facility is secured by first priority perfected liens on substantially all directly owned assets of the Partnership and its wholly-owned subsidiaries, including equity interests in subsidiaries, subject to certain customary exclusions.  Outstanding borrowings under this credit facility are non-recourse to Hess Corporation.  At September 30, 2018, this facility was undrawn.

Market Risk Disclosures

We are exposed in the normal course of business 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.  See Note 15, Financial Risk Management Activities, in the Notes to Consolidated Financial Statements.

Financial Risk Management Activities

We have outstanding foreign exchange contracts with notional amounts totaling $9 million at September 30, 2018 that are used to reduce our exposure to fluctuating foreign exchange rates for the British Pound.  The change in fair value of foreign exchange contracts from a 10% strengthening of the U.S. Dollar exchange rate is estimated to be a loss of approximately $1 million at September 30, 2018.

At September 30, 2018, our outstanding long‑term debt of $6,421 million, excluding capital leases and including current maturities, had a fair value of $6,925 million.  A 15% increase or decrease in the rate of interest would decrease or increase the fair value of debt by approximately $490 million or $550 million, respectively.

At September 30, 2018, we have outstanding West Texas Intermediate (WTI) crude oil put contracts.  See Note 15, Financial Risk Management Activities in the Notes to Consolidated Financial Statements. As of September 30, 2018, an assumed 10% increase in the forward WTI crude oil prices used in determining the fair value of our crude oil put contracts would reduce the fair value of these derivatives instruments by approximately $30 million, while an assumed 10% decrease in the same WTI crude oil prices would increase the fair value of these derivative instruments by approximately $50 million.

33

PART I - FINANCIAL INFORMATION (CONT’D.)

Forward-looking Information

Certain sections in this Quarterly Report on Form 10-Q, including information incorporated by reference herein, contain “forward-looking” statements, as defined under the Private Securities Litigation Reform Act of 1995.  Generally, the words “anticipate,” “estimate,” “expect,” “forecast,” “guidance,” “could,” “may,” “should,” “believe,” “intend,” “project,” “plan,” “predict,” “will,” “target” and similar expressions identify forward-looking statements, which generally are not historical in nature.  Forward-looking statements related to our operations and financial conditions are based on our current understanding, assessments, estimates and projections.  Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from our historical experience and our current projections or expectations.  As and when made, we believe that these forward-looking statements are reasonable.  However, caution should be taken not to place undue reliance on any such forward-looking statements since such statements speak only as of the date when made and there can be no assurance that such forward-looking statements will occur.  We are not obligated to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  Risk factors that could materially impact future actual results are discussed in Item 1A. Risk Factors in our Annual Report on Form 10-K and in our other filings with the SEC.

34

PART I - FINANCIAL INFORMATION (CONT’D.)

Item 3.Quantitative and Qualitative Disclosures about Market Risk.

The information required by this item is presented under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Disclosures.”  

Item 4.Controls and Procedures.

Based upon their evaluation of the Corporation’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of September 30, 2018, John B. Hess, Chief Executive Officer, and John P. Rielly, Chief Financial Officer, concluded that these disclosure controls and procedures were effective as of September 30, 2018.

There was no change in internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Rules 13a-15 or 15d-15 in the quarter ended September 30, 2018 that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

35

PART II – OTHER INFORMATION

Item 1.          Legal Proceedings.

Information regarding legal proceedings is contained in Note 13, Guarantees and Contingencies in the Notes to Consolidated Financial Statements and is incorporated herein by reference.

Item 2.          Share Repurchase Activities.

Our common stock share repurchase activities for the three months ended September 30, 2018, were as follows:

Period	Total Number of Shares Purchased (a)		Average Price Paid per Share (a)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (b)		Maximum ApproximateDollar Value of Shares that May Yet be Purchased Under the Plans or Programs (c) (In millions)
July		2,412,545	$	63.98		2,412,545	$	950
August		729,203		63.97		729,203		949
September		699,004		70.10		699,004		900
Total		3,840,752	$	65.09		3,840,752

(a) In July 2018, we entered into an accelerated share repurchase program (ASR) with a financial institution to repurchase $200 million of our common stock, in which we received an initial delivery of approximately 2.4 million shares and upon completion of this transaction in August, we received an additional delivery of approximately 0.7 million shares of our common stock.  The transaction price was determined by the volume-weighted average price of the shares during the term less a negotiated discount.  During August and September, we repurchased approximately 0.7 million shares in open-market transactions.  The average price paid per share was inclusive of transaction fees.

(b) Since initiation of the buyback program in August 2013, total shares repurchased through September 30, 2018 amounted to 87.1 million at a total cost of $6.6 billion including transaction fees.

(c) In March 2013, we announced that our Board of Directors approved a stock repurchase program that authorized the purchase of common stock up to a value of $4.0 billion.  In May 2014, the share repurchase program was increased to $6.5 billion and in March 2018, it was increased further to $7.5 billion.

36

PART II – OTHER INFORMATION (CONT’D.)

Item 6.          Exhibits.

a.	Exhibits
	31(1)	Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
	31(2)	Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
	32(1)	Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
	32(2)	Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
	101(INS)	XBRL Instance Document.
	101(SCH)	XBRL Schema Document.
	101(CAL)	XBRL Calculation Linkbase Document.
	101(LAB)	XBRL Labels Linkbase Document.
	101(PRE)	XBRL Presentation Linkbase Document.
	101(DEF)	XBRL Definition Linkbase Document.

37

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

HESS CORPORATION
(REGISTRANT)
By	/s/ John B. Hess
	JOHN B. HESS
	CHIEF EXECUTIVE OFFICER
By	/s/ John P. Rielly
	JOHN P. RIELLY
	SENIOR VICE PRESIDENT AND
	CHIEF FINANCIAL OFFICER

Date: November 9, 2018

38

EX-31.1

Exhibit 31(1)

CERTIFICATIONS

I, John B. Hess, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Hess Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and the internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By	/s/ John B. Hess
	JOHN B. HESS
	CHIEF EXECUTIVE OFFICER

Date:  November 9, 2018

EX-31.2

Exhibit 31(2)

I, John P. Rielly, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Hess Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and the internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

By	/s/ John P. Rielly
	JOHN P. RIELLY
	SENIOR VICE PRESIDENT AND
	CHIEF FINANCIAL OFFICER

Date:  November 9, 2018

EX-32.1

Exhibit 32(1)

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Hess Corporation (the “Corporation”) on Form 10-Q for the period ending September 30, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John B. Hess, Chief Executive Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

By	/s/ John B. Hess
	JOHN B. HESS
	CHIEF EXECUTIVE OFFICER
	Date: November 9, 2018

A signed original of this written statement required by Section 906 has been provided to Hess Corporation and will be retained by Hess Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32(2)

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Hess Corporation (the “Corporation”) on Form 10-Q for the period ending September 30, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John P. Rielly, Senior Vice President and Chief Financial Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

By	/s/ John P. Rielly
	JOHN P. RIELLY
	SENIOR VICE PRESIDENT AND
	CHIEF FINANCIAL OFFICER
	Date: November 9, 2018

A signed original of this written statement required by Section 906 has been provided to Hess Corporation and will be retained by Hess Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2018 shares
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
Trading Symbol	HES
Entity Registrant Name	HESS CORP
Entity Central Index Key	0000004447
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding	296,253,136

XML

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

XML

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	$ 1.00	$ 1.00
Preferred stock, shares authorized	20,000,000	20,000,000
Preferred stock, shares issued	575,000	575,000
Preferred stock, liquidation preference per share	$ 1,000	$ 1,000
Series A, cumulative mandatory convertible preferred stock - dividend rate	8.00%	8.00%
Common stock, par value	$ 1.00	$ 1.00
Common stock, shares authorized	600,000,000	600,000,000
Common stock, shares issued	296,253,136	315,053,615

XML

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

XML

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)

XML

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

XML

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

XML

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, using the modified retrospective method.  The adoption of this standard did not affect the timing of revenue recognition for our uncompleted contracts at January 1, 2018, and as a result, no cumulative effect adjustment to Retained earnings was recognized.  Accounts receivables from contracts with customers is presented separately in the Consolidated Balance Sheet with the prior year balance recast to conform to the current period presentation.  In addition, as the adoption of ASC 606 did not affect previous conclusions regarding our involvement as a principal versus agent in contracts with customers, there were no changes in presentation to the Statement of Consolidated Income.

In the first quarter of 2018, we adopted Accounting Standards Update (ASU) 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.  This ASU prohibits the capitalization of the non-service cost components of net periodic benefit cost in connection with the production or construction of an asset.  This provision was applied prospectively effective January 1, 2018.  The provision requiring that non-service cost components of net periodic benefit cost to be presented separately from the service cost component in the Statement of Consolidated Income was applied retrospectively.  We elected the practical expedient allowing the use of the amounts previously disclosed in the notes to our consolidated financial statements as the basis for applying this provision retrospectively as the capitalization of the non-service cost components of net periodic benefit cost was not material during the comparative periods.  This resulted in a reclassification of $- million and $9 million of expense from Operating costs and expenses, and General and administrative expenses to Other, net for the three months ended and nine months ended September 30, 2017, respectively.

In the first quarter of 2018, we adopted ASU 2017-12, Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities.  This ASU makes certain targeted improvements to simplify the application of the existing hedge accounting guidance.  The adoption of this ASU resulted in an increase to Retained earnings and a decrease in Accumulated other comprehensive income (loss) of $1 million to remove the cumulative effect of hedging ineffectiveness previously recognized in earnings for contracts designated as hedging instruments that were outstanding at January 1, 2018.  

In the first quarter of 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230):  Restricted Cash (a consensus of the FASB Emerging Issues Task Force).  This ASU requires that the total change in cash and cash equivalents and restricted cash be reflected on the statement of cash flows.  A reconciliation to the balance sheet is also required when cash and cash equivalents and restricted cash are not separately presented on the balance sheet or are presented in more than one financial statement line item on the balance sheet.  The adoption of this ASU did not have a material impact on our Statement of Consolidated Cash Flows.

In the first quarter of 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230):  Classification of Certain Cash Receipts and Cash Payments (a consensus of the FASB Emerging Issues Task Force).  This ASU is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows.  The guidance addresses eight specific classification issues for which current guidance is either unclear or is non-specific.  The requirement that fees paid to third-parties and premiums incurred in connection with the repayment of debt be classified as financing cash outflows is among the classification issues addressed by this ASU.  The adoption of this ASU did not have a material impact on our Statement of Consolidated Cash Flows.

To conform with the Statement of Consolidated Income presentation in our December 31, 2017 Form 10-K, we have revised the presentation of Sales and other operating revenues and Marketing, including purchased oil and gas for the three months and nine months ended September 30, 2017 associated with the recovery of certain natural gas processing costs from third-parties, by reducing each by $22 million and $60 million, respectively.  This revision did not impact net income, our Consolidated Balance Sheet, Statement of Consolidated Comprehensive Income, Statement of Consolidated Cash Flows, nor Statement of Consolidated Equity.  Amounts reported as Sales and other operating revenues and Marketing, including purchased oil and gas (formerly Costs of products sold) in our September 30, 2017 Form 10-Q were $1,370 million and $360 million, respectively, for the third quarter of 2017 and $3,863 million and $851 million, respectively, for the nine months ended September 30, 2017.

New Accounting Pronouncements:  In February 2016, the FASB issued ASU 2016-02, Leases, as a new Accounting Standards Codification (ASC) Topic, ASC 842.  The new standard 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.  This ASU makes changes to the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments.  The standard requires the use of a forward-looking "expected loss" model compared to the current "incurred loss" model.  This ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted beginning in the first quarter of 2019.  We are currently assessing the impact of the ASU on our consolidated financial statements.

In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment.  This ASU modifies the concept of goodwill impairment from a condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of the reporting unit exceeds its fair value.  Thus, an entity should recognize an impairment charge for the amount by which the carrying amount of a reporting unit exceeds its fair value.  The impairment charge would be limited by the amount of goodwill allocated to the reporting unit.  This ASU removes the requirement to determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if the reporting unit had been acquired in a business combination.  This ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted.  We are currently assessing the impact of the ASU on our consolidated financial statements.

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.  This ASU allows the reclassification of stranded income tax effects within Accumulated other comprehensive income (loss) to Retained earnings that resulted from the enactment of U.S. Federal income tax reform, commonly referred to as the U.S. Tax Cuts and Jobs Act (“Act”).  Specifically, this ASU provides entities the option to reclassify the stranded income tax effects resulting from the reduction to the corporate income tax rate from the Act upon adoption of this ASU, instead of upon liquidation of the individual items (or of the underlying portfolio of items) within Accumulated other comprehensive income (loss).  This ASU is effective for us beginning in the first quarter of 2019, with early adoption permitted.  We are currently assessing the impact of the ASU on our consolidated financial statements.

XML

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 within Sales and other operating revenues and Marketing, including purchased oil and gas, respectively.  Where control of crude oil, NGLs, or natural gas is not transferred to Hess, revenue is presented net of the associated cost of purchased volumes within Sales and other operating revenues in the Statement of Consolidated Income.

Contract types

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

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

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

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

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

Contract Balances

Our right to receive or collect payment from the customer is aligned with the timing of revenue recognition except in situations when we receive shortfall payments under contracts with take-or-pay provisions with customer make-up rights.  Shortfall payments received from customers under contracts with take-or-pay provisions with customer make-up rights are deferred upon receipt and reflected as a contract liability.  At 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 the exemption from disclosure of revenue recognizable in future periods as these performance obligations are satisfied.

Sales-based Taxes

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

Midstream

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

The Midstream segment has multiple long-term, fee-based commercial agreements with a marketing subsidiary of Hess, each 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 to recognize revenue in the amount it is entitled to invoice.  If the commercial agreements have take-or-pay provisions, the Midstream segment’s responsibility to stand-ready to service a minimum volume over each quarterly commitment period represent separate, distinct performance obligations.  Shortfall payments received under take-or-pay provisions are recognized as revenue in the calendar quarter the shortfall occurs as the customer does not have make-up rights beyond the calendar quarter end of the quarterly commitment period.  All revenues, receivables, and contract balances arising from the commercial agreements between the Midstream segment and the Hess marketing subsidiary that is the counterparty to the commercial agreements are eliminated upon consolidation.

XML

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.  

XML

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.

XML

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

XML

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.

XML

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).

XML

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 in connection with vacated office space.

XML

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.

XML

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.

XML

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 following workforce reductions.  In connection with this curtailment, as required under accounting standards, we remeasured our U.S. retirement plans and recorded a total decrease of $125 million in the Corporation’s U.S. post retirement liabilities.  This reduction was primarily driven by a change in weighted average discount rates used to measure the liabilities.  There was no change to the weighted average expected long-term rate of return on plan assets.

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

Net non-service pension costs included in Other, net in the Statement of Consolidated Income for the three and nine months ended September 30, 2018 was income of $17 million and $49 million, respectively, compared to expenses of $0 million and $9 million for the three and nine months ended September 30, 2017, respectively.

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.

XML

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).

XML

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.

XML

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

XML

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, we purchased WTI put options with a notional amount of 90,000 bopd with a WTI monthly floor price of $60 per barrel for calendar year 2019.

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

	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.  In 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 Accumulated other comprehensive income (loss) 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 Interest expense in the Statement of Consolidated Income.  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 crude oil price hedging contracts, which were de-designated as cash flow hedges in the fourth quarter of 2017, decreased Sales and other operating revenues by $4 million and $20 million, respectively.  At September 30, 2018, after-tax deferred losses in Accumulated other comprehensive income (loss) 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 Other, net in Revenues and non-operating income in the Statement of Consolidated Income 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.

XML

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.

XML

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.  This ASU makes changes to the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments.  The standard requires the use of a forward-looking "expected loss" model compared to the current "incurred loss" model.  This ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted beginning in the first quarter of 2019.  We are currently assessing the impact of the ASU on our consolidated financial statements.

In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment.  This ASU modifies the concept of goodwill impairment from a condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of the reporting unit exceeds its fair value.  Thus, an entity should recognize an impairment charge for the amount by which the carrying amount of a reporting unit exceeds its fair value.  The impairment charge would be limited by the amount of goodwill allocated to the reporting unit.  This ASU removes the requirement to determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if the reporting unit had been acquired in a business combination.  This ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted.  We are currently assessing the impact of the ASU on our consolidated financial statements.

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.  This ASU allows the reclassification of stranded income tax effects within Accumulated other comprehensive income (loss) to Retained earnings that resulted from the enactment of U.S. Federal income tax reform, commonly referred to as the U.S. Tax Cuts and Jobs Act (“Act”).  Specifically, this ASU provides entities the option to reclassify the stranded income tax effects resulting from the reduction to the corporate income tax rate from the Act upon adoption of this ASU, instead of upon liquidation of the individual items (or of the underlying portfolio of items) within Accumulated other comprehensive income (loss).  This ASU is effective for us beginning in the first quarter of 2019, with early adoption permitted.  We are currently assessing the impact of the ASU on our consolidated financial statements.

XML

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.

XML

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

XML

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

XML

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

XML

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

XML

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

XML

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	)

XML

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)

XML

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

XML

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

XML

Common Stock Repurchase Program - Additional Information (Details) shares in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2018 USD ($) shares	Sep. 30, 2018 USD ($) shares	Sep. 30, 2018 USD ($) 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	23.0
Share repurchase program, amount	$ 1,500,000,000	$ 1,500,000,000	$ 1,500,000,000

XML

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		2019
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

XML

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

XML

Capitalized Exploratory Well Costs - Net Changes in Capitalized Exploratory Well Costs (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($)
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

XML

Capitalized Exploratory Well Costs - Additional Information (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($)
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%

XML

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

XML

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

XML

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)

XML

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

XML

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

XML

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

XML

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	0.0
Stock Options
Weighted average number of common shares outstanding:
Effect of dilutive securities	0.0	0.0
Performance Share Units
Weighted average number of common shares outstanding:
Effect of dilutive securities	0.0	0.0
Mandatory Convertible Preferred Stock
Weighted average number of common shares outstanding:
Effect of dilutive securities	0.0	0.0

XML

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

XML

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

XML

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

XML

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

XML

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

XML

Financial Risk Management Activities - Gross Notional Amounts of Outstanding Financial Risk Management Derivative Contracts (Detail) - WTI	9 Months Ended	12 Months Ended
	Sep. 30, 2018 MMBbls $ / bbl	Dec. 31, 2017 MMBbls $ / bbl
2018
Derivative [Line Items]
Calendar year program	2018	2018
Instrument type	Puts	Collars
Effective date	Oct. 01, 2018	Jan. 01, 2018
End date	Dec. 31, 2018	Dec. 31, 2018
Crude oil volumes (millions of barrels) | MMBbls	10.6	42.0
Ceiling price	0	65
Floor price	50	50
2019
Derivative [Line Items]
Calendar year program	2019
Instrument type	Puts
Effective date	Jan. 01, 2019
End date	Dec. 31, 2019
Crude oil volumes (millions of barrels) | MMBbls	32.9
Ceiling price	0
Floor price	60

XML

Financial Risk Management Activities - Additional Information (Detail)	3 Months Ended			9 Months Ended		12 Months Ended
	Sep. 30, 2018 USD ($) $ / bbl	Mar. 31, 2018 USD ($) bbl / d	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($) bbl / d $ / bbl	Sep. 30, 2017 USD ($)	Dec. 31, 2017 USD ($) bbl / d $ / bbl
Derivative Instruments Gain Loss [Line Items]
Redeemed and repurchased debt				terminated interest rate swaps with a notional amount of $350 million.
Designated as Fair Value Hedges
Derivative Instruments Gain Loss [Line Items]
Redeemed and repurchased debt				In the first quarter of 2018, we paid $3 million, to terminate interest rate swaps with a gross notional amount of $350 million. See Note 4, Debt.
Crude Oil | Derivative Contracts Designated as Hedging Instruments
Derivative Instruments Gain Loss [Line Items]
Crude oil price hedging contracts increased (decreased) Sales and other operating revenues by this amount, pre-tax	$ (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

XML

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

XML

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

XML

Financial Risk Management Activities - Fair Value Measurements - Additional Information (Detail) $ in Millions	Sep. 30, 2018 USD ($)
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

XML

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%