Indicate by check mark whether the ~~registrant:~~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, a 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.

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 March 31, ~~2019,~~2020, there were ~~304,280,819~~307,158,340 shares of Common Stock outstanding.

~~Securities registered or to be registered in pursuant to Section 12(b) of the Act:~~

Item No.		Page Number		Page Number
	PART I - FINANCIAL INFORMATION		PART I - FINANCIAL INFORMATION
1.	Financial Statements (Unaudited)		Financial Statements (Unaudited)
	Consolidated Balance Sheet at March 31, 2019, and December 31, 2018	2
	Statement of Consolidated Income for the Three Months Ended March 31, 2019, and 2018	3
	Statement of Consolidated Comprehensive Income for the Three Months Ended March 31, 2019, and 2018	4	Consolidated Balance Sheet at March 31, 2020, and December 31, 2019	2
	Statement of Consolidated Cash Flows for the Three Months Ended March 31, 2019, and 2018	5	Statement of Consolidated Income for the Three Months Ended March 31, 2020, and 2019	3
	Statement of Consolidated Equity for the Three Months Ended March 31, 2019, and 2018	6	Statement of Consolidated Comprehensive Income for the Three Months Ended March 31, 2020, and 2019	4
	Notes to Consolidated Financial Statements (Unaudited)	7	Statement of Consolidated Cash Flows for the Three Months Ended March 31, 2020, and 2019	5
	Note 1 - Basis of Presentation	7	Statement of Consolidated Equity for the Three Months Ended March 31, 2020, and 2019	6
	Note 2 - Leases	8	Notes to Consolidated Financial Statements (Unaudited)	7
	Note 3 - Preferred Stock Conversion	10	Note 1 - Basis of Presentation	7
	Note 4 - Revenue	10	Note 2 - Impairment	7
	Note 5 - Inventories	10	Note 3 - Inventories	7
	Note 6 - Capitalized Exploratory Well Costs	11	Note 4 – Property Plant and Equipment	8
	Note 7 - Hess Infrastructure Partners LP	11	Note 5 - Hess Midstream LP	8
	Note 8 - Retirement Plans	12	Note 6 - Debt	8
	Note 9 - Debt	12	Note 7 - Retirement Plans	9
	Note 10 - Weighted Average Common Shares	12	Note 8 - Revenue	9
	Note 11 - Guarantees and Contingencies	13	Note 9 - Weighted Average Common Shares	10
	Note 12 - Segment Information	15	Note 10 - Guarantees and Contingencies	10
	Note 13 - Financial Risk Management Activities	15	Note 11 - Segment Information	12
	Note 14 - Subsequent Event	17	Note 12 - Financial Risk Management Activities	12

2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
3.	Quantitative and Qualitative Disclosures about Market Risk	32	Quantitative and Qualitative Disclosures about Market Risk	30
4.	Controls and Procedures	32	Controls and Procedures	30

	PART II - OTHER INFORMATION		PART II - OTHER INFORMATION
1.	Legal Proceedings	33	Legal Proceedings	31
1A.			Risk Factors	31
2.	Share Repurchase Activities	33	Share Repurchase Activities	32
5.			Other Information	32
6.	Exhibits	34	Exhibits	33
	Signatures	35	Signatures	34

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.

	March 31,			December 31,			March 31,		December 31,
	2019			2018			2020		2019
	(In millions,						(In millions,
	except share amounts)						except share amounts)
Assets
Current Assets:
Cash and cash equivalents	$	2,300		$	2,694		$	2,080	$	1,545
Accounts receivable:
From contracts with customers		868			771			600		940
Joint venture and other		248			230			194		230
Crude oil derivative contracts								1,098		125
Inventories		274			245			230		261
Other current assets		144			519			68		55
Total current assets		3,834			4,459			4,270		3,156
Property, plant and equipment:
Total — at cost		33,446			33,222			31,704		35,820
Less: Reserves for depreciation, depletion, amortization and lease impairment		17,548			17,139			16,893		19,006
Property, plant and equipment — net		15,898			16,083			14,811		16,814
Operating lease right-of-use assets — net		713			—			386		447
Finance lease right-of-use assets — net		332			—			187		299
Goodwill		360			360			360		360
Deferred income taxes		22			21			77		80
Other assets		557			510			626		626
Total Assets	$	21,716		$	21,433		$	20,717	$	21,782
Liabilities
Current Liabilities:
Accounts payable	$	399		$	495		$	431	$	411
Accrued liabilities		1,369			1,560			1,334		1,803
Taxes payable		89			81			33		97
Current maturities of long-term debt		12			67			3		—
Current portion of operating and finance lease obligations		402			—			146		199
Total current liabilities		2,271			2,203			1,947		2,510
Long-term debt		6,550			6,605			8,191		7,142
Long-term operating lease obligations		436			—			357		353
Long-term finance lease obligations		250			—			233		238
Deferred income taxes		420			421			328		415
Asset retirement obligations		745			741			929		897
Other liabilities and deferred credits		491			575			554		521
Total Liabilities		11,163			10,545			12,539		12,076
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 — 0 shares (2018: 574,997)		—			1
Common stock, par value $1.00; Authorized — 600,000,000 shares
Issued �� 304,280,819 shares (2018: 291,434,534)		304			291
Issued — 307,158,340 shares (2019: 304,955,472)								307		305
Capital in excess of par value		5,481			5,386			5,633		5,591
Retained earnings		4,207			4,257			1,021		3,535
Accumulated other comprehensive income (loss)		(650	)		(306	)		239		(699	)
Total Hess Corporation stockholders’ equity		9,342			9,629			7,200		8,732
Noncontrolling interests		1,211			1,259			978		974
Total equity		10,553			10,888			8,178		9,706
Total Liabilities and Equity	$	21,716		$	21,433		$	20,717	$	21,782

	Three Months Ended					Three Months Ended
	March 31,					March 31,
	2019		2018			2020			2019
	(In millions, except per share amounts)					(In millions, except per share amounts)
Revenues and Non-Operating Income
Sales and other operating revenues	$	1,572	$	1,346		$	1,354		$	1,572
Gains on asset sales, net		—		7
Other, net		27		37			15			27
Total revenues and non-operating income		1,599		1,390			1,369			1,599

Costs and Expenses
Marketing, including purchased oil and gas		408		358			378			408
Operating costs and expenses		266		288			303			266
Production and severance taxes		39		39			42			39
Exploration expenses, including dry holes and lease impairment		34		40			189			34
General and administrative expenses		87		110			102			87
Interest expense		98		103			113			98
Loss on debt extinguishment		—		27
Depreciation, depletion and amortization		498		417			561			498
Impairment							2,126			—
Total costs and expenses		1,430		1,382			3,814			1,430
Income (Loss) Before Income Taxes		169		8			(2,445	)		169
Provision (benefit) for income taxes		94		73			(79	)		94
Net Income (Loss)		75		(65	)		(2,366	)		75
Less: Net income (loss) attributable to noncontrolling interests		43		41			67			43
Net Income (Loss) Attributable to Hess Corporation		32		(106	)		(2,433	)		32
Less: Preferred stock dividends		4		11			—			4
Net Income (Loss) Attributable to Hess Corporation Common Stockholders	$	28	$	(117	)	$	(2,433	)	$	28

Net Income (Loss) Attributable to Hess Corporation Per Common Share:
Basic	$	0.09	$	(0.38	)	$	(8.00	)	$	0.09
Diluted	$	0.09	$	(0.38	)	$	(8.00	)	$	0.09
Weighted Average Number of Common Shares Outstanding:
Basic		297.4		309.5			304.0			297.4
Diluted		299.7		309.5			304.0			299.7
Common Stock Dividends Per Share	$	0.25	$	0.25		$	0.25		$	0.25

	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2019			2018			2020			2019
	(In millions)						(In millions)

Net Income (Loss)	$	75		$	(65	)	$	(2,366	)	$	75

Other Comprehensive Income (Loss):

Derivatives designated as cash flow hedges
Effect of hedge (gains) losses reclassified to income		(15	)		31			(64	)		(15	)
Income taxes on effect of hedge (gains) losses reclassified to income		—			—			—			—
Net effect of hedge (gains) losses reclassified to income		(15	)		31			(64	)		(15	)
Change in fair value of cash flow hedges		(346	)		(22	)		990			(346	)
Income taxes on change in fair value of cash flow hedges		—			—			—			—
Net change in fair value of cash flow hedges		(346	)		(22	)		990			(346	)
Change in derivatives designated as cash flow hedges, after taxes		(361	)		9			926			(361	)

Pension and other postretirement plans
(Increase) reduction in unrecognized actuarial losses		6			125			—			6
Income taxes on actuarial changes in plan liabilities		—			(30	)		—			—
(Increase) reduction in unrecognized actuarial losses, net		6			95			—			6
Amortization of net actuarial losses		11			12			12			11
Income taxes on amortization of net actuarial losses		—			—			—			—
Net effect of amortization of net actuarial losses		11			12			12			11
Change in pension and other postretirement plans, after taxes		17			107			12			17
Other Comprehensive Income (Loss)		(344	)		116			938			(344	)

Comprehensive Income (Loss)		(269	)		51			(1,428	)		(269	)
Less: Comprehensive income (loss) attributable to noncontrolling interests		43			41			67			43
Comprehensive Income (Loss) Attributable to Hess Corporation	$	(312	)	$	10		$	(1,495	)	$	(312	)

							Three Months Ended
	Three Months Ended March 31,						March 31,
	2019			2018			2020			2019
	(In millions)						(In millions)
Cash Flows From Operating Activities
Net income (loss)	$	75		$	(65	)	$	(2,366	)	$	75
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Gains on asset sales, net		—			(7	)
Depreciation, depletion and amortization		498			417			561			498
Impairment								2,126			—
Exploratory dry hole costs								135			—
Exploration lease and other impairment		7			10			32			7
Stock compensation expense		27			13			29			27
Noncash (gains) losses on commodity derivatives, net		29			38			70			29
Provision (benefit) for deferred income taxes and other tax accruals		(1	)		(36	)		(85	)		(1	)
Loss on debt extinguishment		—			27
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(117	)		(11	)		258			(117	)
(Increase) decrease in inventories		(29	)		(7	)		31			(29	)
Increase (decrease) in accounts payable and accrued liabilities		(204	)		(135	)		(263	)		(204	)
Increase (decrease) in taxes payable		8			(1	)		(63	)		8
Changes in other operating assets and liabilities		(55	)		(33	)		(20	)		(55	)
Net cash provided by (used in) operating activities		238			210			445			238

Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P		(521	)		(363	)		(740	)		(521	)
Additions to property, plant and equipment - Midstream		(150	)		(37	)		(78	)		(150	)
Payments for Midstream equity investments		(7	)		(24	)		—			(7	)
Proceeds from asset sales, net of cash sold		—			6
Other, net		(2	)		(4	)		—			(2	)
Net cash provided by (used in) investing activities		(680	)		(422	)		(818	)		(680	)

Cash Flows From Financing Activities
Net borrowings (repayments) of debt with maturities of 90 days or less		199			—			60			199
Debt with maturities of greater than 90 days:
Borrowings								1,000			—
Repayments		(3	)		(434	)		—			(3	)
Payments on finance lease obligations		(23	)		—			(1	)		(23	)
Common stock acquired and retired		(25	)		(371	)		—			(25	)
Cash dividends paid		(88	)		(89	)		(81	)		(88	)
Noncontrolling interests, net		(13	)		(12	)		(63	)		(13	)
Other, net		1			(3	)		(7	)		1
Net cash provided by (used in) financing activities		48			(909	)		908			48

Net Increase (Decrease) in Cash and Cash Equivalents		(394	)		(1,121	)		535			(394	)
Cash and Cash Equivalents at Beginning of Year		2,694			4,847			1,545			2,694
Cash and Cash Equivalents at End of Period	$	2,300		$	3,726		$	2,080		$	2,300

	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				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)																									(In millions)
For the Three Months Ended March 31, 2020																									For the Three Months Ended March 31, 2020
Balance at January 1, 2020																										$	—		$	305	$	5,591		$	3,535		$	(699	)	$	8,732		$	974		$	9,706
Net income (loss)																											—			—		—			(2,433	)		—			(2,433	)		67			(2,366	)
Other comprehensive income (loss)																											—			—		—			—			938			938			—			938
Share-based compensation																											—			2		42			(5	)		—			39			—			39
Dividends on common stock																											—			—		—			(76	)		—			(76	)		—			(76	)
Noncontrolling interests, net																											—			—		—			—			—			—			(63	)		(63	)
Balance at March 31, 2020																										$	—		$	307	$	5,633		$	1,021		$	239		$	7,200		$	978		$	8,178

For the Three Months Ended March 31, 2019																									For the Three Months Ended March 31, 2019
Balance at January 1, 2019	$	1		$	291		$	5,386		$	4,257		$	(306	)	$	9,629		$	1,259		$	10,888			$	1		$	291	$	5,386		$	4,257		$	(306	)	$	9,629		$	1,259		$	10,888
Net income (loss)		—			—			—			32			—			32			43			75				—			—		—			32			—			32			43			75
Other comprehensive income (loss)		—			—			—			—			(344	)		(344	)		—			(344	)			—			—		—			—			(344	)		(344	)		—			(344	)
Preferred stock conversion		(1	)		12			(11	)		—			—			—			—			—				(1	)		12		(11	)		—			—			—			—			—
Share-based compensation activity		—			1			28			—			—			29			—			29
Share-based compensation																											—			1		28			—			—			29			—			29
Dividends on preferred stock		—			—			—			(4	)		—			(4	)		—			(4	)			—			—		—			(4	)		—			(4	)		—			(4	)
Dividends on common stock		—			—			—			(78	)		—			(78	)		—			(78	)			—			—		—			(78	)		—			(78	)		—			(78	)
Sale of water business to Hess Infrastructure Partners		—			—			78			—			—			78			(78	)		—				—			—		78			—			—			78			(78	)		—
Noncontrolling interests, net		—			—			—			—			—			—			(13	)		(13	)			—			—		—			—			—			—			(13	)		(13	)
Balance at March 31, 2019	$	—		$	304		$	5,481		$	4,207		$	(650	)	$	9,342		$	1,211		$	10,553			$	—		$	304	$	5,481		$	4,207		$	(650	)	$	9,342		$	1,211		$	10,553

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)		—			—			—			(106	)		—			(106	)		41			(65	)
Other comprehensive income (loss)		—			—			—			—			116			116			—			116
Share-based compensation activity		—			1			12			—			—			13			—			13
Dividends on preferred stock		—			—			—			(11	)		—			(11	)		—			(11	)
Dividends on common stock		—			—			—			(78	)		—			(78	)		—			(78	)
Common stock acquired and retired		—			(8	)		(135	)		(237	)		—			(380	)		—			(380	)
Noncontrolling interests, net		—			—			—			—			—			—			(12	)		(12	)
Balance at March 31, 2018	$	1		$	308		$	5,701		$	5,166		$	(571	)	$	10,605		$	1,332		$	11,937

The financial statements included in this report reflect all normal and recurring adjustments which, in the opinion of management, are necessary for a fair presentation of our consolidated financial position at March 31, ~~2019~~2020 and December 31, ~~2018,~~2019, the consolidated results of operations for the three months ended March 31, ~~2019~~2020 and ~~2018,~~2019, and consolidated cash flows for the three months ended March 31, ~~2019~~2020 and ~~2018.~~2019. 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, ~~2018.~~2019.

In the first quarter of 2020, we adopted ~~Accounting Standards Codification (ASC) Topic 842,~~ ~~Leases~~. ASC 842 supersedes ASC 840 and requires the recognition of right-of-use assets and lease obligations for all leases with lease terms greater than one year, including leases previously treated as operating leases under ASC 840. We adopted ASC 842 using the modified retrospective method which allows the standard to be applied prospectively. No cumulative effect adjustment was recorded to Retained Earnings at January 1, 2019, and comparative financial statements for periods prior to adoption of ASC 842 were not affected. We elected to apply a number of practical expedients permitted by the standard, including not needing to reassess: (i) whether existing contracts are (or contain) leases, (ii) whether the lease classification for existing leases would differ under ASC 842, (iii) whether initial direct costs incurred for existing leases are capitalizable under ASC 842, and (iv) land easements that were not previously accounted for as leases under ASC 840. We also elected to not recognize a lease liability or right-of-use asset for short-term leases as defined in ASC 842. This standard does not apply to leases acquired for oil and gas producing activities that are accounted for under ASC 932, ~~Extractive Activities – Oil and Gas~~.

~~The adoption of ASC 842 did not have an impact on our~~ ~~Statement of Consolidated Income~~ or ~~Statement of Consolidated Cash Flows. The impact of adoption on our~~ ~~Consolidated Balance Sheet~~ ~~on January 1, 2019, was as follows:~~

~~New Accounting Pronouncements:~~ ~~In June 2016, the FASB issued~~ Accounting Standards Update (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 towith the ~~current~~prior "incurred loss" model. We ~~expect~~calculate expected credit losses for our receivables using the probability of default and the expected loss given default. Historical data, current market conditions, and forecasts of future economic conditions are used to ~~adopt~~determine the probability of default and the expected loss given default. The adoption of this ASU did not have a material impact to our financial statements.

As a result of the significant decline in crude oil prices due to the global economic slowdown from the coronavirus (COVID-19) pandemic, we reviewed our oil and gas properties within the Exploration and Production operating segment for impairment. In the first quarter of 2020, ~~when~~we recognized pre-tax impairment charges to reduce the ~~standard becomes effective.~~carrying value of our oil and gas properties and certain related right-of-use assets at the North Malay Basin in Malaysia by $755 million ($755 million after income taxes), the South Arne Field in Denmark by $670 million ($594 million after income taxes), and in the Gulf of Mexico, the Stampede Field by $410 million ($410 million after income taxes) and the Tubular Bells Field by $270 million ($270 million after income taxes) primarily as a result of a lower long-term crude oil price outlook. The impairment charges were based on estimates of fair value determined by discounting internally developed future net cash flows, a Level 3 fair value measurement. The total of the fair value estimates was approximately $1.05 billion. Significant inputs used in determining the discounted future net cash flows include future prices, projected production volumes using risk adjusted oil and gas reserves, and discount rates. The future pricing assumptions used were based on forward strip crude oil prices as of March 31, 2020 for the remainder of 2020 through 2022, and $50 per barrel for WTI ($55 per barrel for Brent) in 2023 and thereafter to the end of field life. The weighted average crude oil benchmark price based on total projected crude oil volumes for the impaired assets was $48.82 per barrel. A discount rate of 10% was used in each of the fair value measurements which represents the estimated discount rate a market participant would use. We ~~continue~~determined the discount rate by considering the weighted average cost of capital for a group of peer companies.

In the first quarter of 2020, we recognized impairment charges totaling $21 million pre-tax ($20 million after income taxes) related to ~~evaluate this ASU but do not believe it will have a material impact on our Consolidated Financial Statements.~~drilling rig right-of-use assets in the Bakken and surplus materials and supplies.

In the first quarter of 2020, we recognized charges of $53 million ($52 million after income taxes) recorded in Marketing, including purchased oil and gas to reflect crude oil inventories at quarter-end market value.

We determine if an arrangement is an operating lease or a finance lease at inception by evaluating whether the contract conveys the right to control an identified asset during the period of use. Right-of use (ROU) assets represent our right to use an identified asset for the lease term4. Property Plant and ~~lease obligations represent our obligation to make payments as set forth in the lease arrangement. ROU assets and liabilities are recognized in the~~ ~~Consolidated Balance Sheet~~ at the commencement date based on the present value of the minimum lease payments over the lease term. Where the implicit discount rate in a lease is not readily determinable, we use our incremental borrowing rate based on information available at the commencement date for determining the present value of the minimum lease payments. The lease term used in measurement of our lease obligations includes options to extend or terminate the lease when, in our judgment, it is reasonably certain that we will exercise that option. Variable lease payments that depend on an index or a rate are included in the measurement of lease obligations using the index or rate at the commencement date. Variable lease payments that vary because of changes in facts or circumstances after the commencement date of the lease are not included in the minimum lease payments used to measure lease obligations. We have agreements that include financial obligations for lease and nonlease components. For purposes of measuring lease obligations, we have elected not to separate nonlease components from lease components for the following classes of assets: drilling rigs, office space, offshore vessels, and aircraft. We apply a portfolio approach to account for operating lease ROU assets and liabilities for certain vehicles, railcars, field equipment and office equipment leases.Equipment

Finance lease cost is recognized as amortization of the ROU asset and interest expense on the lease liability. Operating lease cost is generally recognized on a straight-line basis. Operating lease costs for drilling rigs used to drill development wells and successful exploration wells are capitalized. Operating lease cost for other ROU assets used in oil and gas producing activities are either capitalized or expensed on a straight-line basis based on the nature of operation for which the ROU asset is utilized.

Leases with an initial term of 12 months or less are not recorded on the balance sheet as permitted under ASC 842. We recognize lease cost for short-term leases on a straight-line basis over the term of the lease. Some of our leases include one or more options to renew. The renewal option is at our sole discretion and is not included in the lease term for measurement of the lease obligation unless we are reasonably certain, at the commencement date of the lease, to renew the lease.

~~Operating and finance leases presented on the~~ ~~Consolidated Balance Sheet~~ ~~at March 31, 2019 were as follows:~~

Lease obligations represent 100% of the present value of future minimum lease payments in the lease arrangement. Where we have contracted directly with a lessor in our role as operator of an unincorporated oil and gas venture, we bill our partners their proportionate share for reimbursements as payments under lease agreements become due pursuant to the terms of our joint operating and other agreements.

~~Operating leases: In the normal course of business, we primarily lease drilling rigs, office space, logistical assets (offshore vessels, aircraft, and shorebases), and equipment.~~

~~Finance leases:~~ In 2018, we entered into a sale and lease-back arrangement for a floating storage and offloading vessel (FSO) to handle produced condensate at North Malay Basin, offshore Peninsular Malaysia (Hess operated – 50%). No gain or loss was recognized from the sale transaction. The remaining lease term utilized in the lease obligation is 14.5 years. At March 31, 2019, the carrying value of the Finance lease asset is $256 million and the carrying value of the Finance lease obligation is $266 million. We have another finance lease obligation of $20 million at March 31, 2019 that will be settled in the second quarter of 2019.

~~The following information relates to the Operating and Finance leases recorded at March 31, 2019:~~

~~The components of lease costs in the first quarter of 2019 were as follows (in millions):~~

The above lease costs represent 100% of the lease payments due for the period, including where we as operator have contracted directly with suppliers. As the payments under lease agreements where we are operator become due, we bill our partners their proportionate share for reimbursement pursuant to the terms of our joint operating agreements. Reimbursements are not reflected in the table above. Certain lease costs above associated with exploration and development activities are included in capital expenditures.

~~Supplemental cash flow information related to leases for the first quarter of 2019 was as follows:~~

On January 31, 2019, the Corporation’s 8.00% Series A Mandatory Convertible Preferred Stock (Preferred Stock) automatically converted into shares of common stock at a rate of 21.822 shares of common stock per share of Preferred Stock. In total, the Preferred Stock was converted into approximately 12.5 million shares of common stock. In connection with the Preferred Stock offering in 2016, the Company entered into capped call transactions to reduce the potential dilution to the Company’s common stock upon conversion of the Preferred Stock, subject to a cap. The Company received approximately 0.9 million shares of common stock upon settlement of the capped call transactions. As a result, the net number of common shares issued by the Company upon conversion of the Preferred Stock was approximately 11.6 million shares.

~~Revenue from contracts with customers on a disaggregated basis was as follows (in $ millions):~~

Exploration and Production

Midstream

Eliminations

Total

United States

Denmark

Libya

Malaysia & JDA

E&P Total

Three Months Ended March 31, 2019

Sales of our net production volumes:

Crude oil revenue

$
682

$
16

$
91

$
21

$
810

$
—

$
—

$
810

Natural gas liquids revenue

68

—

—

—

68

—

—

68

Natural gas revenue

42

3

6

180

231

—

—

231

Sales of purchased oil and gas

426

—

22

—

448

—

—

448

Intercompany revenue

—

—

—

—

—

190

(190
)

—

Total revenues from contracts with customers

1,218

19

119

201

1,557

190

(190
)

1,557

Other operating revenues (a)

15

—

—

—

15

—

—

15

Total sales and other operating revenues

$
1,233

$
19

$
119

$
201

$
1,572

$
190

$
(190
)

$
1,572

Three Months Ended March 31, 2018

Sales of our net production volumes:

Crude oil revenue

$
593

$
33

$
99

$
43

$
768

$
—

$
—

$
768

Natural gas liquids revenue

71

—

—

—

71

—

—

71

Natural gas revenue

39

3

8

128

178

—

—

178

Sales of purchased oil and gas

325

—

24

14

363

—

—

363

Intercompany revenue

—

—

—

—

—

167

(167
)

—

Total revenues from contracts with customers

1,028

36

131

185

1,380

167

(167
)

1,380

Other operating revenues (a)

(34
)

—

—

—

(34
)

—

—

(34
)
Total sales and other operating revenues

$
994

$
36

$
131

$
185

$
1,346

$
167

$
(167
)

$
1,346

There have been no significant changes to contracts with customers or composition thereof during the first quarter of 2019. Generally, we receive payments from customers on a monthly basis, shortly after the physical delivery of the crude oil, NGLs, or natural gas. We did not recognize any credit losses on receivables with customers in the first quarter of 2019 or 2018.

The following table discloses the net changes in capitalized exploratory well costs pending determination of proved reserves during the three months ended March 31, ~~2019~~2020 (in millions):

In the first quarter of 2020, the Corporation expensed previously capitalized well costs of $125 million, primarily related to the northern portion of the Shenzi Field (Hess 28%) in the Gulf of Mexico due to reprioritization of the Corporation’s forward capital program in response to the significant decline in crude oil prices. The table above does not include well costs incurred and expensed during 2020 of $10 million associated with the Oldfield-1 well in the Gulf of Mexico.Capitalized exploratory well costs capitalized for greater than one year following completion of drilling were ~~$309~~$319 million at March 31, ~~2019~~2020 and primarily related ~~to:~~to:

Guyana: Approximately ~~45%~~80% of the capitalized well costs in excess of one year ~~relates~~relate to ~~the Liza-4, Pacora-1, Payara-1, Payara-2, Ranger-1 and Snoek-1~~twelve successful exploration wells where hydrocarbons were encountered on the Stabroek Block ~~offshore Guyana~~ (Hess 30%), ~~where hydrocarbons were encountered.~~offshore Guyana. The operator plans ~~to integrate the Liza-4 discovery into the second phase~~further appraisal drilling for certain fields and is conducting pre-development planning for additional phases of development ~~which is expected to commence production by mid-2022. The operator plans to integrate~~beyond the ~~Pacora-1, Payara-1 and Payara-2 discoveries into the third phase~~two existing sanctioned phases of ~~development, which is expected to commence production as early as 2023.~~ The Snoek discovery is expected to produce into the Liza Phase 1 floating, production storage and offloading (FPSO) vessel under a subsequent phase of development, and the operator is planning further drilling at the Ranger discovery.development.

~~Gulf of Mexico:~~ Approximately 40% of the capitalized well costs in excess of one year relates to the appraisal of the northern portion of the Shenzi Field (Hess 28%) in the Gulf of Mexico, where hydrocarbons were encountered in the fourth quarter of 2015. Following exploration and appraisal drilling activities completed by the operator in prior years on adjacent blocks to the north of our Shenzi blocks, the operator is planning to acquire 3D seismic in 2019 for use in development planning of the northern portion of the Shenzi Field.

~~JDA:~~Joint Development Area (JDA): Approximately 10% of the capitalized well costs in excess of one year relates to the JDA (Hess 50%) 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 has submitted a development plan concept to the regulator to facilitate ongoing commercial negotiations for an extension of the existing gas sales contract to include development of the western part of the Block.

Malaysia: Approximately 5%10% of the capitalized well costs in excess of one year ~~relates~~relate to the North Malay Basin (Hess 50%), offshore Peninsular Malaysia, ~~(Hess 50%),~~ where hydrocarbons were encountered in ~~one~~five successful exploration ~~well drilled in the fourth quarter of 2015. In 2018, we completed four exploration wells~~wells. Subsurface evaluation and ~~are conducting subsurface evaluations~~pre-development studies for ~~consideration in~~ future phases of ~~field development.~~development are ongoing.

~~We consolidate the activities of~~At March 31, 2020 Hess ~~Infrastructure Partners~~Midstream LP ~~(HIP)~~(Hess Midstream), ~~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.

As of March 31, 2019, the Midstream segment is comprised of HIP, which owns the general partner of Hess Midstream Partners LP (HESM). HESM owns an approximate 20% controlling interest in the operating companies that comprise our midstream joint venture while HIP owns the remaining 80%, other than the water services business that is ~~wholly owned~~fully consolidated by ~~HIP as described below. At March 31, 2019, HIP~~Hess Corporation, had liabilities totaling ~~$1,273~~$1,971 million (December 31, ~~2018: $1,105~~2019: $1,941 million) that are on a nonrecourse basis to Hess Corporation, while ~~HIP~~Hess Midstream assets available to settle the obligations of ~~HIP~~Hess Midstream include cash and cash equivalents totaling $6$3 million (December 31, ~~2018: $109~~2019: $3 million) and property, plant and equipment with a carrying value of ~~$2,829~~$3,029 million (December 31, ~~2018: $2,664~~2019: $3,010 million).

In the first quarter of 2020, the Corporation entered into a $1.0 billion three year term loan agreement with JPMorgan Chase Bank N.A. with a maturity date of March ~~1, 2019, HIP completed~~16, 2023. The term loan contains provisions that require us to reduce JPMorgan’s initial funded amount of $1.0 billion. The Corporation is currently in the ~~acquisition~~process of ~~Hess’ water services business for $225 million~~syndicating with other lenders. Borrowings under the term loan bear interest at the applicable interest rates either, at the Corporation’s option, the adjusted LIBOR rate in ~~cash.~~ Aseffect from time to time or the alternate base rate (as described in the term loan agreement) plus the applicable margins specified in the term loan agreement, which generally vary based on the credit rating of the Corporation’s senior, unsecured, non-credit enhanced long-term debt. This loan has been classified as noncurrent in the consolidated balance sheet due to the Corporation’s ability and intent to refinance any amount we are unable to syndicate to other banks on a ~~result~~long-term basis through the Corporation’s existing $3.5 billion revolving credit facility with a maturity date of May 15, 2023. The term loan agreement contains customary representations, warranties and covenants, including a financial covenant limiting the ratio of Total Consolidated Debt to Total Capitalization (as such terms are defined in the term loan agreement) of the Corporation and its consolidated subsidiaries to 65%, and customary events of default. At March 31, 2020, Hess Corporation had borrowings of $1.0 billion under this ~~transaction between entities under common control, we recorded an after-tax gain of $78 million~~term loan agreement and was in ~~additional paid-in-capital~~compliance with ~~an offsetting reduction to noncontrolling interest to reflect the adjustment to GIP’s noncontrolling interest in HIP.~~this financial covenant.

On March 22, 2019, HIP and HESM acquired crude oil and gas gathering assets, and HIP acquired water gathering assets of Summit Midstream Partners LP’s Tioga Gathering System for aggregate cash consideration of approximately $90 million, with the potential for an additional $10 million of contingent payments in future periods subject to certain future performance metrics.

	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2019			2018			2020			2019
	(In millions)						(In millions)
Service cost	$	10		$	14		$	14		$	10
Interest cost (a)		24			23			18			24
Expected return on plan assets (a)		(45	)		(49	)		(45	)		(45	)
Amortization of unrecognized net actuarial losses (a)		11			12			12			11
Curtailment gains (a)		—			(2	)
Pension (income) expense (a)	$	—		$	(2	)	$	(1	)	$	—

~~(a)~~ (a) Net non-service pension cost included in Other, net in the Statement of Consolidated Income in the first quarter of ~~2019~~2020 was income of ~~$10~~$15 million ~~(2018: $16~~(2019: $10 million of income).

To preserve cash in 2020, we are minimizing non-required cash contributions to funded pension plans. In ~~2019,~~2020, we expect to contribute ~~$40~~approximately $2 million to our funded pension plans. Through March 31, ~~2019,~~2020, we have contributed ~~$10~~less than $1 million.

	Exploration and Production												Midstream		Eliminations			Total
	United States		Guyana		Malaysia & JDA		Denmark		Libya		E&P Total
	(In millions)
Three Months Ended March 31, 2020
Sales of our net production volumes:
Crude oil revenue	$	656	$	38	$	2	$	36	$	—	$	732	$	—	$	—		$	732
Natural gas liquids revenue		49		—		—		—		—		49		—		—			49
Natural gas revenue		38		—		139		2		2		181		—		—			181
Sales of purchased oil and gas		324		1		—		—		—		325		—		—			325
Intercompany revenue		—		—		—		—		—		—		291		(291	)		—
Total sales and other operating revenues before other operating revenues		1,067		39		141		38		2		1,287		291		(291	)		1,287
Other operating revenues (a)		55		6		1		5		—		67		—		—			67
Total sales and other operating revenues	$	1,122	$	45	$	142	$	43	$	2	$	1,354	$	291	$	(291	)	$	1,354

Three Months Ended March 31, 2019
Sales of our net production volumes:
Crude oil revenue	$	682	$	—	$	21	$	16	$	91	$	810	$	—	$	—		$	810
Natural gas liquids revenue		68		—		—		—		—		68		—		—			68
Natural gas revenue		42		—		180		3		6		231		—		—			231
Sales of purchased oil and gas		426		—		—		—		22		448		—		—			448
Intercompany revenue		—		—		—		—		—		—		190		(190	)		—
Total sales and other operating revenues before other operating revenues		1,218		—		201		19		119		1,557		190		(190	)		1,557
Other operating revenues (a)		15		—		—		—		—		15		—		—			15
Total sales and other operating revenues	$	1,233	$	—	$	201	$	19	$	119	$	1,572	$	190	$	(190	)	$	1,572

There have been no significant changes to contracts with customers or composition thereof during the ~~first quarter of 2019, HIP and HESM borrowed~~three months ended March 31, 2020. Generally, we receive payments from customers on a ~~total of $199 million from their revolving credit facilities. In~~monthly basis, shortly after the first quarter of 2018, we paid $415 million to redeem $350 million principal amount of 8.125% notes due 2019 with a carrying value of $349 million at December 31, 2017, and to purchase other notes with a carrying value of $38 million at December 31, 2017. Concurrent with the redemptionphysical delivery of the 2019 notes, we terminated interest rate swaps with a notional amount of $350 million. First quarter 2018 results included a pre-tax charge of $27 million for the loss on extinguishment of the redeemed and purchased notes.crude oil, natural gas liquids, or natural gas.

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					Three Months Ended
	March 31,					March 31,
	2019		2018			2020			2019
	(In millions)					(In millions)
Net income (loss) attributable to Hess Corporation Common Stockholders:

Net income (loss)	$	75	$	(65	)	$	(2,366	)	$	75
Less: Net income (loss) attributable to noncontrolling interests		43		41			67			43
Less: Preferred stock dividends		4		11			—			4
Net income (loss) attributable to Hess Corporation Common Stockholders	$	28	$	(117	)	$	(2,433	)	$	28

Weighted average number of common shares outstanding:

Basic		297.4		309.5			304.0			297.4
Effect of dilutive securities
Restricted common stock		1.2		—			—			1.2
Stock options		0.2		—			—			0.2
Performance share units		0.9		—			—			0.9
Diluted		299.7		309.5			304.0			299.7

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

	Three Months Ended				Three Months Ended
	March 31,				March 31,
	2019		2018		2020		2019
Restricted common stock		57,252		2,922,316		2,015,659		57,252
Stock options		3,394,418		5,807,579		4,086,340		3,394,418
Performance share units		65,661		623,088		1,296,356		65,661
Common shares from conversion of preferred stocks		3,930,663		12,584,974
Common shares from conversion of preferred stock						—		3,930,663

During the ~~first quarter of 2019,~~three months ended March 31, 2020, we granted ~~941,082~~1,117,009 shares of restricted stock ~~(2018: 1,081,923)~~(2019: 941,082), ~~234,866~~307,999 performance share units ~~(2018: 278,003)~~(2019: 234,866) and ~~526,968~~686,639 stock options ~~(2018: 683,167)~~(2019: 526,968).

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 ~~three~~3 remaining active cases, filed by Pennsylvania, Rhode Island, and Maryland. In June 2014, the Commonwealth of Pennsylvania filed a lawsuit alleging that we and all major oil companies with operations in Pennsylvania, have damaged the groundwater by introducing thereto gasoline with MTBE. The Pennsylvania suit has been forwarded to the existing MTBE multidistrict litigation pending in the Southern District of New York. 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 the 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~~$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 the 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. Our alleged liability derives from our former ownership and operation of a fuel oil terminal and connected shipbuilding and repair facility adjacent to the Canal. The remedy selected by the EPA 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. The EPA’s original estimate was that this remedy would 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 ~~agreed to comply~~have complied with the ~~EPA~~EPA’s March 2014 Administrative Order and ~~are currently contributing~~contributed funding for the Remedial Design based on an allocation of costs among the parties determined by a third-party expert.

~~On September 28, 2017,~~In January 2020, we received ~~a general notice letter and offer to settle~~an additional Administrative Order from the ~~U.S. Environmental Protection Agency relating~~EPA requiring us and several other parties to ~~Superfund claims~~begin Remedial Action along the uppermost portion of the Canal. We intend to comply with this Administrative Order. The remediation work is anticipated to begin in the fourth quarter of 2020. The costs will continue to be allocated amongst the parties, as they were 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.~~Remedial Design.

We periodically receive notices from the EPA that we are a “potential responsible party” under the Superfund legislation with respect to various waste disposal sites. Under this legislation, all potentially responsible parties may be jointly and severally liable. For any site for which we have received such a notice, the EPA’s claims or assertions of liability against us relating to these sites have not been fully developed, or the EPA’s claims have been settled or a settlement is under consideration, in all cases for amounts that are not material. The ultimate impact of these proceedings, and of any related proceedings by private parties, on our business or accounts cannot be predicted at this time due to the large number of other potentially responsible parties and the speculative nature of clean-up cost estimates but is not expected to be material.

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 lawsuits, claims and proceedings, including the ~~aforementioned proceedings~~matters disclosed above, is not expected to have a material adverse effect on our financial condition, results of operations or cash flows. 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 currently have ~~two~~2 operating segments, Exploration and Production and Midstream. All unallocated costs are reflected under Corporate, Interest and Other. The following table presents operating segment financial data:

Exploration and Production

Midstream

Corporate, Interest and Other

Eliminations

Total

(In millions)

For the Three Months Ended March 31, 2019

Sales and Other Operating Revenues - Third-parties

$
1,572

$
—

$
—

$
—

$
1,572

Intersegment Revenues

—

190

—

(190
)

—

Sales and Other Operating Revenues

$
1,572

$
190

$
—

$
(190
)

$
1,572

Net Income (Loss) attributable to Hess Corporation

$
109

$
37

$
(114
)

$
—

$
32

Depreciation, Depletion and Amortization

464

34

—

—

498

Provision (Benefit) for Income Taxes (a)

95

—

(1
)

—

94

Capital Expenditures

515

127

—

—

642

For the Three Months Ended March 31, 2018

Sales and Other Operating Revenues - Third-parties

$
1,346

$
—

$
—

$
—

$
1,346

Intersegment Revenues

—

167

—

(167
)

—

Sales and Other Operating Revenues

$
1,346

$
167

$
—

$
(167
)

$
1,346

Net Income (Loss) attributable to Hess Corporation

$
(25
)

$
28

$
(109
)

$
—

$
(106
)
Depreciation, Depletion and Amortization

385

31

1

—

417

Provision (Benefit) for Income Taxes (a)

95

9

(31
)

—

73

Capital Expenditures

354

37

—

—

391

~~(a)~~

Commencing January 1, 2019, management changed its measurement of segment earnings to reflect income taxes on a post U.S. tax consolidation and valuation allowance assessment basis. In 2018, the provision for income taxes in the Midstream segment was 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 was presented in the E&P segment. If 2018 segment results were prepared on a basis consistent with 2019, Midstream segment net income attributable to Hess Corporation would have been $37 million and E&P segment net losses would have been $34 million in the first quarter of 2018.

	Exploration and Production			Midstream		Corporate, Interest and Other			Eliminations			Total
	(In millions)
For the Three Months Ended March 31, 2020
Sales and Other Operating Revenues - Third parties	$	1,354		$	—	$	—		$	—		$	1,354
Intersegment Revenues		—			291		—			(291	)		—
Sales and Other Operating Revenues	$	1,354		$	291	$	—		$	(291	)	$	1,354

Net Income (Loss) attributable to Hess Corporation	$	(2,371	)	$	61	$	(123	)	$	—		$	(2,433	)
Depreciation, Depletion and Amortization		521			38		2			—			561
Impairment		2,126			—		—			—			2,126
Provision (Benefit) for Income Taxes		(77	)		2		(4	)		—			(79	)
Capital Expenditures		609			57		—			—			666

For the Three Months Ended March 31, 2019
Sales and Other Operating Revenues - Third parties	$	1,572		$	—	$	—		$	—		$	1,572
Intersegment Revenues		—			190		—			(190	)		—
Sales and Other Operating Revenues	$	1,572		$	190	$	—		$	(190	)	$	1,572

Net Income (Loss) attributable to Hess Corporation	$	109		$	37	$	(114	)	$	—		$	32
Depreciation, Depletion and Amortization		464			34		—			—			498
Provision (Benefit) for Income Taxes		95			—		(1	)		—			94
Capital Expenditures		515			127		—			—			642

	March 31,		December 31,		March 31,		December 31,
	2019		2018		2020		2019
	(In millions)				(In millions)
Exploration and Production	$	16,978	$	16,109	$	14,302	$	16,790
Midstream		3,280		3,285		3,519		3,499
Corporate, Interest and Other		1,458		2,039		2,896		1,493
Total	$	21,716	$	21,433	$	20,717	$	21,782

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 produce 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 business with the intent of reducing exposure to foreign currency fluctuations. At March 31, ~~2019,~~2020, these forward contracts relate to the British ~~Pound.~~Pound and the Danish Krone. Interest rate swaps may be used to convert interest payments on certain long-term debt from fixed to floating rates.

15The notional amounts of outstanding financial risk management derivative contracts were as follows:

~~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~~For calendar year 2020 we 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~~put options with an average monthly floor price of ~~the dates shown below were as follows:~~

~~The gross notional amounts~~$55 per barrel for 130,000 barrels of ~~outstanding financial risk management derivative contracts, excluding commodity contracts, were as follows:~~

oil per day (bopd), and Brent put options with an average monthly floor price of $60 per barrel for 20,000 bopd.

The table below reflects the gross and net fair values of risk management derivative instruments and their respective financial statement caption in the Consolidated Balance Sheet:

	Assets		Liabilities			Assets		Liabilities
	(In millions)					(In millions)
March 31, 2019
March 31, 2020
Derivative Contracts Designated as Hedging Instruments:
Commodity - Other current assets	$	96	$	—
Interest rate - Other liabilities and deferred credits (noncurrent)		—		(1	)
Crude oil derivative contracts						$	1,098	$	—
Interest rate - Other assets (noncurrent)							6		—
Total derivative contracts designated as hedging instruments		96		(1	)		1,104		—
Derivative Contracts Not Designated as Hedging Instruments:
Foreign exchange							—		(2	)
Total derivative contracts not designated as hedging instruments							—		(2	)
Gross fair value of derivative contracts		96		(1	)		1,104		(2	)
Master netting arrangements		—		—			—		—
Net Fair Value of Derivative Contracts	$	96	$	(1	)	$	1,104	$	(2	)

December 31, 2018
December 31, 2019
Derivative Contracts Designated as Hedging Instruments:
Commodity - Other current assets	$	484	$	—
Interest rate - Other liabilities and deferred credits (noncurrent)		—		(2	)
Crude oil derivative contracts						$	125	$	—
Interest rate - Other assets (noncurrent)							1		—
Total derivative contracts designated as hedging instruments		484		(2	)		126		—
Derivative Contracts Not Designated as Hedging Instruments:
Foreign exchange							—		(1	)
Total derivative contracts not designated as hedging instruments							—		(1	)
Gross fair value of derivative contracts		484		(2	)		126		(1	)
Master netting arrangements		—		—			—		—
Net Fair Value of Derivative Contracts	$	484	$	(2	)	$	126	$	(1	)

Crude oil derivatives: Crude oil ~~price~~ hedging contracts increased Sales and other operating revenues by $64 million and $15 million in the first quarter of ~~2019~~2020 and ~~decreased Sales and other operating revenue by $30 million in the first quarter of 2018.~~ 2019, respectively. At March 31, ~~2019,~~2020, pre-tax deferred gains in Accumulated other comprehensive income (loss) related to outstanding crude oil price hedging contracts were $3$831 million, all of which will be reclassified into earnings during the remainder of ~~2019~~2020 as the originally hedged crude oil sales are recognized in earnings.

Interest rate swaps designated as fair value hedges: At March 31, ~~2019~~2020 and December 31, ~~2018,~~2019, we had interest rate swaps with gross notional amounts totaling $100 million, 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~~fixed-rate debt are recorded in Interest expense in the Statement of Consolidated Income. In the first quarter of ~~2019,~~2020, the change in fair value of interest rate swaps was aan increase in the asset of $5 million (2019 Q1: decrease in the liability of $1 ~~million (Q1 2018: increase~~

~~in liability of $3~~ million) with a corresponding adjustment in the carrying value of the hedged ~~fixed~~‑~~rate~~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.~~

Foreign exchange:Foreign exchange gains and losses which are reported inOther, netin Revenues and non-operating income in the Statement of Consolidated Income were $5a loss of $1 million in the first quarter of ~~2019 (2018~~2020 (2019 Q1: ~~$4 million)~~$5 million gain). A component of foreign exchange gain is the result of foreign exchange derivative contracts that are not designated as hedges which amounted to a ~~loss~~net gain of ~~less than $1~~$2 million in the first quarter of ~~2019 (2018~~2020 (2019 Q1: ~~gain~~a net loss of $2less than $1 million).

~~Crude oil derivatives:~~ ~~In the first quarter of 2018, noncash adjustments to de-designated crude oil price hedging contracts decreased Sales and other operating revenues by $8 million.~~

We have other short-term financial instruments, primarily cash equivalents, accounts receivable and accounts payable, for which the carrying value approximated fair value at March 31, ~~2019.~~2020. At March 31, ~~2019,~~2020, total long-term debt, which was ~~substantially~~primarily comprised of fixed-rate debt instruments, had a carrying value of ~~$6,562~~$8,194 million and a fair value of ~~$6,987~~$6,468 million based on Level 2 inputs.

On April 18, 2019 the Corporation terminated its existing revolving credit facility maturing in January 2021 and entered into a new fully undrawn $3.5 billion revolving credit facility with a maturity date of May 15, 2023. This facility can be used for borrowings and letters of credit. Borrowings on the new facility will generally bear interest at 1.30% above the London Interbank Offered Rate (LIBOR), though the interest rate is subject to adjustment if the Corporation’s credit rating changes. The facility is subject to customary representations, warranties and covenants, including a financial covenant limiting the ratio of Total Consolidated Debt to Total Capitalization (as such terms are defined in the credit agreement for the facility) of the Corporation and its consolidated subsidiaries to 0.650 to 1.000, and customary events of default.

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read together with the unaudited consolidated financial statements and accompanying footnotes for the quarter ended March 31, 2020 included under Item 1. Financial Statements of this Form 10-Q and the audited consolidated financial statements and related notes included in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2019. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, but are not limited to, those identified below under the section entitled “Risk Factors” and those discussed in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2019.

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 (NGLs), and natural gas with production operations located primarily in the United States (U.S.), ~~Denmark,~~Guyana, the Malaysia/Thailand Joint Development Area (JDA), Malaysia, and ~~Malaysia.~~Denmark. We conduct exploration activities primarily offshore Guyana, ~~Suriname, Canada and in~~ the U.S. Gulf of ~~Mexico.~~Mexico, and offshore Suriname and Canada. At the Stabroek Block (Hess 30%), offshore Guyana, we have ~~participated in thirteen~~announced sixteen significant discoveries. The Liza Phase 1 development achieved first production in December 2019, with peak production expected to reach up to 120,000 gross bopd. The Liza Phase 2 development was sanctioned in ~~2017~~the second quarter of 2019 and is expected to ~~startup by the first quarter of 2020~~start up in 2022 with production reaching up to ~~120,000~~220,000 gross ~~barrels of oil per day (bopd). The discovered resources to date on the Stabroek Block are expected to underpin the potential for at least five~~ ~~floating production, storage and offloading (FPSO) vessels~~ ~~producing more than 750,000 gross bopd by 2025.~~bopd.

Our Midstream operating segment, which is comprised of Hess Corporation’s 47% consolidated ownership interest in Hess Midstream LP, provides fee-based services, including gathering, compressing and processing natural gas and fractionating ~~natural gas liquids (NGLs);~~NGL; gathering, terminaling, loading and transporting crude oil and ~~NGLs;~~NGL; storing and terminaling propane, and water handling services primarily in the Bakken ~~and Three Forks Shale plays~~shale play in the Williston Basin area of North Dakota.

~~First Quarter Highlights~~Hess Response to Global Pandemic and ~~Outlook~~Market Conditions

~~We project our~~The COVID-19 pandemic continues to have a profound impact on society and industry. The Corporation’s first priority in the midst of the COVID-19 pandemic has been the health and safety of the Hess workforce and local communities. A multidisciplinary Hess emergency response team has been overseeing plans and precautions to reduce the risks of COVID-19 in the work environment while maintaining business continuity based on the most current recommendations by government and public health agencies. The Corporation has implemented a variety of health and safety measures including enhanced cleaning procedures and modified work practices such as travel restrictions, health screenings, reduced personnel at offshore platforms and onshore work sites wherever this can be done safely, and remote working arrangements for office workers.

In addition to the global health concerns of COVID-19, the pandemic has severely impacted demand for oil. In response to the resulting sharp decline in oil prices, the Corporation’s focus is on preserving cash and capability, while protecting the long-term value of its assets. Hess entered into a new $1.0 billion three-year term loan agreement and further reduced its E&P capital and exploratory ~~expenditures~~budget for 2020 to $1.9 billion, a 37% reduction from the original budget of $3.0 billion. This reduction will be ~~approximately $2.9 billion~~achieved primarily by shifting from a six-rig program to one rig in ~~2019. Capital investment for our Midstream operations~~the Bakken and deferring discretionary spending across the portfolio including a six to twelve month deferral in the development of the Payara Field and reduced 2020 drilling activity on the Stabroek Block offshore Guyana.

As a result of the unprecedented reduction in demand due to COVID-19, commercial storage in the United States is expected to reach capacity in the second quarter, which is requiring curtailments and shut-ins of production by the industry. To maximize the value of Hess production, the Corporation has chartered three very large crude carriers (VLCCs) to store 2 million barrels each of May, June and July Bakken crude oil production that is expected to be ~~$430 million including assets acquired from Summit Midstream Partners LP. Oil and gas production in 2019 is forecast to be~~sold in the ~~range~~fourth quarter of ~~270,000 to 280,000~~2020.

Slowing economic activity caused by the pandemic has impacted natural gas nominations at the Corporation’s North Malay Basin (NMB) and JDA assets in Southeast Asia. Production in the first quarter for NMB and JDA was 58,000 barrels of oil equivalent per day (boepd) ~~excluding Libya.~~compared to 68,000 boepd in the first quarter of 2019. Nominations have been reduced due to the decline in business activity and production from NMB and JDA is forecast to be approximately 35,000 boepd in the second quarter and approximately 50,000 boepd for the full year 2020. In Guyana, the operator has temporarily idled two of the four drilling rigs on the Stabroek Block due to pandemic-related travel restrictions. The Liza Destiny floating production, offloading, and storage vessel (FPSO) is expected to reach its full capacity of 120,000 gross bopd, in June, with April gross production of approximately 75,000 bopd. Despite pandemic-related delays, the Liza Phase 2 development remains on schedule to start production in 2022.

In the first quarter of 2020, we incurred a net loss of $2,433 million, compared with net income of $32 million in the first quarter of 2019. Excluding items affecting comparability of earnings between periods detailed on page 22, we incurred an adjusted net loss of $182 million in the first quarter of 2020. The decline in adjusted first quarter 2020 results, compared with the prior-year quarter, primarily reflects lower realized selling prices from the weak commodity price environment, partially offset by higher production volumes.

With our revised capital and ~~$391 million~~exploratory budget of $1.9 billion, we forecast oil and gas production in 2020, excluding Libya, to be approximately 320,000 boepd, which is down from the ~~prior-year quarter.~~ ~~Excluding~~original guidance range of 330,000 boepd to 335,000 boepd. We have in excess of 80% of our ~~Midstream segment, we ended~~forecasted crude oil production for the ~~first quarter~~remainder of ~~2019~~2020 hedged with ~~approximately $2.3 billion~~$55 WTI put options for 130,000 bopd and $60 Brent put options for 20,000 bopd. We also have no near-term debt maturities aside from the new term loan in ~~cash and cash equivalents. Based~~March 2023.

In 2020, based on current forward strip crude oil prices, ~~for 2019,~~ we expect cash flow from operating activities, ~~and~~including settlements from crude oil put option contracts, cash and cash equivalents existing at March 31, ~~2019~~2020 of $2.1 billion, and our available committed revolving credit facility will be sufficient to fund our capital investment program and dividends. Due to the weak commodity price environment, we may take any of the following steps, or a combination thereof, to improve our liquidity and financial position: further reduce the planned capital program and other cash outlays, including dividends, ~~through the end of 2019.~~issue debt or equity securities, and pursue asset sales.

~~On January 31, 2019, the 8.00% Series A Mandatory Convertible Preferred Stock automatically converted into shares of common stock. See~~ ~~Note 3, Preferred Stock Conversion~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~.

In the first quarter of ~~2019, we~~2020, E&P had a net loss of $2,371 million, compared with net income of ~~$32 million, compared to a net loss of $106~~$109 million in the first quarter of 2018. Excluding items affecting comparability of earnings between periods on pages 26 to 27, the adjusted net loss for the first quarter of 2018 was $72 million. The improved first quarter 2019 results, compared to the adjusted results in the prior year quarter, primarily reflect higher production volumes, partially offset by lower realized crude oil selling prices and higher depreciation, depletion and amortization expense.

~~In the first quarter of 2019, E&P had net~~ ~~income of $109 million, compared with a net loss of $25 million in the first quarter of 2018.~~2019. Excluding items affecting comparability of earnings between periods, the adjusted net ~~income~~loss for the first quarter of ~~2018~~2020 was ~~$12~~$120 million. Total net production, excluding Libya, averaged ~~278,000~~ 344,000 boepd in the first quarter of ~~2019,~~2020, compared ~~to 233,000~~with 278,000 boepd in the first quarter of ~~2018 which included 13,000 boepd from a divested asset.~~2019. The average realized crude oil selling price, including hedging, was ~~$55.91~~$45.94 per barrel, down from ~~$59.32~~$55.91 per barrel in the first quarter of ~~2018.~~2019. The average realized ~~natural gas liquids~~NGLs selling price in the first quarter of ~~2019~~2020 was ~~$18.46~~$9.32 per barrel, down from ~~$21.11~~$18.46 per barrel in the ~~prior year~~prior-year quarter, while the average realized natural gas selling price was ~~$4.43~~$3.16 per thousand cubic feet (mcf), updown from ~~$3.86~~$4.43 per mcf in the first quarter of ~~2018.~~

~~The Tilapia, Haimara and Yellowtail discoveries can be summarized as follows:~~

The Noble Tom Madden and Stena Carron drillships will next drill the Hammerhead-2 and Hammerhead-3 wells. Drilling plans for 2019 also include a second well at Ranger and three additional exploration wells, the locations of which are being finalized.

~~Liza Phase 1~~: Phase 1 of the Liza development is expected to begin producing up to 120,000 gross bopd by the first quarter of 2020. Drilling of Phase 1 development wells by the Noble Bob Douglas drillship is proceeding and installation of subsea infrastructure is well advanced, with installation of subsea umbilicals, risers, and flowlines planned for the second quarter. Installation of topside modules on the Liza Destiny FPSO is now complete, and commissioning activities are underway. The vessel is expected to arrive offshore Guyana in the third quarter of 2019.

~~Liza Phase 2~~: Phase 2 of the Liza Field development, which will ~~use a second FPSO,~~utilize the Liza Unity ~~will have the~~FPSO with an expected capacity ~~to produce~~of up to 220,000 gross bopd, ~~and is expected~~remains on target to ~~be producing by mid-2022. Six drill centers are planned with a total of 30 wells, including 15 production wells, 9 water injection wells and 6 gas injection wells.~~achieve first oil in 2022. A ~~final investment decision is expected soon.~~

~~Payara: The operator expects a~~ third development, Payara, with expected production capacity of up to ~~be sanctioned late~~220,000 gross bopd, is planned. Pending government approval to proceed, some 2020 activities at Payara are now being deferred, creating a potential delay in ~~2019 with~~ first production ~~expected~~of six to twelve months beyond the initial start-up target in 2023. ~~The Payara development~~

As previously announced a 16th discovery was made in the first quarter at the Uaru-1 well, which encountered approximately 94 feet of high-quality oil-bearing sandstone reservoir and is ~~expected to have~~located approximately 10 miles northeast of the ~~capacity to produce between 180,000 and 220,000 bopd from a third FPSO.~~Liza Field.

	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2019			2018			2020			2019
	(In millions, except per share amounts)						(In millions, except per share amounts)
Net Income (Loss) Attributable to Hess Corporation:
Exploration and Production	$	109		$	(25	)	$	(2,371	)	$	109
Midstream		37			28			61			37
Corporate, Interest and Other		(114	)		(109	)		(123	)		(114	)
Total	$	32		$	(106	)	$	(2,433	)	$	32

Net Income (Loss) Attributable to Hess Corporation Per Common Share:
Basic (a)	$	0.09		$	(0.38	)
Diluted (b)	$	0.09		$	(0.38	)
Net Income (Loss) Attributable to Hess Corporation Per Common Share - Diluted (a)							$	(8.00	)	$	0.09

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					Three Months Ended
	March 31,					March 31,
	2019		2018			2020			2019
	(In millions)					(In millions)
Items Affecting Comparability of Earnings Between Periods, After-Tax:
Exploration and Production	$	—	$	(37	)	$	(2,251	)	$	—
Midstream		—		—			—			—
Corporate, Interest and Other		—		3			—			—
Total	$	—	$	(34	)	$	(2,251	)	$	—

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

	Three Months Ended					Three Months Ended
	March 31,					March 31,
	2019		2018			2020			2019
	(In millions)					(In millions)
Adjusted Net Income (Loss) Attributable to Hess Corporation:
Net income (loss) attributable to Hess Corporation	$	32	$	(106	)	$	(2,433	)	$	32
Less: Total items affecting comparability of earnings between periods, after-tax		—		(34	)		(2,251	)		—
Adjusted Net Income (Loss) Attributable to Hess Corporation	$	32	$	(72	)	$	(182	)	$	32

The following table reconciles reported net cash provided by (used in) operating activities and cash provided by (used in) operating activities before ~~working capital changes:~~changes in operating assets and liabilities:

Adjusted net income (loss) attributable to Hess Corporation 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.~~periods, which are summarized on page 22. 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.

~~Cash~~Net cash provided by (used in) operating activities before ~~working capital~~ changes in operating assets and liabilities presented in this report is a non-GAAP ~~liquidity~~ measure, which we define as reported net cash provided by (used in) operating activities excluding changes in operating assets and liabilities. Management uses net cash provided by (used in) operating activities before ~~working capital~~ changes in operating assets and liabilities to evaluate the ~~Company’s underlying cash-generation performance~~Corporation’s ability to internally fund capital expenditures, pay dividends and service debt and believes that investors’ understanding of our ~~cash-generation~~ ability to generate cash to fund these items is enhanced by disclosing this measure, which excludes working capital and other movements that may distort assessment of ~~business liquidity~~our performance ~~over time.~~between periods.

These measures are not, and should not be viewed as, substitutes for U.S. GAAP net income (loss) and net cash provided by (used in) operating activities.

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.

Excluding the E&P ~~Items~~items affecting comparability of earnings between periods detailed on page ~~26,~~22, the changes in E&P ~~earnings~~results are primarily attributable to changes in selling prices, production and sales volumes, marketing expenses, cash operating costs, Midstream tariffs, depreciation, depletion and amortization (DD&A), exploration expenses and income taxes, as discussed below.

Selling Prices: Lower realized selling prices in the first quarter of ~~2019,~~2020 decreased after-tax results by approximately ~~$10~~$235 million, compared to the same period in ~~2018.~~2019. Average selling prices were as follows:

	Three Months Ended				Three Months Ended
	March 31,				March 31,
	2019		2018		2020		2019
Average Selling Prices (a)
Crude Oil - Per Barrel (Including Hedging)
Crude Oil – Per Barrel (Including Hedging)
United States
Onshore	$	52.16	$	56.40	$	44.05	$	52.16
Offshore		59.30		59.14		49.33		59.30
Total United States		54.76		57.23		45.63		54.76
Guyana						43.26		—
Malaysia and JDA						51.24		59.38
Denmark		67.26		67.37		55.60		67.26
Libya		62.71		66.27		—		62.71
Malaysia and JDA		59.38		67.69
Worldwide		55.91		59.32		45.94		55.91

Crude Oil - Per Barrel (Excluding Hedging)
Crude Oil – Per Barrel (Excluding Hedging)
United States
Onshore	$	50.91	$	59.61	$	40.54	$	50.91
Offshore		58.05		62.31		45.65		58.05
Total United States		53.51		60.43		42.07		53.51
Guyana (b)						36.79		—
Malaysia and JDA						51.24		59.38
Denmark		67.26		67.37		49.14		67.26
Libya		62.71		66.27		—		62.71
Malaysia and JDA		59.38		67.69
Worldwide		54.84		61.82		42.08		54.84

Natural Gas Liquids - Per Barrel
Natural Gas Liquids – Per Barrel
United States
Onshore	$	18.69	$	20.78	$	9.31	$	18.69
Offshore		17.21		24.28		9.39		17.21
Worldwide		18.46		21.11		9.32		18.46

Natural Gas - Per Mcf
Natural Gas – Per Mcf
United States
Onshore	$	2.46	$	2.47	$	1.28	$	2.46
Offshore		2.54		2.08		1.32		2.54
Total United States		2.50		2.38		1.30		2.50
Malaysia and JDA						4.71		5.28
Denmark		4.02		3.44		3.73		4.02
Libya		5.14		6.93		4.89		5.14
Malaysia and JDA		5.28		4.54
Worldwide		4.43		3.86		3.16		4.43

Crude oil ~~price hedge contracts increased Sales~~hedging activities were a net gain of $64 million before and ~~other operating revenues by $15 million~~after income taxes in the first quarter of ~~2019, compared to~~2020, and a ~~decrease~~net gain of ~~$38~~$15 million before and after income taxes in the first quarter of ~~2018. As of March 31, 2019,~~2019. For calendar year 2020, we have ~~crude oil~~WTI put options with an average monthly floor price of $55 per barrel for ~~calendar year 2019 that establish a WTI~~130,000 bopd, and Brent put options with an average monthly floor price of $60 per barrel for 20,000 bopd. At March 31, 2020, the fair value of the put option contracts was $1,098 million. Sales volumes will be underlifted by approximately 4 million barrels of oil in the second quarter and 2 million barrels of oil in the third quarter as a result of using the VLCCs. While we will receive cash for settlement gains as the $55 WTI put option contracts mature, the net realized gain on ~~95,000 bopd.~~contracts associated with the 6 million barrels of underlifted oil, comprised of the cash settlement less the associated amortization of premiums paid, will be deferred until the volumes stored in the VLCCs are sold. We now expect noncash put option premium amortization, which will be reflected in realized selling prices, to reduce our second quarter results by approximately $50 million and reduce our full year 2020 results by approximately $280 million, which is unchanged from our previous full-year guidance.

	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2019			2018			2020			2019
	(In thousands)						(In thousands)
Crude Oil - Barrels
Crude Oil – Barrels
United States
North Dakota (a)		86			73			114			86
Offshore		49			31			48			49
Total United States		135			104			162			135
Guyana								15			—
Malaysia and JDA								4			4
Denmark		6			6			6			6
Libya		19			20			4			19
Malaysia and JDA		4			4
Total		164			134			191			164

Natural Gas Liquids - Barrels
Natural Gas Liquids – Barrels
United States
North Dakota (a)		34			30			49			34
Offshore		6			4			7			6
Other (b)		—			3
Total United States		40			37			56			40

Natural Gas - Mcf
Natural Gas – Mcf
United States
North Dakota (a)		79			73			162			79
Offshore		92			37			113			92
Other (b)		—			58
Total United States		171			168			275			171
Malaysia and JDA								325			381
Denmark		7			10			6			7
Libya		13			13			5			13
Malaysia and JDA		381			313
Total		572			504			611			572

Barrels of Oil Equivalent (c)		299			255
Barrels of Oil Equivalent (b)								349			299

Crude oil and natural gas liquids as a share of total production		68	%		67	%		71	%		68	%

We forecast net production, excluding Libya, to be in the range of 310,000 boepd to 315,000 boepd for the second quarter and approximately 320,000 boepd for the full year of ~~2019 to average between 270,000 boepd and 280,000 boepd excluding Libya.~~2020.

United States:North Dakota net oil production was higher in the first quarter of ~~2019,~~2020, compared to the ~~first~~year-ago quarter, ~~of 2018,~~ primarily due to ~~ongoing~~increased drilling activity and improved w~~ell performance at the Bakken. Offshore~~well performance. North Dakota net natural gas and NGLs production was higher in the first quarter of ~~2019,~~2020, compared to the ~~corresponding period in 2018, primarily~~year-ago quarter, also due to ~~higher production from~~ the ~~Conger, Penn State and Llano fields that were impacted by~~increased drilling activity, as well as additional natural gas captured with the ~~shutdown~~start-up of the ~~third-party operated Enchilada platform~~Little Missouri 4 natural gas processing plant in ~~the year-ago quarter.~~

~~International:~~ ~~Net~~July 2019 and additional NGLs received under percentage of proceeds contracts resulting from lower NGLs commodity pricing. Total offshore net production ~~was higher from the North Malay Basin~~ in the first quarter of ~~2019 compared~~2020 was comparable to the year-ago ~~quarter, reflecting higher buyer~~ ~~nominations in 2019 and downtime from planned maintenance of condensate export equipment in the first quarter of 2018.~~quarter.

International: Net production at Guyana was higher in the first quarter of 2020, compared to the year-ago quarter, due to commencement of production from the Liza Phase 1 development in December 2019. Net production at Libya was lower due to production cessation in February 2020 following the declaration of force majeure by the Libyan National Oil Corporation caused by civil unrest. Net production was lower at Malaysia and JDA primarily due to lower nominations on reduced gas demand from COVID-19 restrictions.

Sales Volumes:The impact of higher sales volumes improved after-tax results by approximately ~~$190~~$185 million in the first quarter of ~~2019,~~2020, compared to the first quarter of ~~2018.~~ 2019. Worldwide sales volumes from Hess net production, which excludes sales volumes of crude oil, ~~natural gas liquids~~NGLs and natural gas purchased from ~~third-parties,~~third parties, were as follows:

Marketing, including purchased oil and gas:Marketing expense is mainly comprised of costs to purchase crude oil, ~~natural gas liquids~~NGL and natural gas from our partners in Hess operated wells or other ~~third-parties,~~third parties, primarily in the U.S., and transportation and other distribution costs for U.S. marketing activities. ~~The increase~~Marketing expense was lower in the first quarter of ~~2019,~~2020, compared towith the ~~same~~corresponding period in ~~2018,~~2019, primarily ~~reflects the purchase of higher volumes, partially offset by the impact of~~due to lower benchmark crude oil prices on ~~the cost of~~ purchased ~~volumes.~~volumes partially offset by higher purchased volumes and a $53 million pre-tax charge for crude oil inventory valuation.

Cash Operating Costs: ~~Excluding items affecting comparability of earnings, cash~~Cash operating costs ~~consisting~~consist of operating costs and expenses, production and severance taxes and E&P general and administrative ~~expenses, were lower~~expenses. Cash operating costs increased on an absolute basis and decreased on a per barrel basis in the first quarter of 2020, compared with the corresponding period in 2019, due to a higher proportion of lower-cost production from the Bakken.

Midstream Tariffs Expense: Tariffs expense increased from 2019, primarily due to ~~lower workover expenses. Cash operating costs on a per-unit basis were also lower, reflecting~~higher throughput volumes in 2020. We estimate Midstream tariffs expense to be in the ~~impact~~range of ~~increased low-cost production from~~$215 million to $230 million in the ~~Gulf~~second quarter and in the range of ~~Mexico and~~$905 million to $930 million for the ~~North Malay Basin.~~full year 2020.

~~Depreciation, Depletion and Amortization:~~ ~~Depreciation, depletion and amortization (DD&A)~~DD&A: DD&A expenses were higher in the first quarter of ~~2019~~2020 on an absolute ~~and~~basis, compared with the corresponding period in 2019, reflecting higher production volumes. DD&A expense on a per-unit basis was lower in the first quarter of 2020, compared towith the ~~same~~corresponding period in ~~2018,~~2019, primarily due to ~~higher production volumes in~~ the ~~Gulf~~year-over-year mix of ~~Mexico, the Bakken and~~ ~~North Malay Basin.~~production.

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

	Actual				Forecast range (a)		Actual				Forecast range (a)
	Three Months Ended				Three Months Ended	Twelve Months Ended	Three Months Ended				Three Months Ended	Twelve Months Ended
	March 31,				June 30,	December 31,	March 31,				June 30,	December 31,
	2019		2018		2019	2019	2020		2019		2020	2020
Cash operating costs (b)	$	11.00	$	13.46	$13.00 — $14.00	$13.00 — $14.00	$	9.70	$	11.00	$10.00 — $10.50	$10.00 — $10.50
DD&A (c)		17.25		16.77	18.00 — 19.00	18.00 — 19.00		16.44		17.25	14.00 — 15.00	15.00 — 16.00
Total Production Unit Costs	$	28.25	$	30.23	$31.00 — $33.00	$31.00 — $33.00	$	26.14	$	28.25	$24.00 — $25.50	$25.00 — $26.50

	Three Months Ended				Three Months Ended
	March 31,				March 31,
	2019		2018		2020		2019
	(In millions)				(In millions)
Exploration lease and other impairment	$	7	$	10
Exploratory dry hole costs (a)					$	135	$	—
Exploration lease and other impairment (b)						32		7
Geological and geophysical expense and exploration overhead		27		30		22		27
Total Exploration Expense	$	34	$	40	$	189	$	34

Exploration expenses, excluding dry hole expense, are estimated to be in the range of ~~$45~~$35 million to ~~$55~~$40 million in the second quarter of ~~2019~~2020 and ~~$200~~$145 million to ~~$220~~$155 million for the full year of ~~2019.~~

Income Taxes: ~~Income~~ The decline in income tax expense ~~is comprised primarily of taxes in Libya~~ in the first quarter of ~~2019 and 2018. Excluding items affecting comparability of earnings between periods and Libyan operations, the effective income tax rate for E&P operations~~ ~~in the first quarter of 2019~~ ~~was an expense of 2%,~~2020, compared to the year-ago quarter, is primarily due to lower pre-tax income in Libya as a ~~small benefit~~result of the declaration of force majeure in ~~the first quarter of 2018.~~January 2020. Excluding items affecting comparability of earnings between periods and Libyan operations, ~~the~~ E&P ~~effective~~ income tax ~~rate~~expense was $9 million, compared with an expense of $2 million in the first quarter of 2019. Excluding items affecting comparability of earnings between periods and Libyan operations, E&P income tax expense is expected to be an expense in the range of 5%$5 million to ~~9% in~~$10 million for the second quarter of ~~2019,~~2020 and ~~an expense of 0%~~$20 million to 4%$30 million for the full year of ~~2019.~~2020.

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

Impairment:In the first quarter of ~~2018,~~2020, we recorded noncash impairment charges totaling $2.1 billion ($2.0 billion after income taxes) related to our oil and gas properties at North Malay Basin in Malaysia, the South Arne Field in Denmark, and the Stampede Field and the Tubular Bells Field in the Gulf of Mexico, primarily as a ~~net after-tax severance~~result of a lower long-term crude oil price outlook. Other charges totaling $21 million pre-tax ($20 million after income taxes) related to drilling rig right-of-use assets in the Bakken and surplus materials and supplies. See Note 2, Impairment in the Notes to Consolidated Financial Statements.

Dry hole, lease impairment and other exploration expenses: In the first quarter of 2020, we incurred pre-tax charges totaling $152 million ($150 million after income taxes), primarily related to the write-off of previously capitalized exploratory wells in the Gulf of Mexico as detailed in Note 4, Property, plant and equipment in the Notes to Consolidated Financial Statements, and to impair certain exploration leasehold costs.

Crude oil inventories write-down: In the first quarter of 2020, we incurred a pre-tax charge of ~~$37~~$53 million ~~related~~($52 million after income taxes) to ~~a cost reduction program. The pre-tax amounts~~reduce crude oil inventories to their net realizable value. These charges are ~~reported~~included in ~~Operating costs~~Marketing, including purchased oil and ~~expenses~~ ~~($19 million),~~ ~~Exploration expenses, including dry holes and lease impairment~~ ~~($3 million) and~~ ~~General and administrative expenses~~ ~~($15 million),~~gas in the Statement of Consolidated Income. See Note 3, Inventories in the Notes to Consolidated Financial Statements.

~~Total~~Sales and other operating revenues ~~and non-operating income~~ for the first quarter of ~~2019~~2020 increased, compared to the first quarter of ~~2018,~~2019, primarily due to higher throughput volumes and ~~tariff rates, and~~ increased rail transportation ~~and water trucking~~ revenues associated with ~~third party charges.~~third-party services. Operating costs and expenses for the first quarter of ~~2019~~2020 increased, compared to the first quarter of ~~2018,~~2019, primarily due to higher maintenance activity, and increased ~~third party~~third-party rail transportation ~~and water trucking~~ charges.

~~Net~~The increase in interest expense from 2019 reflects higher borrowings by the Midstream business.

Excluding items affecting comparability of earnings, net income attributable to Hess Corporation from the Midstreamsegment is estimated to be ~~approximately~~ in the range of $40 million to $35 50million in the second quarter of ~~2019~~2020 and in the range of ~~$170~~ $185 million to ~~$180~~$195 million for the full year of ~~2019.~~2020.

	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2019			2018			2020			2019
	(In millions)						(In millions)
Corporate and other expenses (excluding items affecting comparability)	$	32		$	25		$	39		$	32
Interest expense		90			92			88			90
Less: Capitalized interest		(7	)		(4	)		—			(7	)
Interest expense, net		83			88			88			83
Corporate, Interest and Other expenses before income taxes		115			113			127			115
Provision (benefit) for income taxes		(1	)		(1	)		(4	)		(1	)
Net Corporate, Interest and Other expenses after income taxes		114			112			123			114
Items affecting comparability of earnings between periods, after-tax		—			(3	)		—			—
Total Corporate, Interest and Other Expenses After Income Taxes	$	114		$	109		$	123		$	114

Corporate and other expenses ~~excluding items affecting comparability,~~ were higher in the first quarter of ~~2019,~~2020, primarily due to a charge of $7 million for legal costs related to former downstream businesses. Interest expense, net was higher in the first quarter of 2020, compared to the first quarter of ~~2018, primarily~~2019, due to ~~lower~~the cessation of capitalized interest ~~income. Interest expense, net was lower~~at the Liza Field, offshore Guyana, upon commencement of production in ~~the first quarter of 2019, compared to the first quarter of 2018, primarily due to lower average borrowings and higher capitalized interest.~~ December 2019.

Second quarter ~~2019~~2020 corporate expenses are expected to be in the range of $25 million to $30 million, and interest expense is expected to be in the range of ~~$80~~$95 million to ~~$85~~$100 million. We estimate corporate expenses for full year ~~2019~~2020 to be in the range of ~~$105~~$115 million to ~~$115~~$125 million, and interest expense to be in the range of ~~$315 to $325 million.~~

~~Items Affecting Comparability of Earnings Between Periods:~~ In the first quarter of 2018, we incurred pre-tax charges of $27 million ($27 million after income taxes) relating to the premium paid for the early retirement of debt. In addition, as required under accounting standards’ intraperiod allocation rules, we recognized a noncash income tax benefit of $30$375 million to ~~offset a noncash income tax expense recognized in other comprehensive income, resulting from a reduction in our pension liabilities.~~$385 million.

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~~NGLs 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, crude oil storage capacity, political risk, environmental risk and catastrophic ~~risk.~~risk, including risks associated with COVID-19. For a more comprehensive description of the risks that may affect our business, see the section entitled Item 1A. Risk Factors in this Quarterly Report on Form 10-Q and in Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, ~~2018.~~2019.

Proved reserves are calculated using the average price during the twelve month period before December 31 determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices are defined by contractual agreements, excluding escalations based on future conditions. Crude oil prices used in the determination of proved reserves at December 31, 2019 were $55.73 per barrel for WTI and $62.54 per barrel for Brent, which are significantly higher than crude oil prices at March 31, 2020 (WTI - $20.48 per barrel; Brent - $17.68 per barrel). If crude oil prices for the rest of 2020 remain significantly below prices used for proved reserves at December 31, 2019, proved reserves at December 31, 2020 could be significantly lower than proved reserves at December 31, 2019. It is difficult to estimate the magnitude of any net negative change in proved reserves that may result from lower crude oil prices due to a number of factors that are currently unknown, including 2020 crude oil prices, any revisions in proved reserves that may occur based on 2020 reservoir performance, the levels to which industry costs will decline in response to lower prices, and management’s plans as of December 31, 2020 for developing proved undeveloped reserves. Any changes in proved reserves will impact depreciation, depletion and amortization expense and the Standardized Measure of Discounted Future Net Cash Flows.

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

	March 31,			December 31,			March 31,			December 31,
	2019			2018			2020			2019
	(In millions, except ratio)						(In millions, except ratio)
Cash and cash equivalents (a)	$	2,300		$	2,694		$	2,080		$	1,545
Current maturities of long-term debt		12			67			3			—
Total debt (b)		6,562			6,672			8,194			7,142
Total equity		10,553			10,888			8,178			9,706
Debt to capitalization ratio (c)		39.4	%		38.0	%
Debt to capitalization ratio as defined under debt covenants (c)								42.0	%		39.6	%

							Three Months Ended
	Three Months Ended, March 31,						March 31,
	2019			2018			2020			2019
	(In millions)						(In millions)
Net cash provided by (used in):
Operating activities	$	238		$	210		$	445		$	238
Investing activities		(680	)		(422	)		(818	)		(680	)
Financing activities		48			(909	)		908			48
Net Increase (Decrease) in Cash and Cash Equivalents	$	(394	)	$	(1,121	)	$	535		$	(394	)

Operating activities:Net cash provided by operating activities was ~~$238~~$445 million in the first quarter of ~~2019,~~2020, compared to ~~$210~~$238million in the first quarter of ~~2018. The increase in 2019 operating cash flows primarily reflects higher production volumes.~~2019. Changes in ~~working capital~~operating assets and liabilities was a use of cash of $57 million in the first quarter of 2020, and a use of cash of $397 million in the first quarter of 2019, ~~and a use of cash of $187 million in the first quarter of 2018. Changes in working capital during 2019~~ which included a one-time ~~repayment~~payment of approximately $130 million to our joint venture partner for its share of sale/leaseback proceeds related to our sale of the North Malay Basin floating storage and offloading vessel ~~completed~~that we received in ~~the third quarter of~~ 2018. ~~The remaining working capital items included semi-annual interest payments on debt, an increase in accounts receivable, and a reduction in accounts payable.~~

Investing activities:Additions to property, plant and equipment were up $271 million, compared to the same period in 2018, primarily reflecting increased drilling activity in the Bakken, increased activity at the Liza Phase 1 development and the Midstream operating segment’s acquisition of ~~assets from Summit Midstream Partners LP, partially offset by lower development expenditures in the Gulf of Mexico.~~ ~~The Midstream segment invested $7 million in its 50/50 joint venture with Targa Resources in the first quarter of 2019, compared to $24~~$818 million in the first quarter of ~~2018.~~2020 were up $147 million compared with the corresponding period in 2019. The increase primarily reflects higher activity in the Bakken and Gulf of Mexico and first quarter payments on accrued fourth quarter 2019 capital expenditures. The first quarter of 2019 included Midstream additions of approximately $90 million associated with the Summit acquisition.

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

							Three Months Ended
	Three Months Ended, March 31,						March 31,
	2019			2018			2020			2019
	(In millions)						(In millions)
Additions to property, plant and equipment - E&P:
Capital expenditures incurred - E&P	$	(515	)	$	(354	)	$	(609	)	$	(515	)
Increase (decrease) in related liabilities		(6	)		(9	)		(131	)		(6	)
Additions to property, plant and equipment - E&P	$	(521	)	$	(363	)	$	(740	)	$	(521	)

Additions to property, plant and equipment - Midstream:
Capital expenditures incurred - Midstream	$	(127	)	$	(37	)	$	(57	)	$	(127	)
Increase (decrease) in related liabilities		(23	)		—			(21	)		(23	)
Additions to property, plant and equipment - Midstream	$	(150	)	$	(37	)	$	(78	)	$	(150	)

Financing activities: ~~Debt repayments with maturities of greater than 90 days were $3 million~~Borrowings in the first quarter of ~~2019 and $434 million in the first quarter of 2018, that included~~ ~~the redemption of~~2020 include $1.0 billion related to our ~~8.125% notes due in 2019. HIP and HESM~~new three-year term loan. Hess Midstream borrowed a total of ~~$199~~$60 million from their revolving credit facilities in the first quarter of 2020 and $199 million in the first quarter of 2019. ~~Payments on finance lease obligations, which were reported~~We paid common stock dividends totaling $81 million in ~~debt repayments prior~~the first quarter of 2020, compared to ~~January 1, 2019, were $23~~common stock and preferred dividends of $88 million in the first quarter of 2019. In addition, ~~we paid common and preferred stock dividends totaling $88~~net cash outflows to noncontrolling interests were $63 million in the first quarter of ~~2019, compared to $89~~2020 and $13 million in the first quarter of ~~2018. In the first quarter of 2018, we cash settled the repurchase of $371 million of common stock.~~2019.

~~Excluding our Midstream segment,~~ At March 31, 2020, we ~~ended the first quarter of 2019 with approximately $2.3~~had $2.1 billion in cash and cash equivalents,excluding Midstream, and total liquidity, including available committed credit facilities, of approximately ~~$6.7~~ $5.9 billion. Our fully undrawn $3.5 billion committed revolving credit facility matures in May 2023, and we have no significant near-term debt ~~maturities.~~maturities aside from the new term loan in March 2023. Oil and gas production in 2020, excluding Libya, is forecast to be approximately 320,000 boepd. We have more than 80% of our remaining crude oil production in 2020 hedged with $55 WTI put options for 130,000 bopd and $60 Brent put options for 20,000 bopd.

Net cash provided by operating activities was $445 million in the first quarter of 2020, compared with $238 million in the first quarter of ~~2019, compared to $210 million in the first quarter of 2018.~~2019. Net cash provided by operating activities before ~~working capital~~ changes in operating assets and liabilities was $502 million in the first quarter of 2020 and $635 million in the first quarter of ~~2019 and $397~~2019. Capital expenditures were $666 million in the first quarter of ~~2018. Capital expenditures were~~2020 and $642 million in the first quarter of ~~2019 and $391 million in the first quarter of 2018.~~ ~~Based~~2019. In 2020, based on current forward strip crude oil prices, ~~for 2019,~~ we expect cash flow from operating activities, ~~and~~including settlements from crude oil put option contracts, cash and cash equivalents existing at March 31, ~~2019~~2020, and our available committed revolving credit facility will be sufficient to fund our capital investment program and dividends. Due to the weak commodity price environment, we may take any of the following steps, or a combination thereof, to improve our liquidity and financial position: further reduce the planned capital program and other cash outlays, including dividends, ~~through the end of 2019.~~issue debt or equity securities, and pursue asset sales.

The table below summarizes the capacity, usage, and available capacity for borrowings and letters of credit under committed and uncommitted credit facilities at March 31, ~~2019:~~2020:

						Letters of											Letters of
	Expiration					Credit		Total		Available		Expiration					Credit		Total		Available
	Date	Capacity		Borrowings		Issued		Used		Capacity		Date	Capacity		Borrowings		Issued		Used		Capacity
		(In millions)											(In millions)
Hess Corporation
Revolving credit facility - Hess Corporation	January 2021	$	4,000	$	—	$	—	$	—	$	4,000
Revolving credit facility												May 2023	$	3,500	$	—	$	—	$	—	$	3,500
Committed lines	Various (a)		445		—		54		54		391	Various (a)		345		—		54		54		291
Uncommitted lines	Various (a)		240		—		240		240		—	Various (a)		205		—		205		205		—
Total - Hess Corporation		$	4,685	$	—	$	294	$	294	$	4,391		$	4,050	$	—	$	259	$	259	$	3,791

Midstream
Revolving credit facility - HIP (b)	November 2022	$	600	$	192	$	—	$	192	$	408
Revolving credit facility - Hess Midstream Partners LP (c)	March 2021		300		7		—		7		293
Revolving credit facility (b)												December 2024	$	1,000	$	92	$	—	$	92	$	908
Total - Midstream		$	900	$	199	$	—	$	199	$	701		$	1,000	$	92	$	—	$	92	$	908

~~At March 31, 2019,~~ Hess ~~Corporation had no outstanding borrowings or letters~~Corporation:

In the first quarter of ~~credit under its then existing facility and was in compliance with its financial covenants.~~

~~On April 18, 2019~~2020, the Corporation ~~terminated its existing revolving credit facility maturing in January 2021 and~~ entered into a ~~new fully undrawn~~$1.0 billion three year term loan agreement with JPMorgan Chase Bank N.A. with a maturity date of March 16, 2023. The term loan agreement contains provisions that require us to reduce JPMorgan’s initial funded amount of $1.0 billion. The Corporation is currently in the process of syndicating with other lenders. Borrowings under the term loan bear interest at the applicable interest rates either, at the Corporation’s option, the adjusted LIBOR rate in effect from time to time or the alternate base rate (as described in the term loan agreement) plus the applicable margins specified in the term loan agreement, which generally vary based on the credit rating of the Corporation’s senior, unsecured, non-credit enhanced long-term debt. This loan has been classified as noncurrent in the consolidated balance sheet due to the Corporation’s ability and intent to refinance any amount we are unable to syndicate to other banks on a long-term basis through the Corporation’s existing $3.5 billion revolving credit facility with a maturity date of May 15, 2023. This facility can be used for borrowings and letters of credit. Borrowings on the new facility will generally bear interest at 1.30% above the London Interbank Offered Rate (LIBOR), though the interest rate is subject to adjustment if the Corporation’s credit rating changes. The ~~facility is subject to~~term loan agreement contains customary representations, warranties and covenants, including a financial covenant limiting the ratio of Total Consolidated Debt to Total Capitalization (as such terms are defined in the ~~credit agreement for the facility)~~term loan agreement) of the Corporation and its consolidated subsidiaries to ~~0.650 to 1.000,~~65%, and customary events of default. At March 31, 2020, Hess Corporation had borrowings of $1.0 billion under this term loan agreement and was in compliance with this financial covenant.

At March 31, 2020, Hess Corporation had no outstanding borrowings or letters of credit under its revolving credit facility and was in compliance with its financial covenants.

Two of the three major credit rating agencies that rate our debt have assigned an investment grade rating. In March 2020, Standard and Poor’s Ratings Services affirmed our credit rating at BBB- and revised the outlook to negative (from stable) while Fitch Ratings assigned a BBB- rating to the $1.0 billion term loan, with no change to our BBB- credit rating and stable outlook. In March 2020, Moody’s Investors Service affirmed our credit rating at Ba1 with stable outlook, which is below investment grade.

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

At March 31, ~~2019, HIP~~2020, Hess Midstream Operations LP (formerly Hess Midstream Partners LP, or HESM Opco), a consolidated subsidiary of Hess Midstream LP, had ~~$800 million~~$1.4 billion of senior secured syndicated credit facilities maturing ~~November 2022,~~December 16, 2024, consisting of a ~~$600 million~~$1.0 billion 5-year revolving credit facility and a fully drawn ~~$200~~$400 million 5-year ~~Term Loan~~term loan A facility. The revolving credit facility can be used for borrowings and letters of credit to fund ~~the joint venture’s~~HESM Opco’s operating activities, capital expenditures, distributions and ~~capital expenditures.~~for other general corporate purposes. Borrowings under the 5-year ~~Term Loan~~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~~Pricing levels for the facility fee and interest-rate margins are based on ~~HIP’s leverage~~HESM Opco’s ratio ~~which is calculated as~~of total debt to ~~Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA)~~EBITDA (as defined in the credit facilities). If ~~HIP~~HESM Opco obtains an investment grade credit rating, ~~as defined in~~ the ~~amended credit agreement,~~ pricing levels will be based on ~~the~~HESM Opco’s credit ratings in effect from time to time. The credit facilities contain ~~financial~~ covenants that ~~generally~~ require HESM Opco to maintain a ~~leverage~~ ratio of ~~no more than 5.0~~total debt to ~~1.0~~EBITDA (as defined in the credit facilities) for the prior four fiscal quarters of not greater than 5.00 to 1.00 as of the last day of each fiscal quarter (5.50 to 1.00 during the specified period following certain acquisitions) and, prior to HESM Opco obtaining an ~~interest coverage~~investment grade credit rating, a ratio ~~which is calculated as~~of secured debt to EBITDA ~~to cash interest expense, of no less than 2.25 to 1.0~~ for the prior four fiscal ~~quarters. The amended credit agreement includes a secured leverage ratio test~~quarters of not ~~to exceed 3.75~~greater than 4.00 to 1.00 ~~for so long~~ as of the ~~facilities remain secured. HIP is~~last day of each fiscal quarter. HESM Opco was in compliance with these financial covenants at March 31, 2019. Outstanding borrowings under this credit facility are non-recourse to Hess Corporation. At March 31, 2019, borrowings of $192 million were drawn under HIP’s revolving credit facility, and borrowings of $195 million, excluding deferred issuance costs, were drawn under HIP’s Term Loan A facility.2020. The credit facilities are secured by first-priority perfected liens on substantially all ~~of HIP’s~~the presently owned 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 has a $300 million 4-year senior secured syndicated revolving credit facility that became available for utilization at completion of its initial public offering in April 2017. The credit facility can be used for borrowings and letters of credit to fund operating activities and capital expenditures of HESM and expires March 2021. 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 HESM’s leverage ratio, which is calculated as total debt to EBITDA. If HESM obtains credit ratings, pricing levels will be based on the credit ratings in effect from time to time. HESM 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. HESM is in compliance with these financial covenants at March 31, 2019. The credit facility is secured by first priority perfected liens on substantially all directly ownedafter-acquired assets of HESM Opco and its ~~wholly-owned~~direct and indirect wholly owned material domestic subsidiaries, including equity interests ~~in subsidiaries,~~directly owned by such entities, subject to certain customary exclusions. ~~Outstanding~~At March 31, 2020, borrowings of $92 million were drawn under ~~this~~HESM Opco’s revolving credit facility, and borrowings of $400 million, excluding deferred issuance costs, were drawn under HESM Opco’s term loan A facility. Borrowings under these credit facilities are non-recourse to Hess Corporation. ~~At March 31, 2019, borrowings of $7 million were drawn under this facility.~~

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 ~~13,~~12, Financial Risk Management Activities, in the Notes to Consolidated Financial Statements.

We have outstanding foreign exchange contracts with notional amounts totaling ~~$43~~$65 million at March 31, ~~2019~~2020 that are used to reduce our exposure to fluctuating foreign exchange rates for various currencies. The change in fair value of foreign exchange contracts from a 10% weakening in the U.S. Dollar exchange rate is estimated to be a loss of ~~approximately~~less than $5 million at March 31, ~~2019.~~2020.

At March 31, ~~2019,~~2020, our total long-term debt, which was substantially comprised of fixed-rate instruments, had a carrying value of ~~$6,562~~$8,194 million and a fair value of ~~$6,987~~$6,468 million. A 15% increase or decrease in interest rates would decrease or increase the fair value of debt by approximately ~~$460~~$500 million or ~~$520~~$590 million, respectively. Any changes in interest rates do not impact our cash outflows associated with fixed-rate interest payments or settlement of debt principal, unless a debt instrument is repurchased prior to maturity.

At March 31, ~~2019,~~2020, we have outstanding ~~West Texas Intermediate (WTI)~~WTI and Brent crude oil put option contracts. ~~See~~ ~~Note 13, Financial Risk Management Activities~~ ~~in the~~ ~~Notes to Consolidated Financial Statements~~. As of March 31, ~~2019,~~2020, an assumed 10% increase in the forward WTI and Brent crude oil prices used in determining the fair value of our ~~crude~~ put ~~contracts~~options would reduce the fair value of these ~~derivatives~~derivative instruments by approximately ~~$40~~$115 million, while an assumed 10% decrease in the same ~~WTI~~ crude oil prices would increase the fair value of these derivative instruments by approximately ~~$90~~$125 million.

~~Certain sections in this~~This Quarterly Report on Form 10-Q, including information incorporated by reference herein, ~~contain “forward-looking” statements, as defined under~~contains “forward-looking statements” within the ~~Private~~meaning of Section 27A of the Securities ~~Litigation Reform~~ Act of ~~1995. Generally,~~1933, as amended, and Section 21E of the ~~words~~Securities Exchange Act of 1934, as amended. Words such as “anticipate,” “estimate,” “expect,” “forecast,” “guidance,” “could,” “may,” “should,” “would,” “believe,” “intend,” “project,” “plan,” “predict,” “will,” “target” and similar expressions identify forward-looking statements, which ~~generally~~ are not historical in nature. Our forward-looking statements may include, without limitation: our future financial and operational results; our business strategy; estimates of our crude oil and natural gas reserves and levels of production; benchmark prices of crude oil, natural gas liquids and natural gas and our associated realized price differentials; our projected budget and capital and exploratory expenditures; our plan to syndicate the $1 billion term loan; expected timing and completion of our development projects; and future economic and market conditions in the oil and gas industry.

Forward-looking statements ~~related to our operations and financial conditions~~ are based on our current understanding, assessments, estimates and ~~projections.~~projections of relevant factors and reasonable assumptions about the future. Forward-looking statements are subject to certain known and unknown risks and uncertainties that could cause actual results to differ materially from our historical experience and our current projections or ~~expectations.~~ expectations of future results expressed or implied by these forward-looking statements. The following important factors could cause actual results to differ materially from those in our forward-looking statements:

As and when made, we believe that ~~these~~our forward-looking statements are reasonable. However, given these risks and uncertainties, 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~~occur and actual results may differ materially from those contained in any forward-looking statement we make. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether ~~as a result~~because 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.~~

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.”

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 March 31, ~~2019,~~2020, John B. Hess, Chief Executive Officer, and John P. Rielly, Chief Financial Officer, concluded that these disclosure controls and procedures were effective as of March 31, ~~2019.~~2020.

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 March 31, ~~2019~~2020 that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting. ~~We implemented internal controls to ensure we adequately evaluated our contracts against the accounting and disclosure requirements of ASC 842,~~ ~~Leases~~ ~~to facilitate adoption of the standard on January 1, 2019. There were no significant changes to our internal control over financial reporting due to adoption of the new standard.~~

Information regarding legal proceedings is contained in Note ~~11,~~10, Guarantees and Contingencies in the Notes to Consolidated Financial Statements and is incorporated herein by reference.

Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2019, includes certain risk factors that could materially affect our business, financial condition, or future results. Those risk factors have not materially changed, except as set forth and as supplemented below:

Our business and operations have been and may continue to be adversely affected by the COVID-19 global pandemic or other similar public health developments and the recent reduced demand for oil and natural gas.

The COVID-19 global pandemic and related actions taken by governments and businesses, including voluntary and mandatory quarantines and travel and other restrictions, has resulted in a significant and swift reduction in economic activity. As a result of the COVID-19 pandemic, our operations, and those of our business partners, service companies and suppliers, have experienced and may continue to experience adverse effects, including disruptions, delays or temporary suspensions of operations and supply chains; temporary inaccessibility or closures of facilities; and workforce impacts from illness, school closures and other community response measures. We have implemented a variety of health and safety measures including enhanced cleaning procedures and modified work practices such as travel restrictions, health screenings, reduced personnel at offshore platforms and onshore work sites wherever this can be done safely, and remote working arrangements for office workers. To the extent we or our business partners, service companies or suppliers continue to experience restrictions or other effects, our financial condition, results of operations and future expansion projects may be adversely affected.

The timeline and potential magnitude of the COVID-19 pandemic is currently unknown. In addition to the global health concerns of COVID-19, the pandemic has negatively affected the United States and global economy and severely adversely impacted demand for oil and natural gas. The continuation or amplification of the outbreak of COVID-19 could result in further economic downturn that may affect our operating results in the long-term. In addition, the effects of COVID-19 and concerns regarding its global spread have negatively impacted the domestic and international demand for crude oil and natural gas, which has contributed to price volatility and adversely affected the demand for and marketability of crude oil, natural gas and NGLs, and resulting increased demand for commercial storage which could require further curtailments and shut-ins of production by the industry. In the event one or more of our business partners is adversely affected by COVID-19 or the current market environment, that may impact our costs and ability to conduct business with them. In addition, we may face an increased risk of changes in the regulation related to our business, such as the imposition of limitations on the production of oil and gas by states or other jurisdictions, that may result in additional limits on our products. We also are subject to litigation risk and possible loss contingencies related to COVID-19, including with respect to commercial contracts, employee matters and insurance arrangements. We may face additional asset impairments, decreases in proved reserves, along with other accounting charges as demand for crude oil, natural gas and NGLs decreases. The current environment may make it more difficult to syndicate our term loan and comply with our covenants and other restrictions in agreements governing our debt, and a lack of confidence in our industry on the part of the financial markets may result in a lack of access to capital, any of which could lead to reduced liquidity.

As the potential impact from the COVID-19 pandemic is difficult to predict, the extent to which it may negatively affect our operating results is uncertain. Any impact will depend on future developments and new information that may emerge regarding the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control. To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other risks described in our annual report on Form 10-K for the year ended December 31, 2019.

Our common share repurchase activities for the three months ended March 31, ~~2019,~~2020, were as follows:

Period	Total Number of Shares Purchased (a)		Average Price Paid per Share (b)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs (c) (In millions)		Total Number of Shares Purchased (a)		Average Price Paid per Share (b)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs (c) (In millions)
January		—	$	—		—	$	650		—	$	—		—	$	650
February		—		—		—		650		—		—		—		650
March		32,260		56.62		—		650		35,202		32.34		—		650
Total		32,260	$	56.62		—				35,202	$	32.34		—

On May 6, 2020, the Board of Directors of the Corporation approved and adopted amendments to the Corporation’s By-Laws (as amended, the By-Laws), to help facilitate the conduct of a virtual annual meeting of stockholders in 2020 as a result of the COVID-19 pandemic.

Article III, Section 1 of the By-Laws was amended to clarify that the Corporation’s meetings of stockholders may be held by means of remote communications and to permit appropriate arrangements relevant to such a meeting, including without limitation, arrangements as to format, procedures and notices, in accordance with applicable law.

The foregoing summary description of the amendments to the By-Laws is subject to, and qualified in its entirety by reference to, the full text of the amended By-Laws, filed as Exhibit 3(1) hereto and incorporated herein by reference.

The cover page from the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, has been formatted in Inline XBRL.

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.

Title of each class	Trading Symbol	Name of exchange on which registered
Common Stock	HES	New York Stock Exchange

~~Title of each class~~	~~Trading Symbol~~	~~Name of exchange on which registered~~
~~Common Stock~~	~~HES~~	~~New York Stock Exchange~~

	Operating Leases	Finance Leases
Weighted average remaining lease term	4.7 years	13.5 years
Range of remaining lease terms	0.1 - 9.3 years	0.2 - 14.5 years
Weighted average discount rate	4.3%	7.8%

	Operating Leases		Finance Leases
	(In millions)
Cash paid for amounts included in the measurement of lease obligations:
Operating cash flows	$	106	$	6
Financing cash flows		—		23
Noncash transactions:
Leased assets recognized for new lease obligations incurred	3			—

	March 31, 2019		December 31, 2018
Calendar year program	2019		2019
Instrument type	Puts		Puts
Effective date	Apr. 1, 2019		Jan. 1, 2019
End date	Dec. 31, 2019		Dec. 31, 2019
Crude oil volumes (millions of barrels)		26.1		34.7
Floor price	$	60	$	60

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

	December 31, 2018		Adjustment for Finance Leases			Adjustment for Operating Leases			January 1, 2019
	(In Millions)
Assets
Property, plant and equipment — net	$	16,083	$	(346	)	$	—		$	15,737
Operating lease right-of-use assets — net		—		—			804			804
Finance lease right-of-use assets — net		—		346			—			346
Liabilities
Accrued liabilities		1,560		—			(2	)		1,558
Current maturities of long-term debt		67		(55	)		—			12
Current portion of operating and finance lease obligations		—		55			382			437
Long-term debt		6,605		(254	)		—			6,351
Long-term operating lease obligations		—		—			516			516
Long-term finance lease obligations		—		254			—			254
Other liabilities and deferred credits		575		—			(92	)		483

Operating lease cost	$	103
Finance lease cost:
Amortization of leased assets		13
Interest on lease obligations		6
Short-term lease cost (a)		32
Variable lease cost (b)		19
Sublease income (c)		(3	)
Total lease cost	$	170

Balance at January 1, 2019	$	418
Additions to capitalized exploratory well costs pending the determination of proved reserves		48
Balance at March 31, 2019	$	466

Balance at January 1, 2020	$	584
Additions to capitalized exploratory well costs pending the determination of proved reserves		47
Capitalized exploratory well costs charged to expense		(125	)
Balance at March 31, 2020	$	506

	March 31, 2020		December 31, 2019
	(In millions)
Commodity - crude oil (millions of barrels)		41.3		54.9
Foreign exchange	$	65	$	90
Interest rate swaps	$	100	$	100

	Three Months Ended
	March 31,
	Pre-tax					After-tax
	2020			2019		2020			2019
	(In millions)
Impairment	$	(2,126	)	$	—	$	(2,049	)	$	—
Dry hole, lease impairment and other exploration expenses		(152	)		—		(150	)		—
Crude oil inventories write-down		(53	)		—		(52	)		—
	$	(2,331	)	$	—	$	(2,251	)	$	—

		Exhibits
		~~10(1)~~3(1)**	By-Laws of Hess Corporation (as amended effective May 6, 2020).
		10(1)*	Form of Restricted Stock Award Agreement under the 2017 Long-Term Incentive Plan.
		10(2)**	Form of Stock Option Award Agreement under the 2017 Long-Term Incentive Plan.
		10(3)**	Form of Performance Award Agreement for three-year period ending December 31, ~~2021~~2022 under the 2017 Long-Term Incentive Plan.
		10(4)	~~Credit~~Loan Agreement, dated as of ~~April 18, 2019,~~March 16, 2020, among Hess Corporation, ~~the subsidiary party thereto,~~ the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent incorporated by reference to Exhibit 10(1) of Form 8-K of the registrant, filed on ~~April 23, 2019.~~March 17, 2020.
		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)*	Inline XBRL Instance ~~Document.~~Document- the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
		101(SCH)*	Inline XBRL Taxonomy Extension Schema Document.
		101(CAL)*	Inline XBRL Taxonomy Extension Calculation Linkbase Document.
		101(LAB)*	Inline XBRL ~~Labels~~Taxonomy Extension Label Linkbase Document.
		101(PRE)*	Inline XBRL Taxonomy Extension Presentation Linkbase Document.
		101(DEF)*	Inline XBRL Taxonomy Extension Definition Linkbase Document.

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