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hes-20210630

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

☒

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

For the quarter ended June 30, 2021


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

For the transition period from to

Commission File Number 1-1204

HESS CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

DELAWARE

(State or Other Jurisdiction of Incorporation or Organization)

13-4921002

(I.R.S. Employer Identification Number)

1185 AVENUE OF THE AMERICAS, NEW YORK, NY

(Address of Principal Executive Offices)

10036

(Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:


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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý 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 ý 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.

Large accelerated filer

☒

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

At June 30, 2021, there were 309,672,952 shares of Common Stock outstanding.

HESS CORPORATION

Form 10-Q

TABLE OF CONTENTS


Item No.		Page Number
	PART I - FINANCIAL INFORMATION
1.	Financial Statements (Unaudited)
	Consolidated Balance Sheet at June 30, 202 1 , and December 31, 20 20	2
	Statement of Consolidated Income for the Three and S ix Months Ended June 30, 202 1 , and 20 20	3
	Statement of Consolidated Comprehensive Income for the Three and Six Months Ended June 30, 202 1 , and 20 20	4
	Statement of Consolidated Cash Flows for the Six Months Ended June 30, 202 1 , and 20 20	5
	Statement of Consolidated Equity for the Three and Six Months Ended June 30, 202 1 , and 20 20	6
	Notes to Consolidated Financial Statements (Unaudited)	7
	Note 1 - Basis of Presentation	7
	Note 2 - Inventories	7
	Note 3 - Property, Plant and Equipment	7
	Note 4 - Hess Midstream LP	8
	Note 5 - Accrued Liabilities	8
	Note 6 - Revenue	9
	Note 7 - Impairmen t and Other	10
	Note 8 - Retirement Plans	10
	Note 9 - Weighted Average Common Shares	10
	Note 1 0 - Guarantees and Contingencies	11
	Note 1 1 - Segment Information	13
	Note 1 2 - Financial Risk Management Activities	14
	Note 1 3 - Subsequent Events	16

2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
3.	Quantitative and Qualitative Disclosures about Market Risk	32
4.	Controls and Procedures	32

	PART II - OTHER INFORMATION
1.	Legal Proceedings	33
6.	Exhibits	34
	Signatures	35

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

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEET (UNAUDITED)


	June 30, 2021		December 31, 2020

	(In millions, except share amounts)
Assets
Current Assets:
Cash and cash equivalents	$	2,430	$	1,739
Accounts receivable:
From contracts with customers	856		710
Joint venture and other	146		150

Inventories	241		378
Assets held for sale	228		—
Other current assets	68		104
Total current assets	3,969		3,081
Property, plant and equipment:
Total — at cost	29,942		30,519
Less: Reserves for depreciation, depletion, amortization and lease impairment	16,285		16,404
Property, plant and equipment — net	13,657		14,115
Operating lease right-of-use assets — net	373		426
Finance lease right-of-use assets — net	155		168
Goodwill	360		360
Deferred income taxes	21		59
Other assets	631		612
Total Assets	$	19,166	$	18,821
Liabilities
Current Liabilities:
Accounts payable	$	178	$	200
Accrued liabilities	1,480		1,251
Taxes payable	268		81
Current maturities of long-term debt	511		10
Current portion of operating and finance lease obligations	90		81
Total current liabilities	2,527		1,623
Long-term debt	7,712		8,286
Long-term operating lease obligations	421		478
Long-term finance lease obligations	210		220
Deferred income taxes	318		342
Asset retirement obligations	728		894
Other liabilities and deferred credits	718		643
Total Liabilities	12,634		12,486
Equity
Hess Corporation stockholders’ equity:
Common stock, par value $1.00; Authorized — 600,000,000 shares
Issued — 309,672,952 shares (2020: 306,980,092)	310		307
Capital in excess of par value	5,859		5,684
Retained earnings	155		130
Accumulated other comprehensive income (loss)	(836)		(755)
Total Hess Corporation stockholders’ equity	5,488		5,366
Noncontrolling interests	1,044		969
Total Equity	6,532		6,335
Total Liabilities and Equity	$	19,166	$	18,821

See accompanying Notes to Consolidated Financial Statements.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED INCOME (UNAUDITED)


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020

	(In millions, except per share amounts)
Revenues and Non-Operating Income
Sales and other operating revenues	$	1,579	$	833	$	3,477	$	2,187
Other, net	19		9		40		24
Total revenues and non-operating income	1,598		842		3,517		2,211
Costs and Expenses
Marketing, including purchased oil and gas	322		56		840		434
Operating costs and expenses	315		294		580		597
Production and severance taxes	44		16		81		58
Exploration expenses, including dry holes and lease impairment	48		31		81		220
General and administrative expenses	84		89		178		191
Interest expense	118		119		235		232
Depreciation, depletion and amortization	385		509		781		1,070
Impairment and other	147		—		147		2,126
Total costs and expenses	1,463		1,114		2,923		4,928
Income (Loss) Before Income Taxes	135		(272)		594		(2,717)
Provision (benefit) for income taxes	122		(9)		245		(88)
Net Income (Loss)	13		(263)		349		(2,629)
Less: Net income (loss) attributable to noncontrolling interests	86		57		170		124
Net Income (Loss) Attributable to Hess Corporation	$	(73)	$	(320)	$	179	$	(2,753)

Net Income (Loss) Attributable to Hess Corporation Per Common Share:
Basic	$	(0.24)	$	(1.05)	$	0.58	$	(9.04)
Diluted	$	(0.24)	$	(1.05)	$	0.58	$	(9.04)
Weighted Average Number of Common Shares Outstanding:
Basic	307.5		305.0		306.7		304.5
Diluted	307.5		305.0		308.7		304.5
Common Stock Dividends Per Share	$	0.25	$	0.25	$	0.50	$	0.50

See accompanying Notes to Consolidated Financial Statements.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (UNAUDITED)


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020

	(In millions)
Net Income (Loss)	$	13	$	(263)	$	349	$	(2,629)
Other Comprehensive Income (Loss):
Derivatives designated as cash flow hedges
Effect of hedge (gains) losses reclassified to income	64		(228)		115		(292)
Income taxes on effect of hedge (gains) losses reclassified to income	—		—		—		—
Net effect of hedge (gains) losses reclassified to income	64		(228)		115		(292)
Change in fair value of cash flow hedges	(129)		(214)		(231)		776
Income taxes on change in fair value of cash flow hedges	—		—		—		—
Net change in fair value of cash flow hedges	(129)		(214)		(231)		776
Change in derivatives designated as cash flow hedges, after taxes	(65)		(442)		(116)		484
Pension and other postretirement plans
(Increase) reduction in unrecognized actuarial losses	(11)		4		3		4
Income taxes on actuarial changes in plan liabilities	—		—		—		—
(Increase) reduction in unrecognized actuarial losses, net	(11)		4		3		4
Amortization of net actuarial losses	16		12		32		24
Income taxes on amortization of net actuarial losses	—		—		—		—
Net effect of amortization of net actuarial losses	16		12		32		24
Change in pension and other postretirement plans, after taxes	5		16		35		28
Other Comprehensive Income (Loss)	(60)		(426)		(81)		512
Comprehensive Income (Loss)	(47)		(689)		268		(2,117)
Less: Comprehensive income (loss) attributable to noncontrolling interests	86		57		170		124
Comprehensive Income (Loss) Attributable to Hess Corporation	$	(133)	$	(746)	$	98	$	(2,241)

See accompanying Notes to Consolidated Financial Statements.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS (UNAUDITED)


	Six Months Ended June 30,
	2021		2020

	(In millions)
Cash Flows From Operating Activities
Net income (loss)	$	349	$	(2,629)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
(Gains) losses on asset sales, net	—		(8)
Depreciation, depletion and amortization	781		1,070
Impairment and other	147		2,126
Exploratory dry hole costs	9		135
Exploration lease and other impairment	10		38
Pension settlement loss	4		—
Stock compensation expense	44		47
Noncash (gains) losses on commodity derivatives, net	88		119
Provision (benefit) for deferred income taxes and other tax accruals	42		(95)
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable	(315)		628
(Increase) decrease in inventories	137		(99)
Increase (decrease) in accounts payable and accrued liabilities	(56)		(520)
Increase (decrease) in taxes payable	187		(63)
Changes in other operating assets and liabilities	(51)		(38)
Net cash provided by (used in) operating activities	1,376		711
Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P	(687)		(1,250)
Additions to property, plant and equipment - Midstream	(53)		(147)
Proceeds from asset sales, net of cash sold	297		11
Other, net	(2)		(2)
Net cash provided by (used in) investing activities	(445)		(1,388)
Cash Flows From Financing Activities
Net borrowings (repayments) of debt with maturities of 90 days or less	(75)		72
Debt with maturities of greater than 90 days:
Borrowings	—		1,000
Repayments	(5)		—
Proceeds from sale of Class A shares of Hess Midstream LP	70		—
Payments on finance lease obligations	(4)		(3)
Cash dividends paid	(157)		(157)
Employee stock options exercised	75		15
Noncontrolling interests, net	(137)		(128)
Other, net	(7)		(21)
Net cash provided by (used in) financing activities	(240)		778
Net Increase (Decrease) in Cash and Cash Equivalents	691		101
Cash and Cash Equivalents at Beginning of Year	1,739		1,545
Cash and Cash Equivalents at End of Period	$	2,430	$	1,646

See accompanying Notes to Consolidated Financial Statements.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED EQUITY (UNAUDITED)


	Common Stock		Capital in Excess of Par		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total Hess Stockholders' Equity		Noncontrolling Interests		Total Equity


For the Three Months Ended June 30, 2021
Balance at April 1, 2021	$	308	$	5,779	$	305	$	(776)	$	5,616	$	1,027	$	6,643
Net income (loss)	—		—		(73)		—		(73)		86		13
Other comprehensive income (loss)	—		—		—		(60)		(60)		—		(60)
Share-based compensation	2		80		—		—		82		—		82
Dividends on common stock	—		—		(77)		—		(77)		—		(77)
Noncontrolling interests, net	—		—		—		—		—		(69)		(69)
Balance at June 30, 2021	$	310	$	5,859	$	155	$	(836)	$	5,488	$	1,044	$	6,532
For the Three Months Ended June 30, 2020
Balance at April 1, 2020	$	307	$	5,633	$	1,021	$	239	7,200		$	978	$	8,178
Net income (loss)	—		—		(320)		—		(320)		57		(263)
Other comprehensive income (loss)	—		—		—		(426)		(426)		—		(426)
Share-based compensation	—		17		—		—		17		—		17
Dividends on common stock	—		—		(76)		—		(76)		—		(76)
Noncontrolling interests, net	—		—		—		—		—		(64)		(64)
Balance at June 30, 2020	$	307	$	5,650	$	625	$	(187)	$	6,395	$	971	$	7,366
For the Six Months Ended June 30, 2021
Balance at January 1, 2021	$	307	$	5,684	$	130	$	(755)	5,366		$	969	$	6,335
Net income (loss)	—		—		179		—		179		170		349
Other comprehensive income (loss)	—		—		—		(81)		(81)		—		(81)
Share-based compensation	3		119		—		—		122		—		122
Dividends on common stock	—		—		(154)		—		(154)		—		(154)
Sale of Class A shares of Hess Midstream LP	—		56		—		—		56		41		97
Noncontrolling interests, net	—		—		—		—		—		(136)		(136)
Balance at June 30, 2021	$	310	$	5,859	$	155	$	(836)	$	5,488	$	1,044	$	6,532
For the Six Months Ended June 30, 2020
Balance at January 1, 2020	$	305	$	5,591	$	3,535	$	(699)	8,732		$	974	$	9,706
Net income (loss)	—		—		(2,753)		—		(2,753)		124		(2,629)
Other comprehensive income (loss)	—		—		—		512		512		—		512
Share-based compensation	2		59		(5)		—		56		—		56
Dividends on common stock	—		—		(152)		—		(152)		—		(152)
Noncontrolling interests, net	—		—		—		—		—		(127)		(127)
Balance at June 30, 2020	$	307	$	5,650	$	625	$	(187)	$	6,395	$	971	$	7,366

See accompanying Notes to Consolidated Financial Statements.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. Basis of Presentation

The financial statements included in this report reflect all normal and recurring adjustments which, in the opinion of management, are necessary for a fair presentation of our consolidated financial position at June 30, 2021 and December 31, 2020, the consolidated results of operations for the three and six months ended June 30, 2021 and 2020, and consolidated cash flows for the six months ended June 30, 2021 and 2020. 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, 2020.

2. Inventories

Inventories consisted of the following:


	June 30, 2021		December 31, 2020

	(In millions)
Crude oil and natural gas liquids	$	62	$	226
Materials and supplies	179		152
Total Inventories	$	241	$	378

At December 31, 2020, crude oil inventories included $164 million associated with the cost of 4.2 million barrels of crude oil transported and stored on two chartered very large crude carriers (VLCCs) for sale in Asian markets. The two VLCC cargos were sold in the first quarter of 2021.

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

3. Property, Plant and Equipment

Assets Held for Sale:

In March 2021, we entered into an agreement to sell our interests in Denmark for total consideration of $150 million, with an effective date of January 1, 2021. At June 30, 2021, property, plant and equipment and operating lease right-of-use assets totaling $228 million, and asset retirement obligations and operating lease liabilities totaling $139 million, associated with our interests in Denmark were presented as Assets held for sale and as liabilities held for sale within Accrued Liabilities, respectively, in our Consolidated Balance Sheet.

Dispositions:

In April 2021, we completed the sale of our Little Knife and Murphy Creek nonstrategic acreage interests in the Bakken for net cash consideration of $297 million, after closing adjustments. The sale included approximately 78,700 net acres, which are located in the southernmost portion of the Corporation's Bakken position. The acreage constituted part of a larger amortization base and the sale was treated as a normal retirement. Accordingly, no gain or loss was recognized upon sale.

Capitalized Exploratory Well Costs:

The following table discloses the net changes in capitalized exploratory well costs pending determination of proved reserves during the six months ended June 30, 2021 (in millions):


Balance at January 1, 2021	$	459
Additions to capitalized exploratory well costs pending the determination of proved reserves	72
Balance at June 30, 2021	$	531

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Capitalized exploratory well costs capitalized for greater than one year following completion of drilling were $375 million at June 30, 2021 and primarily related to:

Guyana: Approximately 85% of the capitalized well costs in excess of one year relate to successful exploration wells where hydrocarbons were encountered on the Stabroek Block (Hess 30%), offshore Guyana. The operator plans further appraisal drilling and is conducting pre-development planning for additional phases of development beyond the three previously sanctioned development projects on the Block.

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, 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% of the capitalized well costs in excess of one year relate to the North Malay Basin (Hess 50%), offshore Peninsular Malaysia, where hydrocarbons were encountered in one successful exploration well. Subsurface evaluation and pre-development studies are ongoing.

4. Hess Midstream LP

In March 2021, the Corporation received net proceeds of $70 million from the public offering of 3,450,000 Hess-owned Class A shares in Hess Midstream LP. The transaction resulted in an increase in Capital in Excess of Par of $56 million and Noncontrolling Interests of $41 million including $14 million from the change in ownership and $27 million from the recognition of a deferred tax asset due to an increase in tax basis of Hess Midstream LP's investment in Hess Midstream Operations LP. After giving effect to this transaction, the Corporation owns an approximate 46% interest in Hess Midstream LP, on a consolidated basis.

At June 30, 2021 Hess Midstream LP, a variable interest entity that is fully consolidated by Hess Corporation, had liabilities totaling $1,945 million (December 31, 2020: $2,026 million) that are on a nonrecourse basis to Hess Corporation, while Hess Midstream LP assets available to settle the obligations of Hess Midstream LP include cash and cash equivalents totaling $4 million (December 31, 2020: $3 million), property, plant and equipment with a carrying value of $3,101 million (December 31, 2020: $3,111 million) and an equity-method investment of $102 million (December 31, 2020: $108 million) in the Little Missouri 4 gas processing plant.

5. Accrued Liabilities

Accrued Liabilities consisted of the following:


	June 30, 2021		December 31, 2020

	(In millions)
Accrued capital expenditures	$	351	$	345
Accrued operating and marketing expenditures	304		325
Accrued payments to royalty and working interest owners	209		170
Current portion of asset retirement obligations	209		105
Liabilities held for sale	139		—
Accrued interest on debt	126		126
Accrued compensation and benefits	76		117
Other accruals	66		63
Total Accrued Liabilities	$	1,480	$	1,251

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

6. Revenue

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


	Exploration and Production										Midstream		Eliminations		Total
	United States		Guyana		Malaysia & JDA		Other (a)		E&P Total

	(In millions)
Three Months Ended June 30, 2021
Sales of our net production volumes:
Crude oil revenue	$	661	$	134	$	27	$	135	$	957	$	—	$	—	$	957
Natural gas liquids revenue	120		—		—		—		120		—		—		120
Natural gas revenue	61		—		178		1		240		—		—		240
Sales of purchased oil and gas	299		4		—		26		329		—		—		329
Intercompany revenue	—		—		—		—		—		294		(294)		—
Total revenues from contracts with customers	1,141		138		205		162		1,646		294		(294)		1,646
Other operating revenues (b)	(53)		(6)		—		(8)		(67)		—		—		(67)
Total sales and other operating revenues	$	1,088	$	132	$	205	$	154	$	1,579	$	294	$	(294)	$	1,579
Three Months Ended June 30, 2020
Sales of our net production volumes:
Crude oil revenue	$	254	$	31	$	1	$	14	$	300	$	—	$	—	$	300
Natural gas liquids revenue	43		—		—		—		43		—		—		43
Natural gas revenue	32		—		89		2		123		—		—		123
Sales of purchased oil and gas	143		—		—		—		143		—		—		143
Intercompany revenue	—		—		—		—		—		270		(270)		—
Total revenues from contracts with customers	472		31		90		16		609		270		(270)		609
Other operating revenues (b)	188		27		—		9		224		—		—		224
Total sales and other operating revenues	$	660	$	58	$	90	$	25	$	833	$	270	$	(270)	$	833
Six Months Ended June 30, 2021
Sales of our net production volumes:
Crude oil revenue	$	1,546	$	315	$	49	$	251	$	2,161	$	—	$	—	$	2,161
Natural gas liquids revenue	263		—		—		—		263		—		—		263
Natural gas revenue	174		—		341		4		519		—		—		519
Sales of purchased oil and gas	597		8		—		45		650		—		—		650
Intercompany revenue	—		—		—		—		—		583		(583)		—
Total revenues from contracts with customers	2,580		323		390		300		3,593		583		(583)		3,593
Other operating revenues (b)	(94)		(10)		—		(12)		(116)		—		—		(116)
Total sales and other operating revenues	$	2,486	$	313	$	390	$	288	$	3,477	$	583	$	(583)	$	3,477
Six Months Ended June 30, 2020
Sales of our net production volumes:
Crude oil revenue	$	919	$	69	$	3	$	50	$	1,041	$	—	$	—	$	1,041
Natural gas liquids revenue	91		—		—		—		91		—		—		91
Natural gas revenue	70		—		228		6		304		—		—		304
Sales of purchased oil and gas	459		1		—		—		460		—		—		460
Intercompany revenue	—		—		—		—		—		561		(561)		—
Total revenues from contracts with customers	1,539		70		231		56		1,896		561		(561)		1,896
Other operating revenues (b)	243		33		1		14		291		—		—		291
Total sales and other operating revenues	$	1,782	$	103	$	232	$	70	$	2,187	$	561	$	(561)	$	2,187

(a)Other includes our interests in Denmark and Libya.

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

There have been no significant changes to contracts with customers or composition thereof during the six months ended June 30, 2021. Generally, we receive payments from customers on a monthly basis, shortly after the physical delivery of the crude oil, natural gas liquids, or natural gas.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

7. Impairment and Other

In June 2021, the U.S. Bankruptcy Court approved the bankruptcy plan for Fieldwood Energy LLC (Fieldwood) which includes transferring abandonment obligations of Fieldwood to predecessors in title of certain of its assets, who are jointly and severally liable for the obligations. Second quarter 2021 results include a charge of $147 million ($147 million after income taxes) in connection with total estimated abandonment obligations in the West Delta 79/86 Field (West Delta Field), which we sold to a Fieldwood predecessor in 2004. See Note 10, Guarantees and Contingencies.

First quarter 2020 results include 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 and Tubular Bells fields in the Gulf of Mexico, primarily as a 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.

8. Retirement Plans

Components of net periodic pension cost consisted of the following:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020

	(In millions)
Service cost	$	13	$	14	$	27	$	28
Interest cost (a)	14		19		28		37
Expected return on plan assets (a)	(49)		(45)		(99)		(90)
Amortization of unrecognized net actuarial losses (a)	13		12		28		24
Settlement loss (a)	3		—		4		—
Pension (income) expense (a)	$	(6)	$	—	$	(12)	$	(1)

(a) Net non-service pension cost included in Other, net in the Statement of Consolidated Income for the three and six months ended June 30, 2021 was income of $19 million and $39 million, respectively, compared with income of $14 million and $29 million for the three and six months ended June 30, 2020, respectively.

In 2021, we expect to contribute approximately $10 million to our funded pension plans.

9. Weighted Average Common Shares

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020

	(In millions)
Net income (loss) attributable to Hess Corporation:
Net income (loss)	$	13	$	(263)	$	349	$	(2,629)
Less: Net income (loss) attributable to noncontrolling interests	86		57		170		124
Net income (loss) attributable to Hess Corporation	$	(73)	$	(320)	$	179	$	(2,753)
Weighted average number of common shares outstanding:
Basic	307.5		305.0		306.7		304.5
Effect of dilutive securities
Restricted common stock	—		—		0.7		—
Stock options	—		—		0.5		—
Performance share units	—		—		0.8		—
Diluted	307.5		305.0		308.7		304.5

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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


	Three Months Ended June 30,		Six Months Ended June 30,
	2021	2020	2021	2020
Restricted common stock	1,641,860	2,173,061	94,726	2,094,360
Stock options	2,562,983	4,429,642	832,454	4,239,533
Performance share units	1,161,324	992,166	39,608	1,144,261

During the six months ended June 30, 2021, we granted 705,489 shares of restricted stock (2020: 1,120,356), 205,155 performance share units (2020: 307,999) and 319,295 stock options (2020: 686,639).

10. Guarantees and Contingencies

We are subject to loss contingencies with respect to various claims, lawsuits and other proceedings. A liability is recognized in our consolidated financial statements when it is probable that a loss has been incurred and the amount can be reasonably estimated. If the risk of loss is probable, but the amount cannot be reasonably estimated or the risk of loss is only reasonably possible, a liability is not accrued; however, we disclose the nature of those contingencies. We cannot predict with certainty if, how or when existing claims, lawsuits and proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages.

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 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 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 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 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 final 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. We have complied with the EPA’s March 2014 Administrative Order

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

and contributed funding for the Remedial Design based on an allocation of costs among the parties determined by a third-party expert. In January 2020, we received an additional Administrative Order from the EPA requiring us and several other parties to begin Remedial Action along the uppermost portion of the Canal. We intend to comply with this Administrative Order. The remediation work began in the fourth quarter of 2020. Based on currently known facts and circumstances, we do not believe that this matter will result in a significant liability to us, and the costs will continue to be allocated amongst the parties, as they were for the Remedial Design.

From time to time, we are involved in other judicial and administrative proceedings relating to environmental matters. 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. Beginning in 2017, certain states, municipalities and private associations in California, Delaware, Maryland, Rhode Island and South Carolina separately filed lawsuits against oil, gas and coal producers, including us, for alleged damages purportedly caused by climate change. These proceedings include claims for monetary damages and injunctive relief. Beginning in 2013, various parishes in Louisiana filed suit against approximately 100 oil and gas companies, including us, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. The ultimate impact of such climate and other aforementioned environmental 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.

In August 2020, Fieldwood and related entities filed for bankruptcy relief under Chapter 11 of the U.S. Bankruptcy Code. Fieldwood’s Bankruptcy Plan, which was approved by the U.S. Bankruptcy Court in June 2021, includes the abandonment of certain assets, including seven offshore Gulf of Mexico leases and related facilities in the West Delta Field that were formerly owned by us and sold to a Fieldwood predecessor in 2004, and the discharge of Fieldwood’s obligation to decommission these facilities. As a result, in the next nine months, we expect to receive an Order from the Bureau of Safety and Environmental Enforcement (BSEE) requiring us to decommission the facilities on the seven West Delta leases. Our alleged decommissioning obligation derives from our former ownership of the facilities. We intend to comply with BSEE’s Order once we receive it. We also intend to seek contribution from other parties that owned an interest in the facilities. As of June 30, 2021, we accrued a loss contingency of $147 million ($147 million after income taxes) in connection with total estimated abandonment obligations in the West Delta Field. Potential recoveries from other parties that previously owned an interest in the West Delta Field have not been recognized as of June 30, 2021.

We are also involved in other judicial and administrative proceedings from time to time in addition to the matters described above, including claims related to post-production deductions from royalty payments. We may also be exposed to future decommissioning liabilities for divested assets in the event the current or future owners are determined to be unable to perform such actions, whether due to bankruptcy or otherwise. 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 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.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

11. Segment Information

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


	Exploration and Production		Midstream		Corporate, Interest and Other		Eliminations		Total

	(In millions)
For the Three Months Ended June 30, 2021
Sales and Other Operating Revenues - Third parties	$	1,579	$	—	$	—	$	—	$	1,579
Intersegment Revenues	—		294		—		(294)		—
Sales and Other Operating Revenues	$	1,579	$	294	$	—	$	(294)	$	1,579

Net Income (Loss) attributable to Hess Corporation	$	(25)	$	76	$	(124)	$	—	$	(73)
Depreciation, Depletion and Amortization	344		41		—		—		385
Impairment and other	147		—		—		—		147
Provision (Benefit) for Income Taxes	119		3		—		—		122
Capital Expenditures	396		47		—		—		443
For the Three Months Ended June 30, 2020
Sales and Other Operating Revenues - Third parties	$	833	$	—	$	—	$	—	$	833
Intersegment Revenues	—		270		—		(270)		—
Sales and Other Operating Revenues	$	833	$	270	$	—	$	(270)	$	833

Net Income (Loss) attributable to Hess Corporation	$	(249)	$	51	$	(122)	$	—	$	(320)
Depreciation, Depletion and Amortization	470		39		—		—		509
Provision (Benefit) for Income Taxes	(11)		2		—		—		(9)
Capital Expenditures	428		79		—		—		507
For the Six Months Ended June 30, 2021
Sales and Other Operating Revenues - Third parties	$	3,477	$	—	$	—	$	—	$	3,477
Intersegment Revenues	—		583		—		(583)		—
Sales and Other Operating Revenues	$	3,477	$	583	$	—	$	(583)	$	3,477

Net Income (Loss) attributable to Hess Corporation	$	283	$	151	$	(255)	$	—	$	179
Depreciation, Depletion and Amortization	699		81		1		—		781
Impairment and other	147		—		—		—		147
Provision (Benefit) for Income Taxes	239		6		—		—		245
Capital Expenditures	676		70		—		—		746
For the Six Months Ended June 30, 2020
Sales and Other Operating Revenues - Third parties	$	2,187	$	—	$	—	$	—	$	2,187
Intersegment Revenues	—		561		—		(561)		—
Sales and Other Operating Revenues	$	2,187	$	561	$	—	$	(561)	$	2,187

Net Income (Loss) attributable to Hess Corporation	$	(2,620)	$	112	$	(245)	$	—	$	(2,753)
Depreciation, Depletion and Amortization	991		77		2		—		1,070
Impairment and other	2,126		—		—		—		2,126
Provision (Benefit) for Income Taxes	(88)		4		(4)		—		(88)
Capital Expenditures	1,037		136		—		—		1,173

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Identifiable assets by operating segment were as follows:


	June 30, 2021		December 31, 2020

	(In millions)
Exploration and Production	$	13,753	$	13,688
Midstream	3,587		3,599
Corporate, Interest and Other	1,826		1,534
Total	$	19,166	$	18,821

12. Financial Risk Management Activities

In the normal course of our business, we are exposed to commodity risks related to changes in the prices of crude oil and natural gas. 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 or establish a floor price for a portion of our crude oil or natural gas production. Forward contracts may be used to purchase certain currencies in which we conduct business with the intent of reducing exposure to foreign currency fluctuations. At June 30, 2021, these forward contracts relate to the British Pound, Canadian Dollar and Malaysian Ringgit. Interest rate swaps may be used to convert interest payments on certain long-term debt from fixed to floating rates.

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


	June 30, 2021		December 31, 2020

	(In millions)
Commodity - crude oil put options (millions of barrels)	27.6		27.4

Foreign exchange forwards	$	91	$	163
Interest rate swaps	$	100	$	100

As of June 30, 2021, we have West Texas Intermediate (WTI) put options of 120,000 barrels of oil per day (bopd) with an average monthly floor price of $55 per barrel and Brent put options of 30,000 bopd with an average monthly floor price of $60 per barrel for the remainder of 2021.

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

The table below reflects the fair values of risk management derivative instruments.


	Assets		Liabilities

	(In millions)
June 30, 2021
Derivative Contracts Designated as Hedging Instruments:
Crude oil put options	$	19	$	—
Interest rate swaps	4		—
Total derivative contracts designated as hedging instruments	23		—
Derivative Contracts Not Designated as Hedging Instruments:
Foreign exchange forwards	—		—
Total derivative contracts not designated as hedging instruments	—		—
Gross fair value of derivative contracts	23		—
Gross amounts offset in the Consolidated Balance Sheet	—		—
Net Amounts Presented in the Consolidated Balance Sheet	$	23	$	—
December 31, 2020
Derivative Contracts Designated as Hedging Instruments:
Crude oil put options	$	64	$	—
Crude oil swaps	—		(54)
Interest rate swaps	5		—
Total derivative contracts designated as hedging instruments	69		(54)
Derivative Contracts Not Designated as Hedging Instruments:
Foreign exchange forwards	—		(1)
Total derivative contracts not designated as hedging instruments	—		(1)
Gross fair value of derivative contracts	69		(55)
Gross amounts offset in the Consolidated Balance Sheet	(13)		13
Net Amounts Presented in the Consolidated Balance Sheet	$	56	$	(42)

During the first quarter of 2021, we completed the sale of 4.2 million barrels of Bakken crude oil transported and stored on two VLCCs during 2020 for sale in Asian markets. We recognized net losses of $4 million from crude oil hedging contracts associated with the VLCC volumes in the first quarter of 2021.

The fair value of our crude oil put options is presented within Other current assets in our Consolidated Balance Sheet. The fair value of our interest rate swaps is presented within Other assets in our Consolidated Balance Sheet. The fair value of our foreign exchange forwards is presented within Accrued liabilities in our Consolidated Balance Sheet. All fair values in the table above are based on Level 2 inputs.

Derivative contracts designated as hedging instruments:

Crude oil derivatives designated as cash flow hedges: Crude oil hedging contracts decreased Sales and other operating revenues by $64 million and $115 million in the three and six months ended June 30, 2021, respectively. In the three and six months ended June 30, 2020, crude oil hedging contracts increased Sales and other operating revenues by $228 million and $292 million, respectively. At June 30, 2021, pre-tax deferred losses in Accumulated other comprehensive income (loss) related to outstanding crude oil put option contracts were $112 million, all of which will be reclassified into earnings during the remainder of 2021 as the hedged crude oil sales are recognized in earnings.

Interest rate swaps designated as fair value hedges: At June 30, 2021 and December 31, 2020, 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 from fixed to floating rates. Changes in the fair value of interest rate swaps and the hedged fixed-rate debt are recorded in Interest expense in the Statement of Consolidated Income. In the three and six months ended June 30, 2021, the change in fair value of interest rate swaps was a decrease in the asset of nil and $1 million, respectively, compared with an increase in the asset of $1 million and $6 million in the three and six months ended June 30, 2020, respectively, with a corresponding adjustment in the carrying value of the hedged fixed-rate debt.

Derivative contracts not designated as hedging instruments:

Foreign exchange: Foreign exchange gains and losses which are reported in Other, net in Revenues and non-operating income in the Statement of Consolidated Income were losses of $1 million and $2 million in the three and six months ended June 30, 2021, respectively, compared with losses of $2 million and $3 million in the three and six months ended June 30, 2020, respectively. A

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

component of foreign exchange gains and losses is the result of foreign exchange derivative contracts that are not designated as hedges which amounted to net gains of $1 million and nil in the three and six months ended June 30, 2021, respectively, compared with net gains of $1 million and $3 million in the three and six months ended June 30, 2020, respectively.

Fair Value Measurement:

At June 30, 2021, consolidated long-term debt, which was substantially comprised of fixed-rate debt instruments, had a carrying value of $8,223 million and a fair value of $9,749 million based on Level 2 inputs in the fair value measurement hierarchy. We also have short-term financial instruments, primarily cash equivalents, accounts receivable and accounts payable, for which the carrying value approximated fair value at June 30, 2021 and December 31, 2020.

13. Subsequent Events

In July 2021, we repaid $500 million principal amount of our $1 billion term loan, which matures in March 2023. At June 30, 2021, the $500 million which was repaid in July has been classified as Current maturities of long-term debt in our Consolidated Balance Sheet.

In July 2021, Hess Midstream LP announced that its subsidiary, Hess Midstream Operations LP (HESM Opco), agreed to repurchase approximately 31 million HESM Opco Class B units held by Hess Corporation and Global Infrastructure Partners for approximately $750 million. We expect to receive net proceeds of approximately $375 million. After giving effect to this transaction, which is expected to be completed in the third quarter of 2021, we will own an approximate 45% interest in Hess Midstream LP, on a consolidated basis. In August 2021, HESM Opco issued $750 million in aggregate principal amount of senior unsecured notes due 2030 in a private offering to finance the repurchase.

PART I - FINANCIAL INFORMATION (CONT'D.)

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

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 June 30, 2021 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, 2020. 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 discussed in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2020.

Overview

Hess Corporation is a global E&P company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located primarily in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA), Malaysia, and Denmark. We conduct exploration activities primarily offshore Guyana, in the U.S. Gulf of Mexico, and offshore Suriname and Canada. At the Stabroek Block (Hess 30%), offshore Guyana, we and our partners have discovered a significant resource base and are executing a multi-phased development of the Block. The Liza Phase 1 development achieved first production in December 2019, and has a nameplate production capacity of approximately 120,000 gross bopd. The Liza Phase 2 development was sanctioned in the second quarter of 2019 and remains on track to achieve first production by early 2022, with production capacity of approximately 220,000 gross bopd. A third development, Payara, was sanctioned in the third quarter of 2020 and is expected to achieve first production in 2024, with production capacity of approximately 220,000 gross bopd. A fourth development, Yellowtail, has been identified on the Stabroek Block with anticipated startup in 2025, pending government approvals and project sanctioning. The discovered resources to date on the Stabroek Block are expected to underpin up to ten floating production, storage and offloading vessels (FPSOs) with the first six FPSOs expected by 2027.

Our Midstream operating segment, which is comprised of Hess Corporation’s approximate 46% consolidated ownership interest in Hess Midstream LP at June 30, 2021, provides fee-based services, including gathering, compressing and processing natural gas and fractionating natural gas liquids (NGL); gathering, terminaling, loading and transporting crude oil and NGL; storing and terminaling propane, and water handling services primarily in the Bakken shale play in the Williston Basin area of North Dakota.

In July 2021, Hess Midstream LP announced that its subsidiary, HESM Opco, agreed to repurchase approximately 31 million HESM Opco Class B units held by Hess Corporation and Global Infrastructure Partners for approximately $750 million. We expect to receive net proceeds of approximately $375 million. After giving effect to this transaction, which is expected to be completed in the third quarter of 2021, we will own an approximate 45% interest in Hess Midstream LP, on a consolidated basis. In August 2021, HESM Opco issued $750 million in aggregate principal amount of senior unsecured notes due 2030 in a private offering to finance the repurchase.

Hess Response to Global Pandemic

COVID-19 continues to have a profound impact on society and industry. The Corporation’s first priority in the midst of the pandemic has been the health and safety of the Hess workforce and local communities where the Corporation operates. 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.

2021 Outlook

In July, we repaid $500 million principal amount of our $1 billion term loan, which matures in March 2023, and announced plans to add a third Bakken drilling rig in September 2021. Our E&P capital and exploratory expenditure guidance for 2021 of approximately $1.9 billion remains unchanged, including the planned increase in Bakken rig count. Oil and gas production in 2021, excluding Libya, is now forecast to be approximately 295,000 barrels of oil equivalent per day (boepd). For the remainder of 2021, we have hedged 120,000 bopd with $55 WTI put options and 30,000 bopd with $60 Brent put options.

In the third quarter of 2021, we expect to receive approximately $375 million from HESM Opco related to its announced repurchase of approximately 31 million Class B units and proceeds from the sale of our interests in Denmark for total consideration of $150 million, with an effective date of January 1, 2021.

PART I - FINANCIAL INFORMATION (CONT'D.)

Overview (continued)

quarter of 2021 with $2.42 billion in cash and cash equivalents. In 2021, based on current forward strip crude oil prices, we expect cash flow from operating activities, expected proceeds from the sale of our interests in Denmark and the Class B unit repurchase by HESM Opco, and cash and cash equivalents at June 30, 2021 will be sufficient to fund our capital investment program, the July repayment of $500 million principal amount of our $1 billion term loan maturing in March 2023, and dividends. Depending on market conditions, we may take any of the following steps, or a combination thereof, to improve our liquidity and financial position: reduce the planned capital program and other cash outlays, including dividends, pursue asset sales, borrow against our committed revolving credit facility, or issue debt or equity securities.

Second Quarter Results

In the second quarter of 2021, we incurred a net loss of $73 million, compared with a net loss of $320 million in the second quarter of 2020. Excluding items affecting comparability of earnings between periods detailed on pages 25 and 26, adjusted net income was $74 million in the second quarter of 2021. The improvement in second quarter 2021 adjusted results compared to the prior-year quarter primarily reflects higher realized selling prices.

Exploration and Production Results

In the second quarter of 2021, E&P had a net loss of $25 million, compared with a net loss of $249 million in the second quarter of 2020. Excluding items affecting comparability of earnings between periods, adjusted net income was $122 million in the second quarter of 2021. Total net production, excluding Libya, averaged 307,000 boepd in the second quarter 2021, compared with 334,000 boepd in the second quarter of 2020, or 322,000 boepd pro forma for assets sold. The average realized crude oil selling price, including hedging, was $59.79 per barrel in the second quarter of 2021, compared with $38.46 per barrel in the second quarter of 2020. The average realized NGL selling price in the second quarter of 2021 was $23.12 per barrel, compared with $7.32 per barrel in the prior-year quarter, while the average realized natural gas selling price was $4.05 per thousand cubic feet (mcf) in the second quarter of 2021, compared with $2.41 per mcf in the second quarter of 2020.

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

•In North Dakota, net production from the Bakken oil shale play averaged 159,000 boepd for the second quarter of 2021 (2020 Q2: 194,000 boepd), primarily due to lower drilling activity caused by a reduction in rig count from six to one last year, and lower NGL and natural gas volumes received under percentage of proceeds contracts due to higher commodity prices. Net oil production was 79,000 bopd in the second quarter of 2021 and 108,000 bopd in the prior year quarter. NGL and natural gas volumes received under percentage of proceeds contracts were 14,000 boepd in the second quarter of 2021 compared with 22,000 boepd in the second quarter of 2020 due to higher realized NGL prices lowering volumes received as consideration for gas processing fees. We added a second rig in February 2021 and drilled 17 wells, completed 9 wells, and brought 9 new wells online during the second quarter. In September 2021, we plan to add a third rig in the field. We forecast net production to average approximately 145,000 boepd for the third quarter of 2021, which reflects the planned third quarter Tioga gas plant turnaround, and in the range of 155,000 boepd to 160,000 boepd for the full year 2021.

On April 30, 2021, we completed the sale of our previously announced Little Knife and Murphy Creek nonstrategic acreage interests in the Bakken for net cash consideration of $297 million, after closing adjustments. The sale included approximately 78,700 net acres, which are located in the southernmost portion of the Corporation's Bakken position and not connected to Hess Midstream LP infrastructure.

•In the Gulf of Mexico, net production for the second quarter of 2021 averaged 52,000 boepd (2020 Q2: 68,000 boepd), primarily due to the sale of our interest in the Shenzi Field in the fourth quarter of 2020. Net production from the Shenzi Field was 12,000 boepd in the second quarter of 2020.

•At the Stabroek Block (Hess 30%), offshore Guyana, net production from the Liza Phase 1 development averaged 26,000 bopd for the second quarter of 2021 (2020 Q2: 22,000 bopd). Startup of Phase 2 of the Liza Field development, which will utilize the Liza Unity FPSO with an expected capacity of 220,000 gross bopd, remains on track for early 2022. The third development, Payara, will utilize the Prosperity FPSO with an expected capacity of 220,000 gross bopd; first oil is expected in 2024. A fourth development, Yellowtail, has been identified on the Stabroek Block with anticipated startup in 2025, pending government approvals and project sanctioning. The Mako-2 appraisal well completed in the second quarter confirmed the quality, thickness and areal extent of the reservoir. When integrated with the previously announced results at Uaru-2, the combined discovered resource at Mako and Uaru is expected to support a fifth FPSO on the Stabroek Block.

The recently announced Whiptail-1 well encountered 246 feet (75 meters) of net pay in high quality oil bearing sandstone reservoirs. Drilling is also ongoing at the Whiptail-2 well, which is located three miles northeast of Whiptail-1 and has encountered 167 feet (51 meters) of net pay in high quality oil bearing sandstone reservoirs. Drilling continues at both wells to test deeper targets, and results will be evaluated for future development. The Whiptail discovery is located approximately four

PART I - FINANCIAL INFORMATION (CONT'D.)

Overview (continued)

miles southeast of the Uaru-1 discovery that was announced in January 2020 and approximately three miles west of the Yellowtail Field.

In the second quarter, the Longtail-3 well encountered 230 feet of net pay, including newly identified, high quality hydrocarbon bearing reservoirs below the original Longtail-1 discovery intervals. The well is located approximately two miles south of the Longtail-1 well.

The Koebi-1 exploration well was drilled to a depth of 20,700 feet and did not encounter commercial quantities of hydrocarbons. Second quarter results include a charge of $12 million in exploration expenses for well costs incurred.

The Stena DrillMax is continuing drilling operations at Whiptail-1 and the Noble Don Taylor is continuing drilling operations at Whiptail-2. The Stena Carron is performing a drill stem test on the Uaru-1 well. The Noble Tom Madden, the Noble Bob Douglas and the Noble Sam Croft are drilling and completing Phase 2 development wells.

•In the Gulf of Thailand, net production from Block A-18 of the JDA averaged 38,000 boepd for the second quarter of 2021 (2020 Q2: 23,000 boepd), including contribution from unitized acreage in Malaysia, while net production from North Malay Basin, offshore Peninsular Malaysia, averaged 28,000 boepd for the second quarter of 2021 (2020 Q2: 21,000 boepd). Net production was higher at the JDA and North Malay Basin due to higher natural gas nominations resulting from a recovery in economic activity.

•In March, we entered into an agreement to sell our interests in Denmark for total consideration of $150 million, with an effective date of January 1, 2021. Net production from Denmark during the second quarter of 2021 was 4,000 boepd (2020 Q2: 6,000 boepd). The sale is expected to close during the third quarter of 2021.

Consolidated Results of Operations

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020

	(In millions, except per share amounts)
Net Income (Loss) Attributable to Hess Corporation:
Exploration and Production	$	(25)	$	(249)	$	283	$	(2,620)
Midstream	76		51		151		112
Corporate, Interest and Other	(124)		(122)		(255)		(245)
Total	$	(73)	$	(320)	$	179	$	(2,753)
Net Income (Loss) Attributable to Hess Corporation Per Common Share:
Basic	$	(0.24)	$	(1.05)	$	0.58	$	(9.04)
Diluted	$	(0.24)	$	(1.05)	$	0.58	$	(9.04)

Items Affecting Comparability of Earnings Between Periods

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020

	(In millions)
Items Affecting Comparability of Earnings Between Periods, After-Tax:
Exploration and Production	$	(147)	$	—	$	(147)	$	(2,251)
Midstream	—		—		—		—
Corporate, Interest and Other	—		—		—		—
Total	$	(147)	$	—	$	(147)	$	(2,251)

The items in the table above are explained on pages 25 and 26.

PART I - FINANCIAL INFORMATION (CONT'D.)

Consolidated Results of Operations (continued)

Reconciliations of GAAP and non-GAAP measures

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020

	(In millions)
Adjusted Net Income (Loss) Attributable to Hess Corporation:
Net income (loss) attributable to Hess Corporation	$	(73)	$	(320)	$	179	$	(2,753)
Less: Total items affecting comparability of earnings between periods, after-tax	(147)		—		(147)		(2,251)
Adjusted Net Income (Loss) Attributable to Hess Corporation	$	74	$	(320)	$	326	$	(502)

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


	Six Months Ended June 30,
	2021		2020

	(In millions)
Net cash provided by operating activities before changes in operating assets and liabilities:
Net cash provided by (used in) operating activities	$	1,376	$	711
Changes in operating assets and liabilities	98		92
Net cash provided by (used in) operating activities before changes in operating assets and liabilities	$	1,474	$	803

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, which are summarized on pages 25 and 26. 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.

Net cash provided by (used in) operating activities before changes in operating assets and liabilities presented in this report is a non-GAAP 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 changes in operating assets and liabilities to evaluate the Corporation’s ability to internally fund capital expenditures, pay dividends and service debt and believes that investors’ understanding of our 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 our performance 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.

PART I - FINANCIAL INFORMATION (CONT'D.)

Consolidated Results of Operations (continued)

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.

Comparison of Results

Exploration and Production

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020

	(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues	$	1,579	$	833	$	3,477	$	2,187

Other, net	14		(1)		30		7
Total revenues and non-operating income	1,593		832		3,507		2,194
Costs and Expenses
Marketing, including purchased oil and gas	343		97		885		522
Operating costs and expenses	254		203		462		417
Production and severance taxes	44		16		81		58
Midstream tariffs	270		225		532		466
Exploration expenses, including dry holes and lease impairment	48		31		81		220
General and administrative expenses	49		50		98		102
Depreciation, depletion and amortization	344		470		699		991
Impairment and other	147		—		147		2,126
Total costs and expenses	1,499		1,092		2,985		4,902
Results of Operations Before Income Taxes	94		(260)		522		(2,708)
Provision (benefit) for income taxes	119		(11)		239		(88)
Net Income (Loss) Attributable to Hess Corporation	$	(25)	$	(249)	$	283	$	(2,620)

Excluding the E&P items affecting comparability of earnings between periods detailed on pages 25 and 26, the changes in E&P results are primarily attributable to changes in selling prices, production and sales volumes, marketing expenses, cash operating costs, Midstream tariffs, depreciation, depletion and amortization, exploration expenses and income taxes, as discussed below.

PART I - FINANCIAL INFORMATION (CONT'D.)

Consolidated Results of Operations (continued)

Selling Prices: Higher realized selling prices in the second quarter and first six months of 2021, increased after-tax results by approximately $400 million and $670 million, respectively, compared to the same periods in 2020. Average selling prices were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020

Average Selling Prices (a)
Crude Oil – Per Barrel (Including Hedging)
United States
North Dakota (b)	$	56.75	$	38.23	$	49.35	$	42.26
Offshore	59.33		39.10		55.99		44.49
Total United States	57.52		38.57		51.00		43.03
Guyana	65.63		35.28		62.48		38.41
Malaysia and JDA	65.88		15.62		64.69		26.73
Other (c)	64.16		50.29		60.94		53.49
Worldwide	59.79		38.46		54.04		42.98
Crude Oil – Per Barrel (Excluding Hedging)
United States
North Dakota (b)	$	61.88	$	18.93	$	52.91	$	32.52
Offshore	64.42		22.78		60.24		34.61
Total United States	62.63		20.48		54.73		33.23
Guyana	68.44		19.23		64.48		26.11
Malaysia and JDA	65.88		15.62		64.69		26.73
Other (c)	68.08		29.16		63.88		41.19
Worldwide	64.27		20.63		57.36		32.90
Natural Gas Liquids – Per Barrel
United States
North Dakota	$	23.23	$	7.59	$	26.65	$	8.39
Offshore	21.84		4.71		21.55		7.23
Worldwide	23.12		7.32		26.20		8.27
Natural Gas – Per Mcf
United States
North Dakota	$	2.40	$	0.94	$	4.06	$	1.10
Offshore	2.35		1.14		2.66		1.23
Total United States	2.38		1.01		3.56		1.15
Malaysia and JDA	5.22		3.97		5.13		4.39
Other (c)	2.96		3.51		2.82		4.03
Worldwide	4.05		2.41		4.47		2.81

(a)Selling prices in the United States are adjusted for certain processing and distribution fees included in Marketing expenses. Excluding these fees worldwide selling prices for the second quarter of 2021 would be $62.45 (Q2 2020: $41.33) per barrel for crude oil (including hedging), $66.93 (Q2 2020: $23.50) per barrel for crude oil (excluding hedging), $23.35 (Q2 2020: $7.49) per barrel for NGLs and $4.17 (Q2 2020: $2.55) per mcf for natural gas. Excluding these fees worldwide selling prices for the first six months of 2021 would be $58.97 (2020: $46.20) per barrel for crude oil (including hedging), $62.29 (2020: $36.12) per barrel for crude oil (excluding hedging), $26.43 (2020: $8.46) per barrel for NGLs and $4.59 (2020: $2.93) per mcf for natural gas.

(b)Excluding the two VLCC cargo sales totaling 4.2 million barrels in the first quarter of 2021, the North Dakota crude oil price for the first six months of 2021 excluding hedging was $57.39 per barrel and $53.08 per barrel including hedging.

(c)Other includes our interests in Denmark and Libya.

Crude oil hedging activities were a net loss of $64 million and $115 million before and after income taxes in the second quarter and first six months of 2021, respectively, and a net gain of $228 million and $292 million before and after income taxes in the second quarter and first six months of 2020, respectively. As of June 30, 2021, we have WTI put options with an average monthly floor price of $55 per barrel for 120,000 bopd, and Brent put options with an average monthly floor price of $60 per barrel for 30,000 bopd for the remainder of the year. We expect noncash put option premium amortization, which will be reflected in realized selling prices, to reduce our third quarter results by approximately $65 million and our full year 2021 results by approximately $245 million.

PART I - FINANCIAL INFORMATION (CONT'D.)

Consolidated Results of Operations (continued)

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020

	(In thousands)
Crude Oil – Barrels
United States
North Dakota	79		108		82		111
Offshore	33		45		34		47
Total United States	112		153		116		158
Guyana	26		22		29		18
Malaysia and JDA	4		3		4		3
Other (a)	24		5		23		8
Total	166		183		172		187
Natural Gas Liquids – Barrels
United States
North Dakota	52		57		50		53
Offshore	5		6		5		6
Total United States	57		63		55		59
Natural Gas – Mcf
United States
North Dakota	167		177		159		170
Offshore	85		101		90		107
Total United States	252		278		249		277
Malaysia and JDA	371		245		366		285
Other (a)	9		5		10		9
Total	632		528		625		571
Barrels of Oil Equivalent (b)	328		334		331		341

Crude oil and natural gas liquids as a share of total production	68	%	74	%	69	%	72	%

(a)Other includes our interest in Denmark and Libya. Net production from Libya was 21,000 boepd and 20,000 boepd in the second quarter and first six months of 2021, respectively, compared with nil and 3,000 boepd in the second quarter and first six months of 2020, respectively. Net production from Denmark was 4,000 boepd and 5,000 boepd in the second quarter and first six months of 2021, respectively, compared with 6,000 boepd and 7,000 boepd in the second quarter and first six months of 2020, respectively.

(b)Reflects natural gas production converted based on relative energy content (six mcf equals one barrel). Barrel of oil equivalence does not necessarily result in price equivalence as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past. In addition, NGLs do not sell at prices equivalent to crude oil. See the average selling prices in the table on page 22.

We forecast net production, excluding Libya, to be approximately 265,000 boepd for the third quarter, which reflects the planned third quarter Tioga gas plant turnaround, and approximately 295,000 boepd for the full year 2021.

United States: North Dakota net production was lower in the second quarter and first six months of 2021, compared to the corresponding periods in 2020, primarily due to reduced drilling activity and lower NGL and natural gas volumes received under percentage of proceeds contracts due to higher commodity prices. Total offshore net production was lower in the second quarter and first six months of 2021, compared to the corresponding periods in 2020, primarily due to the sale of our working interest in the Shenzi Field in the deepwater Gulf of Mexico in the fourth quarter of 2020. Net production from the Shenzi Field was 12,000 boepd for both the second quarter and first six months of 2020.

International: Net oil production in Guyana was higher in the second quarter and first six months of 2021, compared to the corresponding periods in 2020, due to the production ramp up from the Liza Phase 1 development. Net oil production in Libya was higher in the second and first six months of 2021, compared to the corresponding periods in 2020, due to the lifting of force majeure, declared in the first quarter of 2020, in October 2020. Net natural gas production was higher at Malaysia and JDA reflecting higher natural gas nominations due to a recovery in economic activity.

PART I - FINANCIAL INFORMATION (CONT'D.)

Consolidated Results of Operations (continued)

Sales Volumes: Worldwide sales volumes from Hess net production, which excludes sales volumes of crude oil, NGLs and natural gas purchased from third parties, were as follows:


	Three Months Ended June 30,		Six Months Ended June 30,
	2021	2020	2021	2020

	(In thousands)
Crude oil – barrels (a)	14,293	12,764	34,688	28,816
Natural gas liquids – barrels	5,142	5,690	9,944	10,787
Natural gas – mcf	57,557	48,081	113,070	103,701
Barrels of Oil Equivalent (b)	29,028	26,468	63,477	56,887
Crude oil – barrels per day	157	140	192	158
Natural gas liquids – barrels per day	57	63	55	59
Natural gas – mcf per day	632	528	625	571
Barrels of Oil Equivalent Per Day (b)	319	291	351	312

(a)Sales volumes for the first six months of 2021 include 4.2 million barrels that were stored on VLCCs at December 31, 2020. During the second quarter of 2020, 3.7 million barrels of crude oil were stored on VLCCs.

Marketing, including Purchased Oil and Gas: Marketing expense is mainly comprised of costs to purchase crude oil, NGL and natural gas from our partners in Hess operated wells or other third parties, primarily in the U.S., and transportation and other distribution costs for U.S. marketing activities. Marketing expense was higher in the second quarter and first six months of 2021, compared with the corresponding periods in 2020, primarily due to higher benchmark crude oil prices and the impact of VLCC activity. Second quarter 2020 marketing expense was reduced by $113 million for costs capitalized to crude oil inventory related to 3.7 million barrels produced and stored on VLCCs. First quarter 2021 marketing expense included $173 million related to the cost of 4.2 million barrels of crude oil stored on two VLCCs in 2020 that were sold in the first quarter.

Cash Operating Costs: Cash operating costs consist of operating costs and expenses, production and severance taxes and E&P general and administrative expenses. Cash operating costs increased in the second quarter and first six months of 2021, compared with the corresponding periods in 2020, primarily due to higher maintenance and workover activity and higher production and severance taxes associated with higher crude oil prices. On a per-unit basis, cash operating costs were higher in the second quarter and first six months of 2021, compared with the corresponding periods in 2020 on the higher costs and the impact of lower 2021 production volumes.

Midstream Tariffs Expense: Tariffs expense increased in the second quarter and first six months of 2021, compared with the corresponding periods in 2020, primarily due to higher minimum volume commitments and tariff rates. We estimate Midstream tariffs expense to be in the range of $265 million to $275 million in the third quarter of 2021 and in the range of $1,080 million to $1,100 million for the full year 2021.

Depreciation, Depletion and Amortization (DD&A): DD&A expense was lower in the second quarter of 2021, compared with the corresponding period in 2020, primarily due to lower production volumes and the impact to DD&A rates resulting from year-end 2020 revisions and additions to proved reserves. DD&A expense was lower in the first six months of 2021, compared with the corresponding period in 2020, due to the impact of first quarter 2020 impairment charges, lower production volumes and the impact to DD&A rates resulting from year-end 2020 revisions and additions to proved reserves.

PART I - FINANCIAL INFORMATION (CONT'D.)

Consolidated Results of Operations (continued)

Unit Costs: Unit cost per boe information is based on total net production volumes. Actual and forecast unit costs per boe are as follows:


	Actual								Forecast range (a)
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,	Twelve Months Ended December 31,
	2021		2020		2021		2020		2021	2021
Cash operating costs (b)	$	11.63	$	8.81	$	10.72	$	9.26	$13.00 — $14.00	$11.00 — $12.00
DD&A (c)	11.55		15.45		11.69		15.95		12.00 — 13.00	12.00 — 13.00
Total Production Unit Costs	$	23.18	$	24.26	$	22.41	$	25.21	$25.00 — $27.00	$23.00 — $25.00

(a)Forecast information excludes any contribution from Libya.

(b)Cash operating costs per boe, excluding Libya, were $12.16 and $11.18 in the three and six months ended June 30, 2021, respectively, compared with $8.64 and $9.13 in the same periods of 2020, respectively.

(c)DD&A per boe, excluding Libya, was $12.13 and $12.25 in the three and six months ended June 30, 2021, respectively, compared with $15.45 and $16.05 in the same periods of 2020, respectively.

Exploration Expenses: Exploration expenses were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020

	(In millions)
Exploratory dry hole costs (a)	$	9	$	—	$	9	$	135
Exploration lease and other impairment (b)	6		6		10		38
Geological and geophysical expense and exploration overhead	33		25		62		47
Total Exploration Expense	$	48	$	31	$	81	$	220

(a)First six months of 2021 primarily relates to the Koebi-1 exploration well, offshore Guyana. First six months of 2020 primarily relates to previously capitalized exploratory wells (see Items Affecting Comparability of Earnings Between Periods below) and the Oldfield-1 exploration well in the Gulf of Mexico.

(b)First six months of 2020 includes impaired leasehold costs due to a reprioritization of the Corporation’s forward capital program.

Exploration expenses, excluding dry hole expense, are estimated to be in the range of $40 million to $45 million in the third quarter of 2021 and in the range of $160 million to $170 million for the full year 2021.

Income Taxes: The increase in income tax expense in the second quarter and first six months of 2021, compared to the corresponding periods in 2020, is primarily due to higher pre-tax income in Libya and Guyana. E&P income tax expense in the second quarter of 2021 was $119 million (Q2 2020: $11 million income tax benefit) and includes $96 million of income tax expense (Q2 2020: $8 million income tax benefit) from Libyan operations, and for the first six months of 2021, E&P income tax expense was $239 million (2020: $88 million income tax benefit) and includes $176 million of income tax expense (2020: $14 million income tax benefit) from Libyan operations. An income tax benefit of $80 million was recognized in the first quarter of 2020 attributable to items affecting comparability of earnings between periods. Excluding items affecting comparability between periods and Libyan operations, E&P income tax expense is expected to be in the range of $35 million to $40 million for the third quarter of 2021 and $125 million to $135 million for the full year 2021.

Items Affecting Comparability of Earnings Between Periods:

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020

	(In millions)

Impairment and other	$	(147)	$	—	$	(147)	$	(2,049)
Dry hole, lease impairment and other exploration expenses	—		—		—		(150)
Crude oil inventories write-down	—		—		—		(52)


	$	(147)	$	—	$	(147)	$	(2,251)

PART I - FINANCIAL INFORMATION (CONT'D.)

Consolidated Results of Operations (continued)

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020

	(In millions)

Impairment and other	$	(147)	$	—	$	(147)	$	(2,126)
Dry hole, lease impairment and other exploration expenses	—		—		—		(152)
Crude oil inventories write-down	—		—		—		(53)


	$	(147)	$	—	$	(147)	$	(2,331)

Impairment and other: In the second quarter of 2021, we recorded a charge of $147 million ($147 million after income taxes) for the total estimated future abandonment obligations of the West Delta Field in the Gulf of Mexico. In June 2021, the U.S. Bankruptcy Court approved Fieldwood’s bankruptcy plan which includes discharging decommissioning obligations, subject to conditions precedent, for certain of Fieldwood’s assets. Those obligations will transfer to former owners of the properties, including us with respect to the West Delta Field, which we sold in 2004. Potential recoveries from other parties that previously owned an interest in the West Delta Field have not been recognized as of June 30, 2021. See Note 10, Guarantees and Contingencies in the Notes to Consolidated Financial Statements.

In the first quarter of 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 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 7, Impairment and Other 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 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 $53 million ($52 million after income taxes) to reduce crude oil inventories to their net realizable value.

Midstream

Following is a summarized income statement for our Midstream operations:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020

	(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues	$	294	$	270	$	583	$	561
Other, net	3		1		6		3
Total revenues and non-operating income	297		271		589		564
Costs and Expenses
Operating costs and expenses	64		95		124		187
General and administrative expenses	4		4		11		12
Interest expense	23		23		46		48
Depreciation, depletion and amortization	41		39		81		77
Total costs and expenses	132		161		262		324
Results of Operations Before Income Taxes	165		110		327		240
Provision (benefit) for income taxes	3		2		6		4
Net Income (Loss)	162		108		321		236
Less: Net income (loss) attributable to noncontrolling interests	86		57		170		124
Net Income (Loss) Attributable to Hess Corporation	$	76	$	51	$	151	$	112

PART I - FINANCIAL INFORMATION (CONT'D.)

Consolidated Results of Operations (continued)

Sales and other operating revenues for the second quarter and first six months of 2021 increased, compared to the corresponding periods in 2020, primarily due to higher minimum volume commitments and tariff rates partially offset by lower pass-through rail transportation revenue. Operating costs and expenses for the second quarter and first six months of 2021 decreased, compared to the corresponding periods in 2020, primarily due to lower pass-through transportation costs.

Excluding items affecting comparability of earnings, net income attributable to Hess Corporation from the Midstream segment is estimated to be in the range of $50 million to $60 million in the third quarter of 2021 and in the range of $275 million to $285 million for the full year 2021.

Corporate, Interest and Other

The following table summarizes Corporate, Interest and Other expenses:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020

	(In millions)
Corporate and other expenses	$	29	$	26	$	66	$	65
Interest expense	95		96		189		184
Corporate, Interest and Other expenses before income taxes	124		122		255		249
Provision (benefit) for income taxes	—		—		—		(4)


Total Corporate, Interest and Other Expenses After Income Taxes	$	124	$	122	$	255	$	245

Corporate and other expenses were comparable in the second quarter and first six months of 2021, compared to the corresponding periods in 2020. Interest expense in the first six months of 2021 was higher than the corresponding period in 2020 due to interest incurred on the $1 billion three year term loan entered into in March 2020.

Third quarter 2021 corporate expenses are expected to be in the range of $30 million to $35 million, and interest expense is expected to be in the range of $95 million to $100 million. We estimate corporate expenses for full year 2021 to be in the range of $130 million to $140 million, and interest expense to be approximately $380 million.

Other Items Potentially Affecting Future Results

Our future results may be impacted by a variety of factors, including but not limited to, volatility in the selling prices of crude oil, 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, including risks associated with COVID-19. For a more comprehensive description of the risks that may affect our business, see Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2020.

Liquidity and Capital Resources

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


	June 30, 2021			December 31, 2020

	(In millions, except ratio)
Cash and cash equivalents (a)	$	2,430		$	1,739
Current maturities of long-term debt (b)	511			10
Total debt (c)	8,223			8,296
Total equity	6,532			6,335
Debt to capitalization ratio (d)	47.2		%	47.5		%

(a)Includes $6 million of cash attributable to our Midstream segment at June 30, 2021 (December 31, 2020: $4 million) of which, $4 million is held by Hess Midstream LP at June 30, 2021 (December 31, 2020: $3 million).

(b)Includes $500 million principal amount of our $1 billion term loan maturing in March 2023 that was repaid in July 2021.

(c)At June 30, 2021, includes $1,832 million of debt outstanding from our Midstream segment (December 31, 2020: $1,910 million) that is non-recourse to Hess Corporation.

(d)Total Consolidated Debt of Hess Corporation (including finance leases and excluding Midstream non-recourse debt) as a percentage of Total Capitalization of Hess Corporation as defined under Hess Corporation's term loan and revolving credit facility financial covenants. Total Capitalization excludes the impact of noncash impairment charges and non-controlling interests.

PART I - FINANCIAL INFORMATION (CONT'D.)

Liquidity and Capital Resources (continued)

Cash Flows

The following table summarizes our cash flows:


	Six Months Ended June 30,
	2021		2020

	(In millions)
Net cash provided by (used in):
Operating activities	$	1,376	$	711
Investing activities	(445)		(1,388)
Financing activities	(240)		778
Net Increase (Decrease) in Cash and Cash Equivalents	$	691	$	101

Operating activities: Net cash provided by operating activities was $1,376 million in the first six months of 2021, compared to $711 million in the first six months of 2020. The increase in 2021 operating cash flows primarily reflects higher realized selling prices and the sale of 4.2 million barrels of Bakken crude oil stored on two VLCCs in the first quarter of 2021. Changes in operating assets and liabilities reduced net cash provided by operating activities by $98 million in the first six months of 2021 and $92 million in the first six months of 2020.

Investing activities: Additions to property, plant and equipment of $740 million in the first six months of 2021 were down $657 million compared with the corresponding period in 2020. The decrease primarily reflects reduced drilling activity. Proceeds from asset sales received in the second quarter of 2021 of $297 million related to the sale of our Little Knife and Murphy Creek nonstrategic acreage interests in the Bakken.

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


	Six Months Ended June 30,
	2021		2020

	(In millions)
Additions to property, plant and equipment - E&P:
Capital expenditures incurred - E&P	$	(676)	$	(1,037)
Increase (decrease) in related liabilities	(11)		(213)
Additions to property, plant and equipment - E&P	$	(687)	$	(1,250)
Additions to property, plant and equipment - Midstream:
Capital expenditures incurred - Midstream	$	(70)	$	(136)
Increase (decrease) in related liabilities	17		(11)
Additions to property, plant and equipment - Midstream	$	(53)	$	(147)

Financing activities: Midstream reduced borrowings under its revolving credit facilities by $75 million in the first six months of 2021 and increased borrowings by $72 million in the first six months of 2020. In March of 2020, the Corporation borrowed $1 billion under a new three year term loan that matures in March 2023. We paid common stock dividends totaling $157 million in both the first six months of 2021 and 2020. Net cash distributed to noncontrolling interests was $137 million in the first six months of 2021 and $128 million in the first six months of 2020. Proceeds received from stock options exercised by employees was $75 million in the first six months of 2021 and $15 million in the first six months of 2020. In the first quarter of 2021, we received net proceeds of $70 million from the public offering of 3,450,000 Hess-owned Class A shares in Hess Midstream LP.

Future Capital Requirements and Resources

At June 30, 2021, we had $2.42 billion in cash and cash equivalents, excluding Midstream, and total liquidity of approximately $6.1 billion. On April 13, 2021, we amended the Corporation's fully undrawn $3.5 billion revolving credit facility by extending the facility's expiration date for one year to May 2024. Oil and gas production in 2021, excluding Libya, is forecast to be approximately 295,000 boepd. For the remainder of 2021, we have hedged 120,000 bopd with $55 WTI put options and 30,000 bopd with $60 Brent put options.

PART I - FINANCIAL INFORMATION (CONT'D.)

Liquidity and Capital Resources (continued)

Net cash provided by operating activities was $1,376 million in the first six months of 2021, compared with $711 million in the first six months of 2020. Net cash provided by operating activities before changes in operating assets and liabilities was $1,474 million in the first six months of 2021 and $803 million in the first six months of 2020. Capital expenditures were $746 million in the first six months of 2021 and $1,173 million in the first six months of 2020. In 2021, based on current forward strip crude oil prices, we expect cash flow from operating activities, expected proceeds from the sale of our interests in Denmark and the Class B unit repurchase by HESM Opco, and cash and cash equivalents at June 30, 2021 will be sufficient to fund our capital investment program, the July repayment of $500 million principal amount of our $1 billion term loan maturing in March 2023, and dividends. Depending on market conditions, we may take any of the following steps, or a combination thereof, to improve our liquidity and financial position: reduce the planned capital program and other cash outlays, including dividends, pursue asset sales, borrow against our committed revolving credit facility, or issue debt or equity securities.

The table below summarizes the capacity, usage, and available capacity for borrowings and letters of credit under committed and uncommitted credit facilities at June 30, 2021:


	Expiration Date	Capacity		Borrowings		Letters of Credit Issued		Total Used		Available Capacity

		(In millions)
Hess Corporation
Revolving credit facility	May, 2024	$	3,500	$	—	$	—	$	—	$	3,500
Committed lines	Various (a)	175		—		29		29		146
Uncommitted lines	Various (a)	228		—		228		228		—
Total - Hess Corporation		$	3,903	$	—	$	257	$	257	$	3,646
Midstream
Revolving credit facility (b)	December, 2024	$	1,000	$	109	$	—	$	109	$	891
Total - Midstream		$	1,000	$	109	$	—	$	109	$	891

(a)Committed and uncommitted lines have expiration dates through 2021.

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

Hess Corporation:

On April 13, 2021, we amended the Corporation's fully undrawn $3.5 billion revolving credit facility that had an expiration date in May 2023, by extending the facility for one year to May 2024 and incorporating customary provisions for the eventual replacement of LIBOR, among other changes as set forth in the amended credit agreement. This facility can be used for borrowings and letters of credit. Borrowings on the facility will generally bear interest at 1.40% above LIBOR, though the interest rate is subject to adjustment if the Corporation’s credit rating changes. At June 30, 2021, Hess Corporation had no outstanding borrowings or letters of credit under its revolving credit facility.

In March 2020, we entered into a $1 billion three year term loan agreement with a maturity date of March 16, 2023. Borrowings under the term loan generally bear interest at LIBOR plus an applicable margin of 2.25% until the term loan's first anniversary. The applicable margin varies based on the credit rating of the Corporation’s senior unsecured long-term debt and will increase by 0.25% on each anniversary of the term loan. In July 2021, we repaid $500 million principal amount of the term loan.

The revolving credit facility, including as amended, and term loan are subject to customary representations, warranties, customary events of default and covenants, including a financial covenant limiting the ratio of Total Consolidated Debt to Total Capitalization of the Corporation and its consolidated subsidiaries to 65%, and a financial covenant limiting the ratio of secured debt to Consolidated Net Tangible Assets of the Corporation and its consolidated subsidiaries to 15% (as these capitalized terms are defined in the credit agreement for the revolving credit facility and the term loan agreement). The indentures for the Corporation's fixed-rate public notes limit the ratio of secured debt to Consolidated Net Tangible Assets (as that term is defined in the indentures) to 15%. At June 30, 2021, Hess Corporation was in compliance with these financial covenants.

Two of the three major credit rating agencies that rate our debt have assigned an investment grade rating. In March 2021, Standard and Poor’s Ratings Services affirmed our credit rating at BBB- and revised the outlook to stable (from negative). Fitch Ratings affirmed a BBB- credit rating and stable outlook in August 2020 and Moody’s Investors Service affirmed our credit rating at Ba1 with stable outlook, which is below investment grade, in March 2020.

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

PART I - FINANCIAL INFORMATION (CONT'D.)

Liquidity and Capital Resources (continued)

Midstream:

At June 30, 2021, Hess Midstream Operations LP (formerly Hess Midstream Partners LP, or HESM Opco), a consolidated subsidiary of Hess Midstream LP, had $1.4 billion of senior secured syndicated credit facilities maturing December 16, 2024, consisting of a $1.0 billion 5-year revolving credit facility and a fully drawn $400 million 5-year term loan A facility. The revolving credit facility can be used for borrowings and letters of credit to fund HESM Opco’s operating activities, capital expenditures, distributions and for other general corporate purposes. Borrowings under the five year term loan A facility will generally bear interest at LIBOR plus an applicable margin ranging from 1.55% to 2.50%, while the applicable margin for the five year syndicated revolving credit facility ranges from 1.275% to 2.000%. Pricing levels for the facility fee and interest-rate margins are based on HESM Opco’s ratio of total debt to EBITDA (as defined in the credit facilities). If HESM Opco obtains an investment grade credit rating, the pricing levels will be based on HESM Opco’s credit ratings in effect from time to time. The credit facilities contain covenants that require HESM Opco to maintain a ratio of total debt to 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 investment grade credit rating, a ratio of secured debt to EBITDA for the prior four fiscal quarters of not greater than 4.00 to 1.00 as of the last day of each fiscal quarter. HESM Opco was in compliance with these financial covenants at June 30, 2021. The credit facilities are secured by first-priority perfected liens on substantially all the presently owned and after-acquired assets of HESM Opco and its direct and indirect wholly owned material domestic subsidiaries, including equity interests directly owned by such entities, subject to certain customary exclusions. At June 30, 2021, borrowings of $109 million were drawn under HESM Opco’s revolving credit facility, and borrowings of $395 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.

Market Risk Disclosures

We are exposed in the normal course of business to commodity risks related to changes in the prices of crude oil and natural gas, as well as changes in interest rates and foreign currency values. See Note 12, Financial Risk Management Activities, in the Notes to Consolidated Financial Statements.

We have outstanding foreign exchange contracts with notional amounts totaling $91 million at June 30, 2021 that are used to reduce our exposure to fluctuating foreign exchange rates for various currencies. A 10% strengthening or weakening in the U.S. Dollar exchange rate is estimated to be a gain or loss of less than $5 million, respectively, at June 30, 2021.

At June 30, 2021, consolidated long-term debt, which was substantially comprised of fixed-rate instruments, had a carrying value of $8,223 million and a fair value of $9,749 million. A 15% increase or decrease in interest rates would decrease or increase the fair value of debt by approximately $370 million or $375 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 June 30, 2021, we have outstanding WTI and Brent crude oil put option contracts. As of June 30, 2021, an assumed 10% increase in the forward WTI and Brent crude oil prices would reduce the fair value of these derivative instruments by approximately $10 million, while an assumed 10% decrease in the same crude oil prices would increase the fair value of these derivative instruments by approximately $15 million.

PART I - FINANCIAL INFORMATION (CONT'D.)

Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q, including information incorporated by reference herein, contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the 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 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, NGL and natural gas and our associated realized price differentials; our projected budget and capital and exploratory expenditures; expected timing and completion of our development projects, proposed asset sale and the Midstream Class B unit repurchase; and future economic and market conditions in the oil and gas industry.

Forward-looking statements are based on our current understanding, assessments, estimates and 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 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:

•fluctuations in market prices of crude oil, NGL and natural gas and competition in the oil and gas exploration and production industry, including as a result of COVID-19;

•reduced demand for our products, including due to COVID-19 or the outbreak of any other public health threat, or due to the impact of competing or alternative energy products and political conditions and events;

•potential failures or delays in increasing oil and gas reserves, including as a result of unsuccessful exploration activity, drilling risks and unforeseen reservoir conditions, and in achieving expected production levels;

•changes in tax, property, contract and other laws, regulations and governmental actions applicable to our business, including legislative and regulatory initiatives regarding environmental concerns, such as measures to limit greenhouse gas emissions and flaring as well as fracking bans;

•disruption or interruption of our operations due to catastrophic events, such as accidents, severe weather, geological events, shortages of skilled labor, cyber-attacks or health measures related to COVID-19;

•the ability of our contractual counterparties to satisfy their obligations to us, including the operation of joint ventures under which we may not control;

•the ability to satisfy the closing conditions of the proposed asset sale and the Midstream Class B unit repurchase;

•unexpected changes in technical requirements for constructing, modifying or operating exploration and production facilities and/or the inability to timely obtain or maintain necessary permits;

•availability and costs of employees and other personnel, drilling rigs, equipment, supplies and other required services;

•any limitations on our access to capital or increase in our cost of capital, including as a result of weakness in the oil and gas industry or negative outcomes within commodity and financial markets;

•liability resulting from litigation, including exposure to decommissioning liabilities for divested assets in the event the current or future owners are unable to perform, and heightened risks associated with being a general partner of Hess Midstream LP; and

•other factors described in the section entitled “Risk Factors” in Item 1A—Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2020 as well as any additional risks described in our other filings with the SEC.

As and when made, we believe that 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 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 because of new information, future events or otherwise.

PART I - FINANCIAL INFORMATION (CONT'D.)

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

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

Item 4. Controls and Procedures.

Based upon their evaluation of the Corporation’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of June 30, 2021, John B. Hess, Chief Executive Officer, and John P. Rielly, Chief Financial Officer, concluded that these disclosure controls and procedures were effective as of June 30, 2021.

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 June 30, 2021 that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

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

PART II – OTHER INFORMATION (CONT'D)

Item 6. Exhibits.


Exhibits
4(1)			Extension and Amendment Agreement, dated as of April 13, 2021, 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 13, 2021 .
10(1)*			Amendment No. 1 to the Hess Corporation 2017 Long-Term Incentive Plan incorporated by reference to Exhibit 10(1) of Form 8-K of the Registrant, filed on June 3, 2021.
10(2)*			Change in Control Termination Benefits Agreement, dated as of August 3, 2015, between the Registrant and Barbara Lowery-Yilmaz.
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- 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 Taxonomy Extension Label Linkbase Document.
101(PRE)			Inline XBRL Taxonomy Extension Presentation Linkbase Document.
101(DEF)			Inline XBRL Taxonomy Extension Definition Linkbase Document.
104			The cover page from the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, has been formatted in Inline XBRL.

* The exhibit relates to executive compensation plans and arrangements.

SIGNATURES

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


HESS CORPORATION
(REGISTRANT)


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


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

Date: August 5, 2021

Document

Exhibit 10(2)

CHANGE IN CONTROL

TERMINATION BENEFITS AGREEMENT

THIS CHANGE IN CONTROL TERMINATION BENEFITS AGREEMENT (the “Agreement”), dated as of the 3rd day of August, 2015, is between Hess Corporation, a Delaware corporation (the “Company”), and Barbara Lowery-Yilmaz (the “Executive”).

WITNESSETH:

WHEREAS, the Company considers it essential to the best interests of the Company and its stockholders that its management be encouraged to remain with the Company and to continue to devote full attention to the Company’s business in the event of a transaction or series of transactions that could result in a change in control of the Company through a tender offer or otherwise;

WHEREAS, the Company recognizes that the possibility of a change in control and the uncertainty which it may raise among management may result in the departure or distraction of management personnel to the detriment of the Company and its stockholders;

WHEREAS, the Executive is a key executive of the Company;

WHEREAS, the Company believes the Executive has made valuable contributions to the productivity and profitability of the Company;

WHEREAS, should the Company receive a proposal for, or otherwise consider any such transaction, in addition to the Executive’s regular duties, the Executive may be called upon to assist in the assessment of such proposals, advise management and the Board of Directors of the Company (the “Board”) as to whether a proposed transaction would be in the best interests of the Company and its stockholders, and to take such other actions as the Board might determine to be appropriate;

WHEREAS, the Board has determined that it is in the best interests of the Company and its stockholders to assure that the Company will have the continued services of the Executive, notwithstanding the possibility, threat or occurrence of a change in control of the Company and believes that it is imperative to diminish the potential distraction of the Executive by virtue of the personal uncertainties and risks created by a pending or threatened change in control, to assure the Executive’s full attention and dedication to the Company in the event of any threatened or pending change in control, and to provide the Executive with appropriate severance arrangements following a change in control; and

WHEREAS, the Company intends that the Agreement comply with, or not be subject to, section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), and guidance and regulations issued thereunder, so that, notwithstanding any other provision of the Agreement, the Agreement shall be interpreted, operated and administered in a manner consistent with this intention.

NOW, THEREFORE, to assure the Company that it will have the continued undivided attention and services of the Executive and the availability of the Executive’s advice and counsel notwithstanding the possibility, threat or occurrence of a change in control of the Company, and to induce the Executive to remain in the employ of the Company and for other good and valuable consideration, the receipt of which is hereby acknowledged, the parties hereto, each intending to be legally bound hereby, agree as follows:

1.Change in Control.

For purposes of the Agreement, a Change in Control shall be deemed to have taken place if any of the following shall occur:

(a) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934 (the “Exchange Act”)), of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either the then (i) outstanding shares of Common Stock of the Company (the “Outstanding Company Common Stock”) or (ii) combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Voting Securities”) provided, however, that the following acquisitions shall not constitute a Change in Control: (i) any acquisition by the Company or any of its subsidiaries, (ii) any acquisition by an employee benefit plan (or related trust) sponsored or maintained by the Company or any of its subsidiaries, (iii) any acquisition by any company with respect to which, following such acquisition, more than 60% of, respectively, the then outstanding shares of common stock of such company and the combined voting power of the then outstanding voting securities of such company entitled to vote generally in the election of directors is then beneficially owned, directly or indirectly, by all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Voting Securities immediately prior to such acquisition in substantially the same proportions as their ownership, immediately prior to such acquisition, of the Outstanding Company Common Stock and Outstanding Voting Securities, as the case may be, or (iv) any acquisition by one or more Hess Entity (for this purpose a “Hess Entity” means (A) Mr. John Hess or any of his children, parents or siblings, (B) any spouse of any person described in Section (A) above, (C) any trust with respect to which any of the persons described in (A) has substantial voting authority (D) any affiliate (as such term is defined in Rule 12b-2 under the Exchange Act) of any person described in (A) above, (E) the Hess Foundation Inc., or (F) any persons

comprising a group controlled (as such term is defined in such Rule 12b-2) by one or more of the foregoing persons or entities described in this Section 1(a)(iv)); or

(b) Within any 24 month period, individuals who, immediately prior to the beginning of such period, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director during such period whose election, or nomination for election by the Company’s stockholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of either an actual or threatened solicitation to which Rule 14a-ll of Regulation 14A promulgated under the Exchange Act applies or other actual or threatened solicitation of proxies or consents; or

(c) Consummation of a reorganization, merger or consolidation, in each case, with respect to which all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Voting Securities immediately prior to such reorganization, merger or consolidation do not, following such reorganization, merger or consolidation, beneficially own, directly or indirectly, more than 60% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the company resulting from such reorganization, merger or consolidation in substantially the same proportions as their ownership, immediately prior to such reorganization, merger or consolidation, of the Outstanding Company Common Stock and Outstanding Voting Securities, as the case may be; or

(d) Consummation of (i) a complete liquidation or dissolution of the Company or (ii) the sale or other disposition of all or substantially all of the assets of the Company, other than to a company, with respect to which following such sale or other disposition, more than 60% of, respectively, the then outstanding shares of common stock of such company and the combined voting power of the then outstanding voting securities of such company entitled to vote generally in the election of directors is then beneficially owned, directly or indirectly, by all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Voting Securities immediately prior to such sale or other disposition in substantially the same proportion as their ownership, immediately prior to such sale or other disposition, of the Outstanding Company Common Stock and Outstanding Voting Securities, as the case may be. The term “the sale or other disposition of all or substantially all of the assets of the Company” shall mean a sale or other disposition in a transaction or series of related transactions involving assets of the Company or of any direct or indirect subsidiary of the Company (including the stock of any direct or indirect subsidiary of the Company) in which the value of the assets or stock being sold or otherwise disposed of (as measured by the purchase price being paid therefor or by such other method as the Board determines is appropriate in a case where there is no readily

ascertainable purchase price) constitutes more than two-thirds of the fair market value of the Company (as hereinafter defined). The “fair market value of the Company” shall be the aggregate market value of the then Outstanding Company Common Stock (on a fully diluted basis) plus the aggregate market value of the Company’s other outstanding equity securities. The aggregate market value of the shares of Outstanding Company Common Stock shall be determined by multiplying the number of shares of such Common Stock (on a fully diluted basis) outstanding on the date of the execution and delivery of a definitive agreement with respect to the transaction or series of related transactions (the “Transaction Date”) by the average closing price of the shares of Outstanding Company Common Stock for the ten trading days immediately preceding the Transaction Date. The aggregate market value of any other equity securities of the Company shall be determined in a manner similar to that prescribed in the immediately preceding sentence for determining the aggregate market value of the shares of Outstanding Company Common Stock or by such other method as the Board shall determine is appropriate.

2. Circumstances Triggering Receipt of Termination Benefits.

(a) Subject to Section 2(c), the Company will provide the Executive with the benefits set forth in Section 4 upon the Executive’s Separation from Service that is initiated:

(i) by the Company at any time within the first 24 months after a Change in Control;

(ii) by the Executive for “Good Reason” (as defined in Section 2(b) below) at any time within the first 24 months after a Change in Control; or

(iii) by the Company or the Executive pursuant to Section 2(d).

For purposes of this Agreement, the term “Separation from Service” or “Separate(s/d) from Service” means a “separation from service” within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”) and Treasury Regulations thereunder.

(b) In the event of a Change in Control, the Executive may Separate from Service for “Good Reason” and receive the payments and benefits set forth in Section 4 upon the occurrence of one or more of the following events (regardless of whether any other reason, other than Cause as provided below, for such Separation from Service exists or has occurred):

(i) Failure to elect or reelect or otherwise to maintain the Executive in the office or the position, or at least a substantially equivalent office or position, of or with the Company (or any successor thereto), which the Executive held immediately prior to a Change in Control, or the removal of the Executive as a

director of the Company (or any successor thereto), if the Executive shall have been a director of the Company immediately prior to the Change in Control;

(ii) (A) Any material adverse change in the nature or scope of the Executive’s authorities, powers, functions, responsibilities or duties from those in effect immediately prior to the Change in Control, (B) a reduction in the Executive’s annual base salary rate, (C) a reduction in the Executive’s annual incentive compensation target or any material reduction in the Executive’s other bonus opportunities, or (D) the termination or denial of the Executive’s ability to participate in Employee Benefits (as defined in Section 4(b)) or retirement benefits (as described in Section 4(c)) or a material reduction in the scope or value thereof, any of which is not remedied by the Company within 10 days after receipt by the Company of written notice from the Executive of such change, reduction or termination, as the case may be;

(iii) The liquidation, dissolution, merger, consolidation or reorganization of the Company or transfer of all or substantially all of its businesses and/or assets, unless the successor or successors (by liquidation, merger, consolidation, reorganization, transfer or otherwise) to which all or substantially all of its businesses and/or assets have been transferred (directly or by operation of law) assumed all duties and obligations of the Company under this Agreement pursuant to Section 9(a);

(iv) The Company requires the Executive to change the Executive’s principal location of work to a location that is in excess of 30 miles from the location thereof immediately prior to the Change in Control, or requires the Executive to travel in the course of discharging the Executive’s responsibilities or duties at least 20% more (in terms of aggregate days in any calendar year or in any calendar quarter when annualized for purposes of comparison to any prior year) than was required of the Executive in any of the three full years immediately prior to the Change in Control without, in either case, the Executive’s prior written consent;

(v) Without limiting the generality or effect of the foregoing, any material breach of this Agreement by the Company or any successor thereto, which breach is not remedied within 10 days after written notice to the Company from the Executive describing the nature of such breach.

(c) Notwithstanding Sections 2(a) and (b) above, no benefits shall be payable by reason of this Agreement in the event of:

(i) The Executive’s Separation from Service by reason of the Executive’s death or Disability, unless the Executive has previously given a valid “Notice of Termination” pursuant to Section 3. For purposes hereof, “Disability” shall be defined as the inability of the Executive due to illness, accident or other physical

or mental disability to perform the Executive’s duties for any period of six consecutive months or for any period of eight months out of any 12-month period, as determined by an independent physician selected by the Executive (or the Executive’s legal representative) and reasonably acceptable to the Company, provided that the Executive does not return to work on substantially a full-time basis within 30 days after written notice from the Company, pursuant to Section 3, of the intent to terminate the Executive’s employment due to Disability;

(ii) The Executive’s retirement on or after Normal Retirement Date pursuant to the Company’s Employees’ Pension Plan; provided, however, that if the Executive Separates from Service for Good Reason at such time of retirement, the Executive’s retirement shall be treated hereunder as a Separation from Service for Good Reason and the Executive shall be entitled to the benefits provided in Section 4 hereof;

(iii) The Executive’s Separation from Service for Cause. For the purposes hereof, “Cause” shall be defined as (A) a felony conviction of the Executive or the failure of the Executive to contest prosecution for a felony, (B) the Executive’s gross and willful misconduct in connection with the performance of the Executive’s duties with the Company and/or its subsidiaries or (C) the willful and continued failure of the Executive to substantially perform the Executive’s duties with the Company (or any successor thereto) after a written demand from the Company’s internal Executive Committee, any successor or similar internal management committee or, absent any such committee, its Chief Executive Officer (such committee, or the Chief Executive Officer, being the “Notifying Party”) for substantial performance which specifically identifies the manner in which the Notifying Party believes that the Executive has not performed the Executive’s duties with the Company, any of which is directly and materially harmful to the business or reputation of the Company or any subsidiary or affiliate. Notwithstanding the foregoing, the Executive shall not be deemed to have Separated from Service for “Cause” hereunder unless and until the Executive shall have been afforded, after reasonable notice, an opportunity to appear, together with counsel (if the Executive chooses to have counsel present), before the Notifying Party, if the Notifying Party is a committee, or in the event that the Notifying Party is the Chief Executive Officer, the three most highly compensated senior executive officers of the Company, not including the Chief Executive Officer (such Notifying Party or the three senior executive officers, as the case may be, being the “Hearing Party”), and after such hearing there shall have been delivered to the Executive a written determination by the Hearing Party that, in the good faith opinion of the Hearing Party the Executive shall have been Separated from Service for “Cause” as herein defined and specifying the particulars thereof in detail. Nothing herein will limit the right of the Executive or the Executive’s beneficiaries to contest the validity or propriety of any such determination. This Section 2(c) shall not preclude the payment of any amounts

otherwise payable to the Executive under any of the Company’s employee benefit plans, pension plans, stock plans, programs and arrangements.

(d) A Separation from Service initiated by the Company without Cause or by the Executive for an event that would constitute Good Reason following a Change in Control that occurs, in either event, prior to a Change in Control, but occurs (i) not more than 180 days prior to the date on which a Change in Control occurs and (ii) (x) at the request of a third party who has indicated an intention or taken steps reasonably calculated to effect a Change in Control or (y) otherwise arose in connection with, or in anticipation of, a Change in Control, shall be deemed to be a Separation from Service without Cause within the first 24 months after a Change in Control for purposes of this Agreement and the date of such Change in Control shall be deemed to be the date immediately preceding the date the Executive’s Separation from Service.

3. Notice of Termination.

Any Separation from Service as contemplated by Section 2 shall be communicated by written “Notice of Separation” to the other party hereto. Any “Notice of Separation” shall (i) indicate the effective date of the Separation from Service, which shall not be less than 30 days or more than 60 days after the date the Notice of Separation is delivered (the “Separation Date”), (ii) cite the specific provision in this Agreement relied upon, and (iii) except for a Separation from Service pursuant to Section 2(d), shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for such Separation from Service including, if applicable, the failure by the Company, after provision of written notice by the Executive, to effect a remedy pursuant to the final clause of Section 2(b)(ii) or 2(b)(v).

4. Benefits upon Separation from Service.

Subject to the conditions set forth in Section 2, the following benefits shall be paid or provided to the Executive:

(a) Compensation.

The Company shall pay to the Executive two times the sum of (i) “Base Pay”, which shall be an amount equal to the greater of (A) the Executive’s rate of annual base salary (prior to any deferrals) on the date of the Executive’s Separation from Service, or (B) the Executive’s rate of annual base salary (prior to any deferrals) immediately prior to the Change in Control, plus (ii) “Incentive Pay”, which shall be an amount equal to the greater of (X) the target annual bonus payable to the Executive under the Company’s incentive compensation plan or any other annual bonus plan for the fiscal year of the Company in which the

Change in Control occurred or (Y) the highest annual bonus earned by the Executive under the Company’s incentive compensation plan or any other annual bonus plan (whether paid currently or on a deferred basis) during the three fiscal years of the Company immediately preceding the fiscal year of the Company in which the Change in Control occurred. In addition, the Executive shall receive a pro rata portion of the target bonus for the fiscal year in which the Executive’s termination of employment occurs.

The amount payable under Section 4(a) shall be paid to the Executive in a lump sum payment by the 60th day following the date of the Executive’s Separation from Service. Notwithstanding the foregoing, payment of such amounts may not be made to a Key Employee (as defined in Section 4(g)) upon a Separation from Service before the date which is six months after the date of the Key Employee’s Separation from Service (or, if earlier, the date of death of the Key Employee). Any payments that would otherwise be made during this period of delay shall be accumulated and paid on the first day of the seventh month following the date of the Executive’s Separation from Service (or, if earlier, the first day of the month after the Participant’s death).

In the event payment of the amount payable under Section 4(a) is delayed for six months pursuant to the immediately preceding paragraph, the Company shall as soon as administratively practicable following the date of the Executive’s Separation from Service (i) establish an irrevocable grantor trust of which the Company is the grantor, and a bank or trust company reasonably acceptable to the Executive is the trustee (the “Grantor Trust”), and (ii) contribute to the Grantor Trust the full such amount payable under Section 4(a). The Grantor Trust shall be a “rabbi trust,” the assets of which shall be used solely for the purpose of satisfying the Company’s obligations under Section 4(a) of this Agreement; provided, however, that such assets shall be subject to the claims of the Company’s general creditors in the event of the Company’s bankruptcy (or similar insolvency proceeding), and the Grantor Trust shall not cause any amount payable under this Agreement to be funded for tax purposes.

(b) Welfare Benefits.

For a period of 24 months following the date of the Executive’s Separation from Service (the “Continuation Period”), the Company shall arrange to provide the Executive with benefits (the “Employee Benefits”), including travel accident, major medical, dental care and other welfare benefit programs, substantially similar to those in effect immediately prior to the Change in Control, or, if greater, to those that the Executive was receiving or entitled to receive immediately prior to the date of the Executive’s Separation from Service (or, if greater, immediately prior to the reduction, termination, or denial described in Section 2(b)(ii)(D)). If and to the extent that any benefit described in this Section 4(b) is not or cannot be paid or provided under any policy, plan, program or arrangement of the Company or any subsidiary, as the case may be, then the Company will itself pay or provide for the payment to the Executive, the Executive’s dependents and beneficiaries of such Employee Benefits along with, in the case of any benefit which is subject to tax because it is not or cannot be paid or provided under any such policy, plan, program or arrangement of the Company or any subsidiary, an additional amount such that after payment by the Executive, or the Executive’s dependents or beneficiaries, as the case may be, of all taxes so imposed, the recipient retains an amount equal to such

taxes. Employee Benefits otherwise receivable by the Executive pursuant to this Section 4(b) will be reduced to the extent comparable welfare benefits are actually received by the Executive from another employer during the Continuation Period, and any such benefits actually received by the Executive shall be reported by the Executive to the Company. In addition, the Executive shall receive additional age and service credit for the Continuation Period for purposes of the Executive’s eligibility to receive any retiree medical benefits.

To the extent the continuation of the Employee Benefits under this Section 4(b) is, or ever becomes, taxable to the Executive and to the extent the Employee Benefits that are medical benefits continue beyond the period in which the Executive would be entitled (or would, but for this Agreement, be entitled) to continuation coverage under a group health plan of the Company under Code section 4980B (COBRA) if the Executive elected such coverage and paid the applicable premiums, the Company shall administer such continuation of coverage consistent with the following additional requirements as set forth in Treas. Reg. § 1.409A-3(i)(1)(iv):

(i) The Executive’s eligibility for Employee Benefits in one year shall not affect the Executive’s eligibility for Employee Benefits in any other year;

(ii) Any reimbursement of eligible expenses will be made on or before the last day of the year following the year in which the expense was incurred; and

(iii) Executive’s right to Employee Benefits shall not be subject to liquidation or exchange for another benefit.

In the event the preceding sentence applies and the Executive is a Key Employee (as defined in Section 4(g)), provision of Employee Benefits after the COBRA period shall commence on the first day of the seventh month following the date of the Executive’s Separation from Service (or, if earlier, the first day of the month after the Executive’s death).

The Executive shall be deemed to be completely vested in the Executive’s currently accrued benefits under the Company’s Employees’ Pension Plan and the Company’s Pension Restoration Plan or other supplemental pension plan (“SERP”) in effect as of the date of the Change in Control (collectively, the “Plans”), regardless of the Executive’s actual vesting service credit thereunder. In addition, the Executive shall be deemed to earn age and service credit for benefit calculation purposes thereunder for the Continuation Period. The additional retirement benefits to be paid pursuant to the Plans shall be calculated as though the Executive’s compensation rate for the years during the Continuation Period equaled the sum of Base Pay plus Incentive Pay. Any benefits payable pursuant to this Section 4(c) that are not payable out of the Plans for any reason (including but not limited to any applicable benefit limitations under the Employee

Retirement Income Security Act of 1974, as amended, or any restrictions relating to the qualification of the Company’s Employees’ Pension Plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (the “Code”)) shall be paid directly by the Company out of its general assets at the time and form in which such benefits would have been payable under the applicable Plan.

(d) Stock Based Compensation Plans.

(i) Any issued and outstanding stock options shall vest and become exercisable on the date of the Executive’s Separation from Service (to the extent they have not already become vested and exercisable) and any other stock-based awards under any compensation plan or program maintained by the Company (including, without limitation, awards of restricted stock and book value appreciation units) and the Executive’s rights thereunder shall vest on the date of the Executive’s Separation from Service (to the extent they have not already vested) and any performance criteria under any such compensation plan or program shall be deemed met at target as of the date of the Executive’s Separation from Service.

(ii) If and to the extent that any benefit or entitlement (or portion thereof) described in paragraph (i) above is not able to be implemented by the Company under the then applicable terms of any plan, program or award agreement applicable to the Executive, to the extent permitted by Code section 409A, the Company shall pay to the Executive cash and/or other property (including, without limitation, common stock of the Company or any successor thereto) with a value, as determined by the Board, equal to the value of any such option, award or other entitlement (or portion thereof) that the Executive was not able to receive under paragraph (i) above, such payment shall be made upon the date provided in Section 4(a) following the Executive’s Separation from Service and such payment shall be in full satisfaction of the option, award or other entitlement (or portion thereof) to which such payment relates.

(e) Defined Contribution Deferred Compensation Plans.

The Company shall pay to the Executive all other amounts of tax-qualified and nonqualified deferred compensation accrued or earned by the Executive through the date of the Executive’s Separation from Service, and amounts otherwise owing under the then existing plans and policies of the Company, other than those amounts described in Section 4(c), including but not limited to, all amounts of compensation previously deferred by the Executive (together with any accrued interest or other earnings thereon) and not yet paid by the Company, under the terms and conditions and time and form of payment of the underlying applicable arrangements, plans or policies of the Company.

(f) Outplacement Services.

If so requested by the Executive, reasonable outplacement services shall be provided to the Executive by a professional outplacement firm or provider selected by the Executive that is reasonably acceptable to the Company at a cost to the Company not in excess of $30,000; provided, however, that such reasonable outplacement expenses must be incurred on or before the last day of the second year following, and payment of such expenses is actually made before the last day of the second year following, the year in which the Executive’s Separation from Service occurred.

(g) Key Employee.

For purposes of this Section 4, the term “Key Employee” means an employee treated as a “specified employee” as of his Separation from Service under Code section 409A(a)(2)(B)(i), i.e., a key employee (as defined in Code section 416(i) without regard to paragraph (5) thereof) of the Company or its affiliates if the Company’s or its affiliate’s stock is publicly traded on an established securities market or otherwise. Key Employees shall be determined in accordance with Code section 409A using a December 31 identification date. A listing of Key Employees as of an identification date shall be effective for the 12-month period beginning on the April 1 following the identification date.

5. Golden Parachute Provisions.

(a) Notwithstanding any provision of this Agreement to the contrary, in the event that any amount or benefit to be paid or provided under this Agreement or otherwise to the Executive constitutes a “parachute payment” within the meaning of Section 280G of the Code, and but for this provision, would be subject to the excise tax imposed by Section 4999 of the Code (such tax or taxes, together with any equivalent state or local excise taxes and any interest and penalties, being hereafter collectively referred to as the “Excise Tax”), then the totality of those amounts shall be either: (a) delivered to the Executive in full, or (b) delivered to the Executive as to such lesser extent which would result in no portion of such payments and benefits being subject to the Excise Tax, whichever of the foregoing amounts, taking into account the applicable federal, state and local income and employment taxes and the Excise Tax, results in the receipt by the Executive on an after-tax basis, of the greatest amount of such payments and benefits, notwithstanding that all or some portion of such amount may be taxable under Section 4999 of the Code. Any reduction of any amount required by this provision shall occur in the following order: (1) reduction of cash payments to the Executive under this Agreement or otherwise; (2) reduction of vesting acceleration of stock options or other stock-based awards under this Agreement or otherwise; and (3) reduction of other benefits paid or provided to the Executive. If two or more stock options or other stock-based awards are granted on the same date, each option or award will be reduced on a pro rata basis (dollar-for-dollar).

(b) Unless the Company and the Executive otherwise agree, any determination required under this Section 5 shall be made in writing by the Company’s outside auditors immediately prior to the Change in Control (the “Accounting Firm”), whose determination shall be conclusive and binding upon the Executive and the Company for all purposes.

(c) The Company and the Executive shall each provide the Accounting Firm access to and copies of any books, records and documents in the possession of the Company or the Executive, as the case may be, reasonably requested by the Accounting Firm, and otherwise cooperate with the Accounting Firm in connection with the preparation and issuance of the determinations and calculations contemplated by Section 5(b).

(d) The fees and expenses of the Accounting Firm for its services in connection with the determinations and calculations contemplated by Section 5(b) shall be borne by the Company.

6. No Mitigation Obligation; Obligations Absolute.

The payment of the severance compensation by the Company to the Executive in accordance with the terms of this Agreement is hereby acknowledged by the Company to be reasonable, and the Executive will not be required to mitigate the amount of any payment or other benefit provided in this Agreement by seeking other employment or otherwise, nor will any profits, income, earnings or other benefits from any source whatsoever create any mitigation, offset, reduction or any other obligation on the part of the Executive hereunder or otherwise, except as expressly provided in the second to last sentence of Section 4(b). The obligations of the Company to make the payments and provide the benefits provided herein to the Executive are absolute and unconditional and may not be reduced under any circumstances, including without limitation any set-off, counterclaim, recoupment, defense or other right which the Company may have against the Executive or any third party at any time.

7. Legal Fees and Expenses.

It is the intent of the Company that the Executive not be required to incur legal fees and the related expenses associated with the interpretation, enforcement or defense of the Executive’s rights under this Agreement by litigation or otherwise because the cost and expense thereof would substantially detract from the benefits intended to be extended to the Executive hereunder. Accordingly, if, following a Change in Control, it should appear to the Executive that the Company has failed to comply with any of its obligations under this Agreement or in the event that the Company or any other person takes or threatens to take any action to declare this Agreement void or unenforceable, or institutes any litigation or other action or proceeding designed to deny, or to recover from, the Executive any or all of the benefits provided or intended to be provided to the Executive

hereunder, the Company irrevocably authorizes the Executive from time to time to retain counsel of the Executive’s choice, at the expense of the Company as hereafter provided, to advise and represent the Executive in connection with any such interpretation, enforcement or defense, including without limitation the initiation or defense of any litigation or other legal action, whether by or against the Company or any director, officer, stockholder or other person affiliated with the Company, in any jurisdiction. Notwithstanding any existing or prior attorney-client relationship between the Company and such counsel, the Company irrevocably consents to the Executive’s entering into an attorney-client relationship with such counsel, and in that connection the Company and the Executive agree that a confidential relationship shall exist between the Executive and such counsel. Without respect to whether the Executive prevails, in whole or in part, in connection with any of the foregoing, the Company will pay and be solely financially responsible for all reasonable attorneys’ fees and related expenses incurred by the

Executive in good faith in connection with any of the foregoing; provided, however, that the Company shall have no obligation hereunder to pay any attorneys’ fees or related expenses with respect to any frivolous claims made by the Executive. Payments by the Company shall be made in accordance with the rules immediately below, upon written request of the Executive which must be accompanied by such evidence of eligible fees and expenses as the Company may reasonably require.

The Company shall administer such reimbursements consistent with the following additional requirements as set forth in Treas. Reg. § 1.409A-3(i)(1)(iv):

(i) The Executive’s eligibility for reimbursement of eligible legal fees and expenses in one year shall not affect Executive’s eligibility for eligible legal fees in any other year;

(ii) Any reimbursement of eligible legal fees and expenses shall be made on or before the last day of the year following the year in which the expense was incurred; and

(iii) The Executive’s right to the reimbursement of eligible legal fees and expenses shall not be subject to liquidation or exchange for another benefit.

8. Continuing Obligations.

The Executive hereby agrees that all documents, records, techniques, business secrets and other information which have come into the Executive’s possession from time to time during the Executive’s employment with the Company shall be deemed to be confidential and proprietary to the Company and, except for personal documents and records of the Executive, shall be returned to the Company. The Executive further agrees to retain in confidence any confidential information known to him concerning the Company and its subsidiaries and their respective businesses so long as such information is not otherwise publicly disclosed, except that Executive may disclose any such information required to be disclosed in the normal course of the Executive’s employment

with the Company or pursuant to any court order or other legal process or as necessary to enforce the Executive’s rights under this Agreement.

9. Successors.

(a) The Company shall require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company, by agreement in form and substance reasonably satisfactory to the Executive to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place. Failure of such successor entity to enter into such agreement prior to the effective date of any such succession (or, if later, within three business days after first receiving a written request for such agreement) shall constitute a breach of this Agreement and shall entitle the Executive to terminate employment pursuant to Section 2(a) (ii) and to receive the payments and benefits provided under Section 4. As used in this Agreement, “Company” shall mean the Company as herein before defined and any successor to its business and/or assets as aforesaid which executes and delivers the Agreement provided for in this Section 9 or which otherwise becomes bound by all the terms and provisions of this Agreement by operation of law.

(b) This Agreement shall inure to the benefit of and be enforceable by the Executive’s personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. If the Executive dies while any amounts are payable to him hereunder, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to the Executive’s designee or, if there is no such designee, to the Executive’s estate.

10. Notices.

For all purposes of this Agreement, all communications, including without limitation notices, consents, requests or approvals, required or permitted to be given hereunder will be in writing and will be deemed to have been duly given when hand delivered or dispatched by electronic facsimile transmission (with receipt thereof orally confirmed), or five business days after having been mailed by United States registered or certified mail, return receipt requested, postage prepaid, or three business days after having been sent by a nationally recognized overnight courier service such as FedEx, UPS, or Purolator, addressed to the Company (to the attention of the Secretary of the Company, with a copy to the General Counsel of the Company) at its principal executive office and to the Executive at the Executive’s principal residence, or to such other address as any party may have furnished to the other in writing and in accordance herewith, except that notices of changes of address shall be effective only upon receipt.

11. Governing Law.

THE VALIDITY, INTERPRETATION, CONSTRUCTION AND PERFORMANCE OF THIS AGREEMENT SHALL BE GOVERNED BY THE LAWS OF THE STATE OF NEW YORK.

12. Miscellaneous.

No provisions of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in a writing signed by the Executive and the Company. No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or any prior or subsequent time. No agreements or representations, oral or otherwise, express or implied, with respect to the subject matter hereof have been made by either party which are not set forth expressly in this Agreement (or in any employment or other written agreement relating to the Executive). Nothing expressed or implied in this Agreement will create any right or duty on the part of the Company or the Executive to have the Executive remain in the employment of the Company or any subsidiary prior to or following any Change in Control. The Company may withhold from any amounts payable under this Agreement all federal, state, city or other taxes as the Company is required to withhold pursuant to any law or government regulation or ruling. In the event that the Company refuses or otherwise fails to make a payment when due and it is ultimately decided that the Executive is entitled to such payment, such payment shall be increased to reflect an interest factor, compounded annually, equal to the prime rate in effect as of the date the payment was first due plus two points. For this purpose, the prime rate shall be based on the rate identified by Chase Manhattan Bank as its prime rate.

13. Separability.

The invalidity or unenforceability of any provisions of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect.

14. Non-assignability.

This Agreement is personal in nature and neither of the parties hereto shall, without the consent of the other, assign or transfer this Agreement or any rights or obligations hereunder, except as provided in Section 9. Without limiting the foregoing, the Executive’s right to receive payments hereunder shall not be assignable or transferable, whether by pledge, creation of a security interest or otherwise, other than a transfer by will or by the laws of descent or distribution, and in the event of any attempted assignment or transfer by the Executive contrary to this Section 14 the Company shall have no liability to pay any amount so attempted to be assigned or

transferred to any person other than the Executive or, in the event of death, the Executive’s designated beneficiary or, in the absence of an effective beneficiary designation, the Executive’s estate.

15. Effectiveness; Term.

This Agreement will be effective and binding as of the date first above written immediately upon its execution and shall continue in effect through the second anniversary of such date; provided, however, that the term of this Agreement shall automatically be extended for an additional day for each day that passes so that there shall at any time be two years remaining in the term unless the Company provides written notice to the Executive that it does not wish the term of this Agreement to continue to be so extended, in which case the Agreement shall terminate on the second anniversary of such notice if there has not been a Change in Control prior to such second anniversary. In the event that a Change in Control has occurred during the term of this Agreement, then this Agreement shall continue to be effective until the second anniversary of such Change in Control. Notwithstanding any other provision of this Agreement, if, prior to a Change in Control, the Executive ceases for any reason to be an employee of the Company and any subsidiary (other than a termination of employment pursuant to Section 2(d) hereof), thereupon without further action the term of this Agreement shall be deemed to have expired and this Agreement will immediately terminate and be of no further effect. For purposes of this Section 15, the Executive shall not be deemed to have ceased to be an employee of the Company and any subsidiary by reason of the transfer of the Executive’s employment between the Company and any subsidiary, or among any subsidiaries. Notwithstanding any provision of this Agreement to the contrary, the parties’ respective rights and obligations under Sections 4 through 9 will survive any termination or expiration of this Agreement or the termination of the Executive’s employment following a Change in Control for any reason whatsoever.

16. Counterparts. This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original but all of which together will constitute one and the same agreement.

17. Prior Agreement. This Agreement supersedes and terminates any and all prior similar agreements by and among Company (and/or a subsidiary) and the Executive.

IN WITNESS WHEREOF, the parties have caused this Agreement to be executed and delivered as of the day and year first above set forth.

HESS CORPORATION

/s/ Barbara Lowery-Yilmaz

By:

/s/ John B. Hess

Barbara Lowery-Yilmaz

Name:

John B. Hess

Title:

Chief Executive Officer

Document

Exhibit 31(1)

CERTIFICATIONS

I, John B. Hess, certify that:

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

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

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

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

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

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

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

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

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

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

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


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

Date: August 5, 2021

Document

Exhibit 31(2)

I, John P. Rielly, certify that:

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

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


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

Date: August 5, 2021

Document

Exhibit 32(1)

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Hess Corporation (the "Corporation") on Form 10-Q for the period ending June 30, 2021 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, John B. Hess, Chief Executive Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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


By						/s/ John B. Hess
						JOHN B. HESS
						CHIEF EXECUTIVE OFFICER
						Date: August 5, 2021

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

Document

Exhibit 32(2)

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Hess Corporation (the "Corporation") on Form 10-Q for the period ending June 30, 2021 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, John P. Rielly, Executive Vice President and Chief Financial Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

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

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


By						/s/ John P. Rielly
						JOHN P. RIELLY
						EXECUTIVE VICE PRESIDENT AND
						CHIEF FINANCIAL OFFICER
						Date: August 5, 2021