.

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, 2019

or

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

For the transition period from                      to                     

Commission File Number 1-1204

HESS CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

DELAWARE

(State or Other Jurisdiction of Incorporation or Organization)

13-4921002

(I.R.S. Employer Identification Number)

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

(Address of Principal Executive Offices)

10036

(Zip Code)

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

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  ☒    No  ☐

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

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

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

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

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

At June 30, 2019, there were 304,480,590 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, 2019, and December 31, 2018	2
	Statement of Consolidated Income for the Three and Six Months Ended June 30, 2019, and 2018	3
	Statement of Consolidated Comprehensive Income for the Three and Six Months Ended June 30, 2019, and 2018	4
	Statement of Consolidated Cash Flows for the Six Months Ended June 30, 2019, and 2018	5
	Statement of Consolidated Equity for the Three and Six Months Ended June 30, 2019, and 2018	6
	Notes to Consolidated Financial Statements (Unaudited)	7
	Note 1 - Basis of Presentation	7
	Note 2 - Leases	8
	Note 3 - Preferred Stock Conversion	10
	Note 4 - Revenue	10
	Note 5 - Inventories	11
	Note 6 - Capitalized Exploratory Well Costs	12
	Note 7 - Hess Infrastructure Partners LP	12
	Note 8 - Retirement Plans	13
	Note 9 - Debt	13
	Note 10 - Weighted Average Common Shares	14
	Note 11 - Guarantees and Contingencies	14
	Note 12 - Segment Information	16
	Note 13 - Financial Risk Management Activities	17
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
3.	Quantitative and Qualitative Disclosures about Market Risk	33
4.	Controls and Procedures	33
	PART II - OTHER INFORMATION
1.	Legal Proceedings	34
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,			December 31,
	2019			2018
	(In millions,
	except share amounts)
Assets
Current Assets:
Cash and cash equivalents	$	2,208		$	2,694
Accounts receivable:
From contracts with customers		868			771
Joint venture and other		192			230
Inventories		278			245
Other current assets		138			519
Total current assets		3,684			4,459
Property, plant and equipment:
Total — at cost		34,098			33,222
Less: Reserves for depreciation, depletion, amortization and lease impairment		17,991			17,139
Property, plant and equipment — net		16,107			16,083
Operating lease right-of-use assets — net		615			—
Finance lease right-of-use assets — net		322			—
Goodwill		360			360
Deferred income taxes		21			21
Other assets		586			510
Total Assets	$	21,695		$	21,433
Liabilities
Current Liabilities:
Accounts payable	$	353		$	495
Accrued liabilities		1,541			1,560
Taxes payable		95			81
Current maturities of long-term debt		14			67
Current portion of operating and finance lease obligations		329			—
Total current liabilities		2,332			2,203
Long-term debt		6,511			6,605
Long-term operating lease obligations		395			—
Long-term finance lease obligations		246			—
Deferred income taxes		418			421
Asset retirement obligations		738			741
Other liabilities and deferred credits		524			575
Total Liabilities		11,164			10,545
Equity
Hess Corporation stockholders’ equity:
Preferred stock, par value $1.00; Authorized — 20,000,000 shares
Series A 8% Cumulative Mandatory Convertible; $1,000 per share liquidation preference; Issued — 0 shares (2018: 574,997)		—			1
Common stock, par value $1.00; Authorized — 600,000,000 shares
Issued — 304,480,590 shares (2018: 291,434,534)		304			291
Capital in excess of par value		5,513			5,386
Retained earnings		4,125			4,257
Accumulated other comprehensive income (loss)		(648	)		(306	)
Total Hess Corporation stockholders’ equity		9,294			9,629
Noncontrolling interests		1,237			1,259
Total equity		10,531			10,888
Total Liabilities and Equity	$	21,695		$	21,433

See accompanying Notes to Consolidated Financial Statements.

2

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED INCOME (UNAUDITED)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019		2018
	(In millions, except per share amounts)
Revenues and Non-Operating Income
Sales and other operating revenues	$	1,660		$	1,534		$	3,232	$	2,880
Gains on asset sales, net		22			11			22		18
Other, net		15			21			42		58
Total revenues and non-operating income		1,697			1,566			3,296		2,956
Costs and Expenses
Marketing, including purchased oil and gas		477			450			885		808
Operating costs and expenses		285			288			551		576
Production and severance taxes		46			42			85		81
Exploration expenses, including dry holes and lease impairment		43			62			77		102
General and administrative expenses		89			129			176		239
Interest expense		97			98			195		201
Loss on debt extinguishment		—			26			—		53
Depreciation, depletion and amortization		494			444			992		861
Total costs and expenses		1,531			1,539			2,961		2,921
Income (Loss) Before Income Taxes		166			27			335		35
Provision (benefit) for income taxes		132			114			226		187
Net Income (Loss)		34			(87	)		109		(152	)
Less: Net income (loss) attributable to noncontrolling interests		40			43			83		84
Net Income (Loss) Attributable to Hess Corporation		(6	)		(130	)		26		(236	)
Less: Preferred stock dividends		—			12			4		23
Net Income (Loss) Attributable to Hess Corporation Common Stockholders	$	(6	)	$	(142	)	$	22	$	(259	)
Net Income (Loss) Attributable to Hess Corporation Per Common Share:
Basic	$	(0.02	)	$	(0.48	)	$	0.07	$	(0.85	)
Diluted	$	(0.02	)	$	(0.48	)	$	0.07	$	(0.85	)
Weighted Average Number of Common Shares Outstanding:
Basic		302.2			297.5			299.8		303.5
Diluted		302.2			297.5			302.1		303.5
Common Stock Dividends Per Share	$	0.25		$	0.25		$	0.50	$	0.50

See accompanying Notes to Consolidated Financial Statements.

3

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
	(In millions)
Net Income (Loss)	$	34		$	(87	)	$	109		$	(152	)
Other Comprehensive Income (Loss):
Derivatives designated as cash flow hedges
Effect of hedge (gains) losses reclassified to income		14			49			(1	)		80
Income taxes on effect of hedge (gains) losses reclassified to income		—			—			—			—
Net effect of hedge (gains) losses reclassified to income		14			49			(1	)		80
Change in fair value of cash flow hedges		—			(13	)		(346	)		(35	)
Income taxes on change in fair value of cash flow hedges		—			—			—			—
Net change in fair value of cash flow hedges		—			(13	)		(346	)		(35	)
Change in derivatives designated as cash flow hedges, after taxes		14			36			(347	)		45
Pension and other postretirement plans
(Increase) reduction in unrecognized actuarial losses		(24	)		5			(18	)		130
Income taxes on actuarial changes in plan liabilities		—			(1	)		—			(31	)
(Increase) reduction in unrecognized actuarial losses, net		(24	)		4			(18	)		99
Amortization of net actuarial losses		12			9			23			21
Income taxes on amortization of net actuarial losses		—			—			—			—
Net effect of amortization of net actuarial losses		12			9			23			21
Change in pension and other postretirement plans, after taxes		(12	)		13			5			120
Other Comprehensive Income (Loss)		2			49			(342	)		165
Comprehensive Income (Loss)		36			(38	)		(233	)		13
Less: Comprehensive income (loss) attributable to noncontrolling interests		40			43			83			84
Comprehensive Income (Loss) Attributable to Hess Corporation	$	(4	)	$	(81	)	$	(316	)	$	(71	)

See accompanying Notes to Consolidated Financial Statements.

4

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS (UNAUDITED)

	Six Months Ended June 30,
	2019			2018
	(In millions)
Cash Flows From Operating Activities
Net income (loss)	$	109		$	(152	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Gains on asset sales, net		(22	)		(18	)
Depreciation, depletion and amortization		992			861
Exploratory dry hole costs		—			13
Exploration lease and other impairment		11			20
Stock compensation expense		48			32
Noncash (gains) losses on commodity derivatives, net		58			85
Provision (benefit) for deferred income taxes and other tax accruals		(1	)		(34	)
Loss on debt extinguishment		—			53
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(70	)		(68	)
(Increase) decrease in inventories		(33	)		1
Increase (decrease) in accounts payable and accrued liabilities		(130	)		(64	)
Increase (decrease) in taxes payable		14			(34	)
Changes in other operating assets and liabilities		(63	)		(60	)
Net cash provided by (used in) operating activities		913			635
Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P		(1,085	)		(793	)
Additions to property, plant and equipment - Midstream		(210	)		(100	)
Payments for Midstream equity investments		(23	)		(41	)
Proceeds from asset sales, net of cash sold		22			33
Other, net		(1	)		(5	)
Net cash provided by (used in) investing activities		(1,297	)		(906	)
Cash Flows From Financing Activities
Net borrowings (repayments) of debt with maturities of 90 days or less		160			—
Debt with maturities of greater than 90 days:
Repayments		(5	)		(591	)
Payments on finance lease obligations		(45	)		—
Common stock acquired and retired		(25	)		(890	)
Cash dividends paid		(164	)		(176	)
Noncontrolling interests, net		(27	)		(23	)
Other, net		4			12
Net cash provided by (used in) financing activities		(102	)		(1,668	)
Net Increase (Decrease) in Cash and Cash Equivalents		(486	)		(1,939	)
Cash and Cash Equivalents at Beginning of Year		2,694			4,847
Cash and Cash Equivalents at End of Period	$	2,208		$	2,908

See accompanying Notes to Consolidated Financial Statements.

5

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED EQUITY (UNAUDITED)

	Mandatory Convertible Preferred Stock			Common Stock			Capital in Excess of Par			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Hess Stockholders' Equity			Noncontrolling Interests			Total Equity
	(In millions)
For the Three Months Ended June 30, 2019
Balance at April 1, 2019	$	—		$	304		$	5,481		$	4,207		$	(650	)	$	9,342		$	1,211		$	10,553
Net income (loss)		—			—			—			(6	)		—			(6	)		40			34
Other comprehensive income (loss)		—			—			—			—			2			2			—			2
Share-based compensation		—			—			32			—			—			32			—			32
Dividends on common stock		—			—			—			(76	)		—			(76	)		—			(76	)
Noncontrolling interests, net		—			—			—			—			—			—			(14	)		(14	)
Balance at June 30, 2019	$	—		$	304		$	5,513		$	4,125		$	(648	)	$	9,294		$	1,237		$	10,531
For the Three Months Ended June 30, 2018
Balance at April 1, 2018	$	1		$	308		$	5,701		$	5,166		$	(571	)	$	10,605		$	1,332		$	11,937
Net income (loss)		—			—			—			(130	)		—			(130	)		43			(87	)
Other comprehensive income (loss)		—			—			—			—			49			49			—			49
Share-based compensation		—			—			35			—			—			35			—			35
Dividends on preferred stock		—			—			—			(12	)		—			(12	)		—			(12	)
Dividends on common stock		—			—			—			(75	)		—			(75	)		—			(75	)
Common stock acquired and retired		—			(8	)		(235	)		(257	)		—			(500	)		—			(500	)
Noncontrolling interests, net		—			—			—			—			—			—			(11	)		(11	)
Balance at June 30, 2018	$	1		$	300		$	5,501		$	4,692		$	(522	)	$	9,972		$	1,364		$	11,336
For the Six Months Ended June 30, 2019
Balance at January 1, 2019	$	1		$	291		$	5,386		$	4,257		$	(306	)	$	9,629		$	1,259		$	10,888
Net income (loss)		—			—			—			26			—			26			83			109
Other comprehensive income (loss)		—			—			—			—			(342	)		(342	)		—			(342	)
Preferred stock conversion		(1	)		12			(11	)		—			—			—			—			—
Share-based compensation		—			1			60			—			—			61			—			61
Dividends on preferred stock		—			—			—			(4	)		—			(4	)		—			(4	)
Dividends on common stock		—			—			—			(154	)		—			(154	)		—			(154	)
Sale of water business to Hess Infrastructure Partners		—			—			78			—			—			78			(78	)		—
Noncontrolling interests, net		—			—			—			—			—			—			(27	)		(27	)
Balance at June 30, 2019	$	—		$	304		$	5,513		$	4,125		$	(648	)	$	9,294		$	1,237		$	10,531
For the Six Months Ended June 30, 2018
Balance at January 1, 2018	$	1		$	315		$	5,824		$	5,597		$	(686	)	$	11,051		$	1,303		$	12,354
Cumulative effect of adoption of new accounting standards		—			—			—			1			(1	)		—			—			—
Net income (loss)		—			—			—			(236	)		—			(236	)		84			(152	)
Other comprehensive income (loss)		—			—			—			—			165			165			—			165
Share-based compensation		—			1			47			—			—			48			—			48
Dividends on preferred stock		—			—			—			(23	)		—			(23	)		—			(23	)
Dividends on common stock		—			—			—			(153	)		—			(153	)		—			(153	)
Common stock acquired and retired		—			(16	)		(370	)		(494	)		—			(880	)		—			(880	)
Noncontrolling interests, net		—			—			—			—			—			—			(23	)		(23	)
Balance at June 30, 2018	$	1		$	300		$	5,501		$	4,692		$	(522	)	$	9,972		$	1,364		$	11,336

See accompanying Notes to Consolidated Financial Statements.

6

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1.  Basis of Presentation

The financial statements included in this report reflect all normal and recurring adjustments which, in the opinion of management, are necessary for a fair presentation of our consolidated financial position at June 30, 2019 and December 31, 2018, the consolidated results of operations for the three and six months ended June 30, 2019 and 2018, and consolidated cash flows for the six months ended June 30, 2019 and 2018.  The unaudited results of operations for the interim periods reported are not necessarily indicative of results to be expected for the full year.

The financial statements were prepared in accordance with the requirements of the Securities and Exchange Commission (SEC) for interim reporting.  As permitted under those rules, certain notes or other financial information that are normally required by generally accepted accounting principles (GAAP) in the United States have been condensed or omitted from these interim financial statements.  These statements, therefore, should be read in conjunction with the consolidated financial statements and related notes included in the Corporation’s Annual Report on Form 10-K for the year ended December 31, 2018.

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

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

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

New Accounting Pronouncements:  In June 2016, the FASB issued Accounting Standards Update (ASU) 2016-13, Financial Instruments – Credit Losses.  This ASU makes changes to the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments.  The standard requires the use of a forward-looking "expected loss" model compared to the current "incurred loss" model.  We expect to adopt this ASU in the first quarter of 2020 when the standard becomes effective.  We continue to evaluate this ASU but do not believe it will have a material impact on our Consolidated Financial Statements.

7

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

2.  Leases

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

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

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

Operating and finance leases presented on the Consolidated Balance Sheet at June 30, 2019 were as follows:

	Operating Leases		Finance Leases
	(In millions)
Right-of-use assets - net (a)	$	615	$	322
Lease obligations:
Current	$	313	$	16
Long-term		395		246
Total lease obligations	$	708	$	262

(a) Finance lease ROU assets have a cost of $384 million and accumulated amortization of $62 million.

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

The nature of our leasing arrangements at June 30, 2019 was as follows:

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

Finance leases:  In 2018, we entered into a sale and lease-back arrangement for a floating storage and offloading vessel to handle produced condensate at North Malay Basin, offshore Peninsular Malaysia (Hess operated – 50%).  No gain or loss was recognized from the sale transaction.  The remaining lease term utilized in the lease obligation is 14.3 years.

8

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Maturities of lease obligations at June 30, 2019 were as follows:

	Operating Leases			Finance Leases
	(In millions)
2019	$	206		$	18
2020		183			36
2021		70			36
2022		64			36
2023		64			36
Remaining years		198			248
Total lease payments		785			410
Less: Imputed interest		(77	)		(148	)
Total lease obligations	$	708		$	262

The following information relates to the Operating and Finance leases recorded at June 30, 2019:

	Operating Leases	Finance Leases
Weighted average remaining lease term	4.9 years	14.3 years
Range of remaining lease terms	0.1 - 9.1 years	14.3 years
Weighted average discount rate	4.3%	7.9%

 The components of lease costs were as follows:

	Three Months Ended			Six Months Ended
	June 30, 2019
	(In millions)
Operating lease cost	$	107		$	210
Finance lease cost:
Amortization of leased assets		11			24
Interest on lease obligations		5			11
Short-term lease cost (a)		39			71
Variable lease cost (b)		21			40
Sublease income (c)		(3	)		(6	)
Total lease cost	$	180		$	350

(a) Short-term lease cost is primarily attributable to equipment used in global exploration, development, and production activities.  Future short-term lease costs will vary based on activity levels of our operated assets.

(b) Variable lease costs for the drilling rig leases result from differences in the minimum rate and the actual usage of the ROU asset during the lease period.  Variable lease costs for logistical assets result from differences in stated monthly rates and total charges reflecting the actual usage of the ROU asset during the lease period.  Variable lease costs for our office leases represent common area maintenance charges which have not been separated from lease components.

(c) We sublease certain of our office space to third parties under our head lease.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Supplemental cash flow information related to leases for the six months ended June 30, 2019 was as follows:

	Operating Leases		Finance Leases
	(In millions)
Cash paid for amounts included in the measurement of lease obligations (a):
Operating cash flows	$	209	$	11
Financing cash flows		—		48
Noncash transactions:
Leased assets recognized for new lease obligations incurred	3			—

(a) Amounts represent gross lease payments before any recovery from partners.

3.  Preferred Stock Conversion

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

4.  Revenue

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

	Exploration and Production												Midstream		Eliminations			Total
	United States			Denmark		Libya		Malaysia & JDA		E&P Total
Three Months Ended June 30, 2019
Sales of our net production volumes:
Crude oil revenue	$	762		$	51	$	130	$	24	$	967		$	—	$	—		$	967
Natural gas liquids revenue		48			—		—		—		48			—		—			48
Natural gas revenue		33			2		6		154		195			—		—			195
Sales of purchased oil and gas		439			—		22		—		461			—		—			461
Intercompany revenue		—			—		—		—		—			190		(190	)		—
Total revenues from contracts with customers		1,282			53		158		178		1,671			190		(190	)		1,671
Other operating revenues (a)		(11	)		—		—		—		(11	)		—		—			(11	)
Total sales and other operating revenues	$	1,271		$	53	$	158	$	178	$	1,660		$	190	$	(190	)	$	1,660
Three Months Ended June 30, 2018
Sales of our net production volumes:
Crude oil revenue	$	692		$	19	$	110	$	28	$	849		$	—	$	—		$	849
Natural gas liquids revenue		75			—		—		—		75			—		—			75
Natural gas revenue		37			2		7		165		211			—		—			211
Sales of purchased oil and gas		424			—		22		—		446			—		—			446
Intercompany revenue		—			—		—		—		—			176		(176	)		—
Total revenues from contracts with customers		1,228			21		139		193		1,581			176		(176	)		1,581
Other operating revenues (a)		(47	)		—		—		—		(47	)		—		—			(47	)
Total sales and other operating revenues	$	1,181		$	21	$	139	$	193	$	1,534		$	176	$	(176	)	$	1,534

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

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	Exploration and Production												Midstream		Eliminations			Total
	United States			Denmark		Libya		Malaysia & JDA		E&P Total
Six Months Ended June 30, 2019
Sales of our net production volumes:
Crude oil revenue	$	1,444		$	67	$	221	$	45	$	1,777		$	—	$	—		$	1,777
Natural gas liquids revenue		116			—		—		—		116			—		—			116
Natural gas revenue		75			5		12		334		426			—		—			426
Sales of purchased oil and gas		865			—		44		—		909			—		—			909
Intercompany revenue		—			—		—		—		—			380		(380	)		—
Total revenues from contracts with customers		2,500			72		277		379		3,228			380		(380	)		3,228
Other operating revenues (a)		4			—		—		—		4			—		—			4
Total sales and other operating revenues	$	2,504		$	72	$	277	$	379	$	3,232		$	380	$	(380	)	$	3,232
Six Months Ended June 30, 2018
Sales of our net production volumes:
Crude oil revenue	$	1,285		$	52	$	209	$	71	$	1,617		$	—	$	—		$	1,617
Natural gas liquids revenue		146			—		—		—		146			—		—			146
Natural gas revenue		76			5		15		293		389			—		—			389
Sales of purchased oil and gas		749			—		46		14		809			—		—			809
Intercompany revenue		—			—		—		—		—			343		(343	)		—
Total revenues from contracts with customers		2,256			57		270		378		2,961			343		(343	)		2,961
Other operating revenues (a)		(81	)		—		—		—		(81	)		—		—			(81	)
Total sales and other operating revenues	$	2,175		$	57	$	270	$	378	$	2,880		$	343	$	(343	)	$	2,880

(a) 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, 2019.  Generally, we receive payments from customers on a monthly basis, shortly after the physical delivery of the crude oil, NGLs, or natural gas.  We did not recognize any credit losses on receivables with customers during the first six months of 2019 nor 2018.

5.  Inventories

Inventories consisted of the following:

	June 30,		December 31,
	2019		2018
	(In millions)
Crude oil and natural gas liquids	$	82	$	74
Materials and supplies		196		171
Total Inventories	$	278	$	245

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

6.  Capitalized Exploratory Well Costs

The following table discloses the net changes in capitalized exploratory well costs pending determination of proved reserves during the six months ended June 30, 2019 (in millions):

Balance at January 1, 2019	$	418
Additions to capitalized exploratory well costs pending the determination of proved reserves		101
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(25	)
Balance at June 30, 2019	$	494

Reclassifications to wells, facilities and equipment based on the determination of proved reserves resulted from sanction of the second phase of development for the Liza Field, offshore Guyana.  Capitalized exploratory well costs capitalized for greater than one year following completion of drilling were $349 million at June 30, 2019 and primarily related to:  

Guyana: Approximately 45% of the capitalized well costs in excess of one year relates to eight successful exploration wells where hydrocarbons were encountered on the Stabroek Block (Hess 30%), offshore Guyana.  The operator plans further appraisal drilling for certain fields and is conducting pre-development planning for additional phases of development beyond the two existing sanctioned phases of development.

Gulf of Mexico: Approximately 35% of the capitalized well costs in excess of one year relates to the appraisal of the northern portion of the Shenzi Field (Hess 28%) in the Gulf of Mexico, where hydrocarbons were encountered in the fourth quarter of 2015.  Following exploration and appraisal drilling activities completed by the operator in prior years on adjacent blocks to the north of our Shenzi blocks, the operator is planning to acquire 3D seismic in 2019 for use in development planning of the northern portion of the Shenzi Field.

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 commercial negotiations for an extension of the existing gas sales contract to include development of the western part of the Block.

Malaysia:  Approximately 10% of the capitalized well costs in excess of one year relates to the North Malay Basin (Hess 50%), offshore Peninsular Malaysia, where hydrocarbons were encountered in four successful exploration wells in the second quarter of 2018 and one successful exploration well drilled in the fourth quarter of 2015.  In 2019, we are continuing to conduct subsurface evaluations for consideration in future phases of field development.

7.  Hess Infrastructure Partners LP

We consolidate the activities of Hess Infrastructure Partners LP (HIP), a 50/50 joint venture between Hess Corporation and Global Infrastructure Partners (GIP), which qualifies as a variable interest entity (VIE) under U.S. GAAP.  We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power, through our 50% ownership, to direct those activities that most significantly impact the economic performance of HIP.

As of June 30, 2019, the Midstream segment is comprised of HIP, which owns the general partner of Hess Midstream Partners LP (HESM).  HESM owns an approximate 20% controlling interest in the operating companies that comprise our midstream joint venture while HIP owns the remaining 80%, other than a water services business that is wholly owned by HIP.  At June 30, 2019, HIP liabilities totaling $1,279 million (December 31, 2018: $1,105 million) are on a nonrecourse basis to Hess Corporation, while HIP assets available to settle the obligations of HIP include cash and cash equivalents totaling $17 million (December 31, 2018: $109 million) and property, plant and equipment with a carrying value of $2,863 million (December 31, 2018: $2,664 million).

On March 1, 2019, HIP completed the acquisition of Hess’ water services business for $225 million in cash.  As a result of this transaction between entities under common control, we recorded an after-tax gain of $78 million in additional paid-in-capital with an offsetting reduction to noncontrolling interest to reflect the adjustment to GIP’s noncontrolling interest in HIP.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

8. Retirement Plans

Components of net periodic pension cost consisted of the following:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
	(In millions)
Service cost	$	11		$	10		$	21		$	24
Interest cost (a)		24			24			48			47
Expected return on plan assets (a)		(45	)		(49	)		(90	)		(98	)
Amortization of unrecognized net actuarial losses (a)		12			9			23			21
Curtailment gains (a)		—			—			—			(2	)
Pension (income) expense (a)	$	2		$	(6	)	$	2		$	(8	)

(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, 2019 was income of $9 million and $19 million, respectively, compared with income of $16 million and $32 million for the three and six months ended June 30, 2018, respectively.

In 2019, we expect to contribute $40 million to our funded pension plans.  Through June 30, 2019, we have contributed $20 million.

9.  Debt

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

In the first quarter of 2018, we paid $415 million to redeem $350 million principal amount of 8.125% notes due 2019 and to purchase other notes with a carrying value of $38 million.  Concurrent with the redemption of the 2019 notes, we terminated interest rate swaps with a notional amount of $350 million.  In the second quarter of 2018, we paid $138 million to purchase notes with a carrying value of $112 million.  As a result, we recorded losses on debt extinguishment of $53 million during the six months ended June 30, 2018.

Hess Midstream:  In the first quarter of 2019, HIP and HESM borrowed a total of $199 million from their revolving credit facilities of which $39 million was repaid in the second quarter of 2019.  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

10.  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						Six Months Ended
	June 30,						June 30,
	2019			2018			2019		2018
	(In millions)
Net income (loss) attributable to Hess Corporation Common Stockholders:
Net income (loss)	$	34		$	(87	)	$	109	$	(152	)
Less: Net income (loss) attributable to noncontrolling interests		40			43			83		84
Less: Preferred stock dividends		—			12			4		23
Net income (loss) attributable to Hess Corporation Common Stockholders	$	(6	)	$	(142	)	$	22	$	(259	)
Weighted average number of common shares outstanding:
Basic		302.2			297.5			299.8		303.5
Effect of dilutive securities
Restricted common stock		—			—			0.9		—
Stock options		—			—			0.2		—
Performance share units		—			—			1.2		—
Diluted		302.2			297.5			302.1		303.5

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
Restricted common stock		2,156,525		2,849,465		28,970		2,885,890
Stock options		4,894,731		5,623,004		2,920,944		5,715,292
Performance share units		1,858,050		1,072,395		32,831		847,741
Common shares from conversion of preferred stocks		—		12,547,650		1,954,473		12,566,312

During the six months ended June 30, 2019, we granted 945,009 shares of restricted stock (2018: 1,081,923), 234,866 performance share units (2018: 278,003) and 526,968 stock options (2018: 683,167).

11.  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

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filed a lawsuit alleging that we and other major oil companies damaged the groundwater in Maryland by introducing thereto gasoline with MTBE.  The suit filed in Maryland state court, was served on us in January 2018 and has been removed to Federal court by the defendants.

In September 2003, we received a directive from the New Jersey Department of Environmental Protection (NJDEP) to remediate contamination in the sediments of the Lower Passaic River.  The NJDEP is also seeking natural resource damages.  The directive, insofar as it affects us, relates to alleged releases from a petroleum bulk storage terminal in Newark, New Jersey we previously owned.  We and over 70 companies entered into an Administrative Order on Consent with the Environmental Protection Agency (EPA) to study the same contamination; this work remains ongoing.  We and other parties settled a cost recovery claim by the State of New Jersey and 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 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.  The remedy includes dredging of surface sediments and the placement of a cap over the deeper sediments throughout the Canal and in-situ stabilization of certain contaminated sediments that will remain in place below the cap.  The EPA’s original estimate was that this remedy would cost $506 million; however, the ultimate costs that will be incurred in connection with the design and implementation of the remedy remain uncertain.  Our alleged liability derives from our former ownership and operation of a fuel oil terminal and connected shipbuilding and repair facility adjacent to the Canal.  We agreed to comply with the EPA Administrative Order and are currently contributing funding for the Remedial Design based on an allocation of costs among the parties determined by a third-party expert.  

On September 28, 2017, we received a general notice letter and offer to settle from the EPA relating to Superfund claims for the Ector Drum, Inc. Superfund Site in Odessa, Texas.  The EPA and Texas Commission on Environmental Quality took clean-up and response action at the site commencing in 2014 and concluded in December 2015.  The site was determined to have improperly stored industrial waste, including drums with oily liquids.  The total clean-up cost incurred by the EPA was approximately $3.5 million.  We are negotiating a voluntary settlement with the EPA for an amount that is not expected to be material.

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

From time to time, we are involved in other judicial and administrative proceedings, including proceedings relating to other environmental matters.  We cannot predict with certainty if, how or when such proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages.  Numerous issues may need to be resolved, including through potentially lengthy discovery and determination of important factual matters before a loss or range of loss can be reasonably estimated for any proceeding.

Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of lawsuits, claims and proceedings, including the 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

12.  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, 2019
Sales and Other Operating Revenues - Third parties	$	1,660	$	—	$	—		$	—		$	1,660
Intersegment Revenues		—		190		—			(190	)		—
Sales and Other Operating Revenues	$	1,660	$	190	$	—		$	(190	)	$	1,660
Net Income (Loss) attributable to Hess Corporation	$	68	$	35	$	(109	)	$	—		$	(6	)
Depreciation, Depletion and Amortization		459		35		—			—			494
Provision (Benefit) for Income Taxes (a)		131		—		1			—			132
Capital Expenditures		625		69		—			—			694
For the Three Months Ended June 30, 2018
Sales and Other Operating Revenues - Third parties	$	1,534	$	—	$	—		$	—		$	1,534
Intersegment Revenues		—		176		—			(176	)		—
Sales and Other Operating Revenues	$	1,534	$	176	$	—		$	(176	)	$	1,534
Net Income (Loss) attributable to Hess Corporation	$	31	$	30	$	(191	)	$	—		$	(130	)
Depreciation, Depletion and Amortization		407		31		6			—			444
Provision (Benefit) for Income Taxes (a)		105		9		—			—			114
Capital Expenditures		486		84		—			—			570
For the Six Months Ended June 30, 2019
Sales and Other Operating Revenues - Third parties	$	3,232	$	—	$	—		$	—		$	3,232
Intersegment Revenues		—		380		—			(380	)		—
Sales and Other Operating Revenues	$	3,232	$	380	$	—		$	(380	)	$	3,232
Net Income (Loss) attributable to Hess Corporation	$	177	$	72	$	(223	)	$	—		$	26
Depreciation, Depletion and Amortization		923		69		—			—			992
Provision (Benefit) for Income Taxes (a)		226		—		—			—			226
Capital Expenditures		1,140		196		—			—			1,336
For the Six Months Ended June 30, 2018
Sales and Other Operating Revenues - Third parties	$	2,880	$	—	$	—		$	—		$	2,880
Intersegment Revenues		—		343		—			(343	)		—
Sales and Other Operating Revenues	$	2,880	$	343	$	—		$	(343	)	$	2,880
Net Income (Loss) attributable to Hess Corporation	$	6	$	58	$	(300	)	$	—		$	(236	)
Depreciation, Depletion and Amortization		792		62		7			—			861
Provision (Benefit) for Income Taxes (a)		200		18		(31	)		—			187
Capital Expenditures		840		121		—			—			961

(a) Commencing January 1, 2019, management changed its measurement of segment earnings to reflect income taxes on a post U.S. tax consolidation and valuation allowance assessment basis.  In 2018, the provision for income taxes in the Midstream segment was presented before consolidating its operations with other U.S. activities of the Corporation and prior to evaluating realizability of net U.S. deferred taxes.  An offsetting impact was presented in the E&P segment.  If 2018 segment results were prepared on a basis consistent with 2019, in the three and six months ended June 30, 2018, Midstream segment net income attributable to Hess Corporation would have been $39 million and $76 million, respectively, and E&P segment net income (loss) attributable to Hess Corporation would have been income of $22 million and a loss of $12 million, respectively.

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HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Identifiable assets by operating segment were as follows:

	June 30,		December 31,
	2019		2018
	(In millions)
Exploration and Production	$	16,572	$	16,109
Midstream		3,337		3,285
Corporate, Interest and Other		1,786		2,039
Total	$	21,695	$	21,433

13.  Financial Risk Management Activities

In the normal course of our business, we are exposed to commodity risks related to changes in the prices of crude oil and natural gas as well as changes in interest rates and foreign currency values.  Financial risk management activities include transactions designed to reduce risk in the selling prices of crude oil or natural gas we produce or by reducing our exposure to foreign currency or interest rate movements.  Generally, futures, swaps or option strategies may be used to fix the forward selling price of a portion of our crude oil or natural gas production.  Forward contracts may also be used to purchase certain currencies in which we conduct business with the intent of reducing exposure to foreign currency fluctuations.  At June 30, 2019, these forward contracts relate to the British Pound.  Interest rate swaps may be used to convert interest payments on certain long-term debt from fixed to floating rates.

We present gross notional amounts of both long and short positions in the table below.  These amounts include long and short positions that offset in closed positions and have not reached contractual maturity.  Gross notional amounts do not quantify risk or represent assets or liabilities of the Corporation but are used in the calculation of cash settlements under the contracts.

The gross notional amounts of outstanding West Texas Intermediate (WTI) commodity contracts as of the dates shown below were as follows:

	June 30, 2019		December 31, 2018
Calendar year program	2019		2019
Contract type	Puts		Puts
Effective date	Jul. 1, 2019		Jan. 1, 2019
End date	Dec. 31, 2019		Dec. 31, 2019
Crude oil volumes (millions of barrels)		17.5		34.7
Floor price per barrel – WTI	$	60	$	60

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

	June 30, 2019		December 31, 2018
	(In millions)
Foreign exchange	$	44	$	16
Interest rate swaps	$	100	$	100

17

PART I - FINANCIAL INFORMATION (CONT’D.)

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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

	Assets		Liabilities
	(In millions)
June 30, 2019
Derivative Contracts Designated as Hedging Instruments:
Commodity - Other current assets	$	91	$	—
Interest rate - Other assets (noncurrent)		1		—
Total derivative contracts designated as hedging instruments		92		—
Gross fair value of derivative contracts		92		—
Master netting arrangements		—		—
Net Fair Value of Derivative Contracts	$	92	$	—
December 31, 2018
Derivative Contracts Designated as Hedging Instruments:
Commodity - Other current assets	$	484	$	—
Interest rate - Other liabilities and deferred credits (noncurrent)		—		(2	)
Total derivative contracts designated as hedging instruments		484		(2	)
Gross fair value of derivative contracts		484		(2	)
Master netting arrangements		—		—
Net Fair Value of Derivative Contracts	$	484	$	(2	)

All fair values in the table above are based on Level 2 inputs.

Derivative contracts designated as hedging instruments:

Crude oil derivatives:  In the three and six months ended June 30, 2019, the impact from crude oil hedging contracts on Sales and other operating revenues was a decrease of $14 million and an increase of $1 million, respectively.  Crude oil price hedging contracts for the three and six months ended June 30, 2018 decreased Sales and other operating revenues by $44 million and $74 million, respectively.  At June 30, 2019, pre-tax deferred gains in Accumulated other comprehensive income (loss) related to outstanding crude oil price hedging contracts were $17 million, all of which will be reclassified into earnings during the remainder of 2019 as the originally hedged crude oil sales are recognized in earnings.  

Interest rate swaps designated as fair value hedges:  At June 30, 2019 and December 31, 2018, we had interest rate swaps with gross notional amounts totaling $100 million, which were designated as fair value hedges where we have converted interest payments on certain long-term debt from fixed to floating rates.  Changes in the fair value of interest rate swaps and the hedged fixed-rate debt are recorded in Interest expense in the Statement of Consolidated Income.  For the three and six months ended June 30, 2019, the change in fair value of interest rate swaps was a decrease in the liability of $2 million and $3 million, respectively, compared with an increase in liability of $1 million and $4 million in the three and six months ended June 30, 2018, 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 $2 million and gains of $3 million in the three and six months ended June 30, 2019, respectively, compared with losses of $5 million and less than $1 million in the three and six months ended June 30, 2018, respectively.  A component of foreign exchange gains and losses are the results of foreign exchange derivative contracts that are not designated as hedges which amounted to gains of $1 million and $1 million in the three and six months ended June 30, 2019, respectively, compared with losses of $3 million and $1 million in the three and six months ended June 30, 2018, respectively.

Crude oil derivatives:  In the three and six months ended June 30, 2018, noncash adjustments to de-designated crude oil price hedging contracts decreased Sales and other operating revenues by $8 million and $16 million, respectively.

Fair Value Measurement:  

We have other short-term financial instruments, primarily cash equivalents, accounts receivable and accounts payable, for which the carrying value approximated fair value at June 30, 2019.  At June 30, 2019, total long-term debt, which was substantially comprised of fixed-rate debt instruments, had a carrying value of $6,525 million and a fair value of $7,264 million based on Level 2 inputs.

18

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, 2019 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, 2018.  This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2018.

Overview

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

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

Second Quarter Highlights and Outlook

We project our E&P capital and exploratory expenditures will be approximately $2.8 billion in 2019, which is down from original guidance of $2.9 billion.  Capital investment for our Midstream operations is expected to be $430 million including assets acquired from Summit Midstream Partners LP.  Oil and gas production in 2019, excluding Libya, is forecast to be in the range of 275,000 to 280,000 barrels of oil equivalent per day (boepd), which is the upper end of our previous guidance range of 270,000 boepd to 280,000 boepd.  We have crude oil put option contracts for the remainder of 2019 that establish a WTI monthly floor price of $60 per barrel for 95,000 bopd.

Net cash provided by operating activities was $913 million in the first six months of 2019, compared with $635 million in the first six months of 2018.  Net cash provided by operating activities before changes in operating assets and liabilities were $1,195 million in the first six months of 2019 and $860 million in the first six months of 2018.  Capital expenditures were $1,336 million in the first six months of 2019 and $961 million in the first six months of 2018.  Excluding our Midstream segment, we ended the second quarter of 2019 with approximately $2.2 billion in cash and cash equivalents.  Based on current forward strip crude oil prices for 2019, we expect cash flow from operating activities and cash and cash equivalents existing at June 30, 2019 will be sufficient to fund our capital investment program and dividends through the end of 2019.

Second Quarter Results

In the second quarter of 2019, we incurred a net loss of $6 million, compared with a net loss of $130 million in the second quarter of 2018.  Excluding items affecting comparability of earnings between periods on pages 27 to 28, we incurred an adjusted net loss of $28 million in the second quarter of 2019, compared with an adjusted net loss of $56 million in the second quarter of 2018.  The improved second quarter 2019 results, compared to the prior-year quarter, primarily reflect higher U.S. crude oil net production and reduced exploration expenses, partially offset by the impact of lower realized selling prices and higher depreciation, depletion and amortization (DD&A) expenses.

Exploration and Production Results

In the second quarter of 2019, E&P had net income of $68 million, compared with net income of $31 million in the second quarter of 2018.  Excluding items affecting comparability of earnings between periods, the adjusted net income for the second quarter of 2019 was $46 million, compared with an adjusted net income of $21 million in 2018.  Total net production, excluding Libya, averaged 273,000 boepd in the second quarter of 2019, compared with 247,000 boepd in the second quarter of 2018 which included 13,000 boepd from a divested asset.  The average realized crude oil selling price, including hedging, was $60.45 per barrel, down from $62.65 per barrel in the second quarter of 2018.  The average realized NGLs selling price in the second quarter of 2019 was $12.18 per barrel, down from $20.51 per barrel in the prior-year quarter, while the average realized natural gas selling price was $3.92 per thousand cubic feet (mcf), down from $4.12 per mcf in the second quarter of 2018.

19

PART I - FINANCIAL INFORMATION (CONT’D.)

Overview (continued)

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

Producing E&P assets:

• In North Dakota, net production from the Bakken oil shale play averaged 140,000 boepd for the second quarter of 2019 (2018 Q2: 114,000 boepd), due to increased drilling activity and improved well performance.  In the second quarter of 2019, we operated six rigs, drilled 39 wells, and brought 39 new wells on production.  During 2019 we expect to bring approximately 160 new wells on production.  We forecast net production for full year 2019 to be in the range of 140,000 boepd to 145,000 boepd, which is the upper end of our previous guidance range of 135,000 boepd to 145,000 boepd.

• In the Gulf of Mexico, net production for the second quarter of 2019 averaged 65,000 boepd (2018 Q2: 47,000 boepd), primarily reflecting higher production from the Conger Field that was impacted by the shutdown of the third-party operated Enchilada platform during the prior-year quarter and higher production at the Penn State Field.  In May 2019, the Conger Field was temporarily shut-in for unplanned maintenance at the Enchilada platform that reduced second quarter 2019 net production by approximately 4,000 boepd.

• In the Gulf of Thailand, net production from Block A-18 of the JDA averaged 35,000 boepd for second quarter of 2019 (2018 Q2: 37,000 boepd), including contribution from unitized acreage in Malaysia, while net production from North Malay Basin, offshore Peninsular Malaysia, averaged 24,000 boepd for second quarter of 2019 (2018 Q2: 26,000 boepd).

Other E&P assets:

• At the Stabroek Block (Hess - 30 %), offshore Guyana, the second phase of development at the Liza Field was sanctioned by the partners following regulatory approval from the government of Guyana.  Liza Phase 2 will utilize the Liza Unity FPSO, which will have the capacity to produce up to 220,000 gross bopd.  Six drill centers are planned with a total of 30 wells, including 15 production wells, nine water injection wells and six gas injection wells.  First oil is expected by mid-2022.  The development is expected to have a gross capital cost of approximately $6 billion, including a lease capitalization cost of approximately $1.6 billion for the FPSO.  Excluding pre-sanction and lease costs, the Corporation’s net share of development costs is forecast to be approximately $1.6 billion, of which $210 million is included in our 2019 capital and exploratory budget.

Liza Phase 1 remains on track to achieve first oil by the first quarter of 2020.  It is expected to produce up to 120,000 gross bopd at peak rates utilizing the Liza Destiny FPSO, which is expected to arrive offshore Guyana in September 2019.

Planning is underway for a third phase of development at the Payara Field, which is expected to produce between 180,000 and 220,000 gross bopd with first oil as early as 2023.  

Exploration and appraisal activity on the Stabroek Block in the second quarter of 2019 was as follows:

o Yellowtail:  The Yellowtail-1 well encountered approximately 292 feet of high-quality oil-bearing sandstone reservoir and is located approximately 6 miles northwest of the Tilapia discovery.  As the fifth discovery in the greater Turbot area it underpins another potential major development hub.

o Hammerhead:  The Hammerhead-2 appraisal well, located approximately 0.9 miles from the Hammerhead-1 discovery well, and the Hammerhead-3 appraisal well, located approximately 1.9 miles from Hammerhead-1, were both successfully drilled and encountered high quality, oil bearing sandstone reservoir.  A successful drill stem test was also performed on Hammerhead-3.  The appraisal results will be evaluated for potential future development.

The Stena Carron drillship is currently drilling a second well at the Ranger discovery, while the Noble Bob Douglas and the Noble Tom Madden drillships are conducting drilling operations for the Liza Phase 1 development.  The Noble Tom Madden is next expected to drill the Tripletail exploration well, which is in the greater Turbot area, beginning in August 2019.  The operator, Esso Exploration and Production Guyana Limited, plans to add another drillship, the Noble Don Taylor, in the fourth quarter, bringing the number of drillships offshore Guyana to four.

20

PART I - FINANCIAL INFORMATION (CONT’D.)

Consolidated Results of Operations

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
	(In millions, except per share amounts)
Net Income (Loss) Attributable to Hess Corporation:
Exploration and Production	$	68		$	31		$	177		$	6
Midstream		35			30			72			58
Corporate, Interest and Other		(109	)		(191	)		(223	)		(300	)
Total	$	(6	)	$	(130	)	$	26		$	(236	)
Net Income (Loss) Attributable to Hess Corporation Per Common Share:
Basic (a)	$	(0.02	)	$	(0.48	)	$	0.07		$	(0.85	)
Diluted (b)	$	(0.02	)	$	(0.48	)	$	0.07		$	(0.85	)

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

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

Items Affecting Comparability of Earnings Between Periods

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2019		2018			2019		2018
	(In millions)
Items Affecting Comparability of Earnings Between Periods, After-Tax:
Exploration and Production	$	22	$	10		$	22	$	(27	)
Midstream		—		—			—		—
Corporate, Interest and Other		—		(84	)		—		(81	)
Total	$	22	$	(74	)	$	22	$	(108	)

The items in the table above are explained on pages 27 to 28.

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						Six Months Ended
	June 30,						June 30,
	2019			2018			2019		2018
	(In millions)
Adjusted Net Income (Loss) Attributable to Hess Corporation:
Net income (loss) attributable to Hess Corporation	$	(6	)	$	(130	)	$	26	$	(236	)
Less: Total items affecting comparability of earnings between periods, after-tax		22			(74	)		22		(108	)
Adjusted Net Income (Loss) Attributable to Hess Corporation	$	(28	)	$	(56	)	$	4	$	(128	)

21

PART I - FINANCIAL INFORMATION (CONT’D.)

Consolidated Results of Operations (continued)

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

	Six Months Ended
	June 30,
	2019			2018
	(In millions)
Net cash provided by operating activities before changes in operating assets and liabilities:
Net cash provided by (used in) operating activities	$	913		$	635
Changes in operating assets and liabilities		(282	)		(225	)
Net cash provided by (used in) operating activities before changes in operating assets and liabilities	$	1,195		$	860

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.  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 liquidity measure, which we define as reported net cash provided by (used in) operating activities excluding changes in operating assets and liabilities.  Management uses net cash provided by (used in) operating activities before changes in operating assets and liabilities to evaluate the Corporation’s underlying cash-generation performance and believes that investors’ understanding of our cash-generation ability is enhanced by disclosing this measure, which excludes working capital and other movements that distort assessment of business liquidity performance over time.

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

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

22

PART I - FINANCIAL INFORMATION (CONT’D.)

Consolidated Results of Operations (continued)

Comparison of Results

Exploration and Production

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
	(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues	$	1,660	$	1,534	$	3,232	$	2,880
Gains on asset sales, net		22		11		22		13
Other, net		7		9		27		24
Total revenues and non-operating income		1,689		1,554		3,281		2,917
Costs and Expenses
Marketing, including purchased oil and gas		498		463		932		837
Operating costs and expenses		231		241		444		488
Production and severance taxes		46		42		85		81
Midstream tariffs		165		163		327		314
Exploration expenses, including dry holes and lease impairment		43		62		77		102
General and administrative expenses		48		40		90		97
Depreciation, depletion and amortization		459		407		923		792
Total costs and expenses		1,490		1,418		2,878		2,711
Results of Operations Before Income Taxes		199		136		403		206
Provision (benefit) for income taxes (a)		131		105		226		200
Net Income (Loss) Attributable to Hess Corporation	$	68	$	31	$	177	$	6

(a) Commencing January 1, 2019, management changed its measurement of segment earnings to reflect income taxes on a post U.S. tax consolidation and valuation allowance assessment basis.  See footnote (a) in the table on page 16 for further details.  

Excluding the E&P items affecting comparability of earnings between periods detailed on page 27, the changes in E&P earnings are primarily attributable to changes in selling prices, production and sales volumes, marketing expenses, cash operating costs, Midstream tariffs, DD&A, exploration expenses and income taxes, as discussed below.

23

PART I - FINANCIAL INFORMATION (CONT’D.)

Consolidated Results of Operations (continued)

Selling Prices:  Lower realized selling prices in the second quarter and first six months of 2019 decreased after-tax results by approximately $60 million and $80 million, respectively, compared to the same periods in 2018.  Average selling prices were as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
Average Selling Prices (a)
Crude Oil – Per Barrel (Including Hedging)
United States
Onshore	$	56.08	$	59.03	$	54.14	$	57.73
Offshore		62.23		62.80		60.73		61.08
Total United States		58.22		60.25		56.49		58.77
Denmark		70.27		75.26		69.51		70.04
Libya		69.87		73.85		66.72		70.06
Malaysia and JDA		66.88		72.55		63.11		69.53
Worldwide		60.45		62.65		58.25		60.98
Crude Oil – Per Barrel (Excluding Hedging)
United States
Onshore	$	57.19	$	63.47	$	54.09	$	61.56
Offshore		63.42		67.14		60.68		64.87
Total United States		59.36		64.66		56.43		62.59
Denmark		70.27		75.26		69.51		70.04
Libya		69.87		73.85		66.72		70.06
Malaysia and JDA		66.88		72.55		63.11		69.53
Worldwide		61.37		66.28		58.20		64.05
Natural Gas Liquids – Per Barrel
United States
Onshore	$	12.16	$	20.08	$	15.22	$	20.42
Offshore		12.32		24.54		14.97		24.42
Worldwide		12.18		20.51		15.19		20.80
Natural Gas – Per Mcf
United States
Onshore	$	1.41	$	1.94	$	1.86	$	2.20
Offshore		2.19		2.19		2.37		2.15
Total United States		1.76		2.01		2.11		2.19
Denmark		3.74		3.53		3.89		3.47
Libya		5.78		6.91		5.44		6.92
Malaysia and JDA		5.08		5.11		5.19		4.84
Worldwide		3.92		4.12		4.18		3.99

(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 2019 would be $63.33 (Q2 2018: $65.66) per barrel for crude oil (including hedging), $64.25 (Q2 2018: $69.29) per barrel for crude oil (excluding hedging), $12.38 (Q2 2018: $20.73) per barrel for NGLs and $3.99 (Q2 2018: $4.20) per mcf for natural gas.  Excluding these fees Worldwide selling prices for the first six months of 2019 would be $61.32 (2018: $64.05) per barrel for crude oil (including hedging), $61.27 (2018: $67.12) per barrel for crude oil (excluding hedging), $15.37 (2018: $21.02) per barrel for NGLs and $4.25 (2018: $4.07) per mcf for natural gas.

In the three and six months ended June 30, 2019, the impact from crude oil price hedging contracts on Sales and other operating revenues was a decrease of $14 million and an increase of $1 million, respectively.  Crude oil price hedging contracts for the three and six months ended June 30, 2018 decreased Sales and other operating revenues by $52 million and $90 million, respectively.  As of June 30, 2019, we have crude oil put options for calendar year 2019 that establish a WTI monthly floor price of $60 per barrel on 95,000 bopd.

24

PART I - FINANCIAL INFORMATION (CONT’D.)

Consolidated Results of Operations (continued)

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
	(In thousands)
Crude Oil – Barrels
United States
North Dakota (a)		87			74			86			73
Offshore		46			34			47			33
Total United States		133			108			133			106
Denmark		6			5			6			6
Libya		18			16			19			18
Malaysia and JDA		4			4			4			4
Total		161			133			162			134
Natural Gas Liquids – Barrels
United States
North Dakota (a)		38			32			36			30
Offshore		5			4			6			4
Other (b)		—			4			—			4
Total United States		43			40			42			38
Natural Gas – Mcf
United States
North Dakota (a)		103			75			91			74
Offshore		83			52			88			44
Other (b)		—			54			—			56
Total United States		186			181			179			174
Denmark		6			6			6			8
Libya		11			11			12			12
Malaysia and JDA		332			355			355			335
Total		535			553			552			529
Barrels of Oil Equivalent (c)		293			265			296			260
Crude oil and natural gas liquids as a share of total production		70	%		65	%		69	%		66	%

(a) Net production from the Bakken was 140,000 boepd and 135,000 boepd in the second quarter and first six months of 2019, respectively, compared with 114,000 boepd and 112,000 boepd in the second quarter and first six months of 2018, respectively.

(b) In August 2018, the Corporation sold its joint venture interests in the Utica shale play in eastern Ohio.  Net production was 13,000 boepd in the second quarter and first six months of 2018.

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

We forecast net production, excluding Libya, to average between 270,000 boepd and 280,000 boepd for the third quarter and to average between 275,000 boepd and 280,000 boepd for the full year of 2019.

United States:  North Dakota net production was higher in the second quarter and first six months of 2019, compared to the corresponding periods in 2018, primarily due to ongoing drilling activity and improved well performance at the Bakken.  Offshore net production was higher in the second quarter and first six months of 2019, compared to the corresponding periods in 2018, primarily due to higher production from the Conger and Penn State fields that were impacted by a prior-year shutdown of the third-party operated Enchilada platform.

International:  Net production was lower in the second quarter of 2019, compared to the corresponding period in 2018, due to a planned maintenance shutdown at the North Malay Basin and lower buyer nominations at JDA in the second quarter of 2019.  Net production was higher in the first six months of 2019, compared to the corresponding period in 2018, primarily reflecting downtime from planned maintenance of condensate export equipment at the North Malay Basin in the first quarter of 2018.

25

PART I - FINANCIAL INFORMATION (CONT’D.)

Consolidated Results of Operations (continued)

Sales Volumes:  The impact of higher sales volumes improved after-tax results by approximately $130 million and $320 million in the second quarter and first six months of 2019, compared to the same periods in 2018.  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				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
	(In thousands)
Crude oil – barrels		15,061		12,259		29,001		24,070
Natural gas liquids – barrels		3,931		3,620		7,562		6,928
Natural gas – mcf		48,638		50,303		100,073		95,695
Barrels of Oil Equivalent (a)		27,098		24,263		53,242		46,947
Crude oil – barrels per day		166		135		160		133
Natural gas liquids – barrels per day		43		40		42		38
Natural gas – mcf per day		535		553		552		529
Barrels of Oil Equivalent Per Day (a)		298		267		294		259

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

Marketing, including purchased oil and gas:  Marketing expense is mainly comprised of costs to purchase crude oil, NGLs 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.  The increase in the second quarter and first six months of 2019, compared to the same periods in 2018, primarily reflects the purchase of higher volumes.

Cash Operating Costs:  Cash operating costs in the second quarter of 2019, consisting of operating costs and expenses, production and severance taxes and E&P general and administrative expenses, were flat compared with the second quarter of 2018.  Excluding items affecting comparability of earnings, cash operating costs for the first six months of 2019 decreased, compared with the prior-year period primarily due to lower workover expenses.  Cash operating costs on a per-unit basis were also lower, reflecting the impact of increased production from the Bakken and Gulf of Mexico.

Depreciation, Depletion and Amortization:  DD&A expenses were higher in the second quarter and first six months of 2019 on an absolute basis, compared to the same periods in 2018, primarily due to higher net production volumes in the Bakken and Gulf of Mexico.  DD&A expense on a per unit basis was marginally up in the second quarter and first six months of 2019, compared with the same periods in 2018, due to the mix of production.

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

	Actual								Forecast range (a)
	Three Months Ended				Six Months Ended				Three Months Ended	Twelve Months Ended
	June 30,				June 30,				September 30,	December 31,
	2019		2018		2019		2018		2019	2019
Cash operating costs (b)	$	12.11	$	13.37	$	11.55	$	13.41	$13.00  — $14.00	$12.50  — $13.00
DD&A (c)		17.20		16.85		17.23		16.81	18.00  —  19.00	18.00  —  19.00
Total Production Unit Costs	$	29.31	$	30.22	$	28.78	$	30.22	$31.00 — $33.00	$30.50 — $32.00

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

(b) Excluding items affecting comparability of earnings and Libya, cash operating costs per boe were $12.72 and $12.12 in the three and six months ended June 30, 2019, respectively, compared with $14.03 and $14.21 in the same periods of 2018, respectively.

(c) Excluding items affecting comparability of earnings and Libya, DD&A per boe was $18.31 and $18.34 in three months and six months ended June 30, 2019, respectively, compared with $17.92 and $18.02 in the same periods of 2018, respectively.

26

PART I - FINANCIAL INFORMATION (CONT’D.)

Consolidated Results of Operations (continued)

Exploration Expenses:  Exploration expenses were as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
	(In millions)
Exploratory dry hole costs	$	—	$	13	$	—	$	13
Exploration lease and other impairment		4		10		11		20
Geological and geophysical expense and exploration overhead		39		39		66		69
Total Exploration Expense	$	43	$	62	$	77	$	102

Exploration expenses, excluding dry hole expense, are estimated to be in the range of $50 million to $60 million in the third quarter of 2019 and $200 million to $210 million for the full year of 2019.

Income Taxes:  Income tax expense is comprised primarily of taxes in Libya in the second quarter and first six months of both 2019 and 2018.  Excluding items affecting comparability of earnings between periods and Libyan operations, the effective income tax rate for E&P operations in the second quarter and first six months of 2019 was an expense of 15% and 6%, respectively.  The tax rates in the second quarter and first six months of 2018 were not meaningful as results on a pre-tax basis were essentially break-even.  Excluding items affecting comparability of earnings between periods and Libyan operations, the E&P effective income tax rate is expected to be an expense in the range of 0% to 4% for the third quarter of 2019 and for the full year of 2019.

Items Affecting Comparability of Earnings Between Periods:

Gain on asset sale, net:  In the second quarter of 2019, we recorded a pre-tax gain of $22 million ($22 million after income taxes) associated with the sale of our remaining acreage in the Utica shale play.  In the second quarter of 2018, we recorded a pre-tax gain of $10 million ($10 million after income taxes) associated with the sale of our interests in Ghana.

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

Midstream

Following is a summarized income statement of our Midstream operations:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
	(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues	$	190	$	176	$	380	$	343
Other, net		—		2		—		3
Total revenues and non-operating income		190		178		380		346
Costs and Expenses
Operating costs and expenses		58		47		113		88
General and administrative expenses		5		3		11		6
Depreciation, depletion and amortization		35		31		69		62
Interest expense		17		15		32		30
Total costs and expenses		115		96		225		186
Results of Operations Before Income Taxes		75		82		155		160
Provision (benefit) for income taxes (a)		—		9		—		18
Net Income (Loss)		75		73		155		142
Less: Net income (loss) attributable to noncontrolling interests (b)		40		43		83		84
Net Income (Loss) Attributable to Hess Corporation	$	35	$	30	$	72	$	58

(a) Commencing January 1, 2019, management changed its measurement of segment earnings to reflect income taxes on a post U.S. tax consolidation and valuation allowance assessment basis.  See footnote (a) in the table on page 16 for further details.

(b) The noncontrolling interests’ share of income is not subject to tax.

27

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 2019 increased, compared to the corresponding periods in 2018, primarily due to higher throughput volumes and tariff rates, and increased rail transportation and water trucking revenues associated with third party charges.  Operating costs and expenses for the second quarter and first six months of 2019 increased, compared to the corresponding periods in 2018, due to higher maintenance activity, and increased third party rail transportation and water trucking charges.

Net income attributable to Hess Corporation from the Midstream segment is estimated to be approximately $40 million in the third quarter of 2019 and in the range of $170 million to $175 million for the full year of 2019.

Corporate, Interest and Other

The following table summarizes Corporate, Interest and Other expenses:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2019			2018			2019			2018
	(In millions)
Corporate and other expenses (excluding items affecting comparability)	$	28		$	24		$	60		$	49
Interest expense		89			88			179			180
Less: Capitalized interest		(9	)		(5	)		(16	)		(9	)
Interest expense, net		80			83			163			171
Corporate, Interest and Other expenses before income taxes		108			107			223			220
Provision (benefit) for income taxes		1			—			—			(1	)
Net Corporate, Interest and Other expenses after income taxes		109			107			223			219
Items affecting comparability of earnings between periods, after-tax		—			84			—			81
Total Corporate, Interest and Other Expenses After Income Taxes	$	109		$	191		$	223		$	300

Corporate and other expenses, excluding items affecting comparability, were higher in the second quarter of 2019, compared to the corresponding period in 2018, primarily due to lower non-operating revenue in the second quarter of 2019.  Corporate and other expenses, excluding items affecting comparability, were higher in the first six months of 2019, compared to the corresponding period in 2018, primarily due to lower interest income and other non-operating income.  Interest expense, net was lower in the second quarter and first six months of 2019, compared with corresponding periods in 2018, primarily due to higher capitalized interest.  

Third quarter 2019 corporate expenses are expected to be in the range of $25 million to $30 million, and interest expense is expected to be in the range of $75 million to $80 million.  We estimate corporate expenses for full year 2019 to be in the range of $110 million to $115 million, and interest expense to be in the range of $315 million to $320 million.  

Items Affecting Comparability of Earnings Between Periods:  In the three and six months ended June 30, 2018, we recognized pre-tax charges totaling $26 million ($26 million after income taxes) and $53 million ($53 million after income taxes), respectively, related to the premium paid for debt repurchases.  In the second quarter of 2018, we recorded a pre-tax charge of $58 million ($58 million after income taxes) resulting from the settlement of legal claims related to former downstream interests.  In addition, in the first quarter of 2018, as required under accounting standards’ intraperiod allocation rules, we recognized a noncash income tax benefit of $30 million to offset a noncash income tax expense recognized in other comprehensive income, resulting from a reduction in our pension liabilities.

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, political risk, environmental risk and catastrophic risk.  For a more comprehensive description of the risks that may affect our business, see Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2018.

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PART I - FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources

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

	June 30,			December 31,
	2019			2018
	(In millions, except ratio)
Cash and cash equivalents (a)	$	2,208		$	2,694
Current maturities of long-term debt		14			67
Total debt (b)		6,525			6,672
Total equity		10,531			10,888
Debt to capitalization ratio (c)		39.2	%		38.0	%

(a) Includes $17 million of cash attributable to our Midstream segment, at June 30, 2019 (December 31, 2018: $109 million).

(b) Includes $1,137 million of debt outstanding at June 30, 2019 from our Midstream segment that is non-recourse to Hess Corporation (December 31, 2018: $981 million).

(c) Total debt (including finance lease obligations) as a percentage of the sum of total debt (including finance lease obligations) plus equity.  Prior to the adoption of ASC 842, Leases, finance lease obligations were included in debt.

Cash Flows

The following table summarizes our cash flows:

	Six Months Ended, June 30,
	2019			2018
	(In millions)
Net cash provided by (used in):
Operating activities	$	913		$	635
Investing activities		(1,297	)		(906	)
Financing activities		(102	)		(1,668	)
Net Increase (Decrease) in Cash and Cash Equivalents	$	(486	)	$	(1,939	)

Operating activities:  Net cash provided by operating activities was $913 million in the first six months of 2019, compared with $635 million in the first six months of 2018.  The increase in 2019 operating cash flows primarily reflects higher net production volumes.  Changes in operating assets and liabilities was a use of cash of $282 million in the first six months of 2019, and a use of cash of $225 million in the first six months of 2018.  Changes in operating assets and liabilities during 2019 included a one-time payment of approximately $130 million to our joint venture partner for its share of sale/leaseback proceeds related to our sale of the North Malay Basin floating storage and offloading vessel completed in the third quarter of 2018.  The remaining changes primarily included an increase in accounts receivable and a reduction in accounts payable.

Investing activities:  Additions to property, plant and equipment were up $402 million in the first six months of 2019, compared to the same period in 2018, primarily reflecting increased drilling activity in the Bakken, increased activity at the Liza Phase 1 development and the Midstream operating segment’s acquisition of assets from Summit Midstream Partners LP, partially offset by lower exploration expenditures in Canada.  The Midstream segment invested $23 million in its 50/50 joint venture with Targa Resources in the first six months of 2019, compared with $41 million in the first six months of 2018.

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

	Six Months Ended, June 30,
	2019			2018
	(In millions)
Additions to property, plant and equipment - E&P:
Capital expenditures incurred - E&P	$	(1,140	)	$	(840	)
Increase (decrease) in related liabilities		55			47
Additions to property, plant and equipment - E&P	$	(1,085	)	$	(793	)
Additions to property, plant and equipment - Midstream:
Capital expenditures incurred - Midstream	$	(196	)	$	(121	)
Increase (decrease) in related liabilities		(14	)		21
Additions to property, plant and equipment - Midstream	$	(210	)	$	(100	)

29

PART I - FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources (continued)

Financing activities: HIP borrowed a net total of $160 million from its revolving credit facility in the first six months of 2019.  Debt repayments were $5 million in the first six months of 2019 and $591 million in the first six months of 2018, that included the redemption of our 8.125% notes due in 2019.  Payments on finance lease obligations were $45 million in the first six months of 2019.  In addition, we paid common and preferred stock dividends totaling $164 million in the first six months of 2019, compared with $176 million in the first six months of 2018.  In the first six months of 2018, we cash settled the repurchase of $890 million of common stock.

Future Capital Requirements and Resources

Excluding our Midstream segment, we ended the second quarter of 2019 with approximately $2.2 billion in cash and cash equivalents, total liquidity including available committed credit facilities of approximately $6.1 billion and no significant near-term debt maturities.

Net cash provided by operating activities was $913 million in the first six months of 2019, compared with $635 million in the first six months of 2018.  Net cash provided by operating activities before changes in operating assets and liabilities was $1,195 million in the first six months of 2019 and $860 million in the first six months of 2018.  Capital expenditures were $1,336 million in the first six months of 2019 and $961 million in the first six months of 2018.  Based on current forward strip crude oil prices for 2019, we expect cash flow from operating activities and cash and cash equivalents existing at June 30, 2019, will be sufficient to fund our capital investment program and dividends through the end of 2019.

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, 2019:

						Letters of
	Expiration					Credit		Total		Available
	Date	Capacity		Borrowings		Issued		Used		Capacity
		(In millions)
Hess Corporation
Revolving credit facility	May 2023	$	3,500	$	—	$	—	$	—	$	3,500
Committed lines	Various (a)		445		—		54		54		391
Uncommitted lines	Various (a)		218		—		218		218		—
Total - Hess Corporation		$	4,163	$	—	$	272	$	272	$	3,891
Midstream
Revolving credit facility - HIP (b)	November 2022	$	600	$	160	$	—	$	160	$	440
Revolving credit facility - Hess Midstream Partners LP (c)	March 2021		300		—		—		—		300
Total - Midstream		$	900	$	160	$	—	$	160	$	740

(a) Committed and uncommitted lines have expiration dates through 2020 and 2019, respectively.

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

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

At June 30, 2019, Hess Corporation had no outstanding borrowings or letters of credit under its revolving credit facility and was in compliance with its financial covenants.

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

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

30

PART I - FINANCIAL INFORMATION (CONT’D.)

Liquidity and Capital Resources (continued)

At June 30, 2019, HIP had $800 million of senior secured syndicated credit facilities maturing November 2022, consisting of a $600 million 5-year revolving credit facility and a drawn $200 million 5-year Term Loan A facility.  The revolving credit facility can be used for borrowings and letters of credit to fund the joint venture’s operating activities and capital expenditures.  Borrowings under the 5-year Term Loan A facility will generally bear interest at LIBOR plus an applicable margin ranging from 1.55% to 2.50%, while the applicable margin for the 5-year syndicated revolving credit facility ranges from 1.275% to 2.000%.  The interest rate is subject to adjustment based on HIP’s leverage ratio, which is calculated as total debt to Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA).  If HIP obtains an investment grade credit rating, as defined in the amended credit agreement, pricing levels will be based on the credit ratings in effect from time to time.  The credit facilities contain financial covenants that generally require a leverage ratio of no more than 5.0 to 1.0 for the prior four fiscal quarters and an interest coverage ratio, which is calculated as EBITDA to cash interest expense, of no less than 2.25 to 1.0 for the prior four fiscal quarters.  The amended credit agreement includes a secured leverage ratio test not to exceed 3.75 to 1.00 for so long as the facilities remain secured.  HIP is in compliance with these financial covenants at June 30, 2019.  Outstanding borrowings under this credit facility are non-recourse to Hess Corporation.  At June 30, 2019, borrowings of $160 million were drawn under HIP’s revolving credit facility, and borrowings of $192.5 million, excluding deferred issuance costs, were drawn under HIP’s Term Loan A facility.  The credit facilities are secured by first-priority perfected liens on substantially all of HIP’s and certain of its wholly-owned subsidiaries’ directly owned assets, including its equity interests in certain subsidiaries, subject to customary exclusions.

HESM has a $300 million 4-year senior secured syndicated revolving credit facility that became available for utilization at completion of its initial public offering in April 2017.  The credit facility can be used for borrowings and letters of credit to fund operating activities and capital expenditures of HESM and expires March 2021.  Borrowings on the credit facility will generally bear interest at LIBOR plus an applicable margin of 1.275%.  The interest rate is subject to adjustment based on HESM’s leverage ratio, which is calculated as total debt to EBITDA.  If HESM obtains credit ratings, pricing levels will be based on the credit ratings in effect from time to time.  HESM is subject to customary covenants in the credit agreement, including financial covenants that generally require a leverage ratio of no more than 4.5 to 1.0 for the prior four fiscal quarters.  HESM is in compliance with these financial covenants at June 30, 2019.  The credit facility is secured by first priority perfected liens on substantially all directly owned assets of HESM and its wholly-owned subsidiaries, including equity interests in subsidiaries, subject to certain customary exclusions.  Outstanding borrowings under this credit facility are non-recourse to Hess Corporation.  At June 30, 2019, no borrowings were drawn under this facility.

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

Financial Risk Management Activities

We have outstanding foreign exchange contracts with notional amounts totaling $44 million at June 30, 2019 that are used to reduce our exposure to fluctuating foreign exchange rates for various currencies.  The change in fair value of foreign exchange contracts from a 10% weakening in the U.S. Dollar exchange rate is estimated to be a loss of approximately $5 million at June 30, 2019.

At June 30, 2019, our total long-term debt, which was substantially comprised of fixed-rate instruments, had a carrying value of $6,525 million and a fair value of $7,264 million.  A 15% increase or decrease in interest rates would decrease or increase the fair value of debt by approximately $450 million or $500 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, 2019, we have outstanding West Texas Intermediate (WTI) crude oil put contracts.  See Note 13, Financial Risk Management Activities in the Notes to Consolidated Financial Statements. As of June 30, 2019, an assumed 10% increase in the forward WTI crude oil prices used in determining the fair value of our crude put contracts would reduce the fair value of these derivatives instruments by approximately $35 million, while an assumed 10% decrease in the same WTI crude oil prices would increase the fair value of these derivative instruments by approximately $70 million.

31

PART I - FINANCIAL INFORMATION (CONT’D.)

Forward-looking Information

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

32

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, 2019, 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, 2019.

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, 2019 that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

33

PART II – OTHER INFORMATION

Item 1.   Legal Proceedings.

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

Item 6.   Exhibits.

Exhibits
31(1)	Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
31(2)	Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
32(1)	Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
32(2)	Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
101(INS)	XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101(SCH)	XBRL Schema Document.
101(CAL)	XBRL Calculation Linkbase Document.
101(LAB)	XBRL Labels Linkbase Document.
101(PRE)	XBRL Presentation Linkbase Document.
101(DEF)	XBRL Definition Linkbase Document.

*  These exhibits relate to executive compensation plans and arrangements.

34

SIGNATURES

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

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

Date: August 6, 2019

35