UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

For the fiscal year ended December 31, 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	13-4921002
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)
1185 AVENUE OF THE AMERICAS,	10036
NEW YORK, NY.	(Zip Code)
(Address of principal executive offices)

Registrant’s telephone number, including area code (212) 997-8500

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

Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock (par value $1.00)	HES	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ No ☑

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                    ☐ Emerging Growth Company        ☐	Smaller reporting 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 ☑

The aggregate market value of voting stock held by non-affiliates of the Registrant amounted to $16,996,000,000, computed using the outstanding Common Stock and closing market price on June 28, 2019, the last business day of the Registrant’s most recently completed second fiscal quarter.

At January 31, 2020, there were 305,214,587 shares of Common Stock outstanding.

Part III is incorporated by reference from the Proxy Statement for the 2020 annual meeting of stockholders.  

HESS CORPORATION

Form 10-K

TABLE OF CONTENTS

Item No.		Page
	PART I
1 and 2.	Business and Properties	6
	Information about our Executive Officers	16
1A.	Risk Factors	18
1B.	Unresolved Staff Comments	21
3.	Legal Proceedings	22
4.	Mine Safety Disclosures	23
	PART II
5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
6.	Selected Financial Data	26
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
7A.	Quantitative and Qualitative Disclosures About Market Risk	47
8.	Financial Statements and Supplementary Data	48
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	100
9A.	Controls and Procedures	100
9B.	Other Information	100
	PART III
10.	Directors, Executive Officers and Corporate Governance	100
11.	Executive Compensation	100
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	100
13.	Certain Relationships and Related Transactions, and Director Independence	100
14.	Principal Accounting Fees and Services	100
	PART IV
15.	Exhibits, Financial Statement Schedules	101
	Signatures	104

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.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

• fluctuations in market prices of crude oil, natural gas liquids and natural gas and competition in the oil and gas exploration and production industry generally;

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

• potential failures or delays in achieving expected production levels given inherent uncertainties in estimating quantities of proved reserves;

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

• reduced demand for our products, including the impact of competing or alternative energy products and political conditions and events, such as instability, changes in governments, armed conflict, economic sanctions and outbreaks of infectious diseases;

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

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

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

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

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

• liability resulting from litigation, including heightened risks associated with being a general partner of Hess Midstream LP; and

• other factors described in Item 1A—Risk Factors in this Annual Report on Form 10-K and any additional risks described in our other filings with the Securities and Exchange Commission.

As and when made, we believe that our forward-looking statements are reasonable.  However, given these risks and uncertainties, caution should be taken not to place undue reliance on any such forward-looking statements since such statements speak only as of the date when made and there can be no assurance that such forward-looking statements will occur and actual results may differ materially from those contained in any forward-looking statement we make.  Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether because of new information, future events or otherwise.

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Glossary

Throughout this report, the following company or industry specific terms and abbreviations are used:

Appraisal well – An exploration well drilled to confirm the results of a discovery well, or a well that is used to determine the boundaries of a productive formation.

Bbl – One stock tank barrel, which is 42 United States gallons liquid volume.

Barrel of oil equivalent or Boe – This reflects natural gas reserves converted on the basis of relative energy content of six mcf equals one barrel of oil equivalent (one mcf represents one thousand cubic feet).  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.

Boepd – Barrels of oil equivalent per day.

Bopd – Barrels of oil per day.

Condensate – A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that when produced, is in the liquid phase at surface pressure and temperature.

Development well – A well drilled within the proved area of an oil and/or natural gas reservoir with the intent of producing oil and/or natural gas from that area of the reservoir.

Dry hole – An exploratory or development well that does not find oil or natural gas in commercial quantities.

Exploratory well – A well drilled to find oil or natural gas in an unproved area or find a new reservoir in a field previously found to be productive by another reservoir.

Fractionation – A process by which the mixture of natural gas liquids that results from natural gas processing is separated into the NGL components, such as ethane, propane, butane, isobutane, and natural gasoline, prior to their sale to various petrochemical and industrial end users.  Fractionation is accomplished by controlling the temperature of the stream of mixed liquids in order to take advantage of the difference in boiling points of separate products.

Field – An area consisting of a single reservoir or multiple reservoirs all grouped or related to the same individual geological structural feature and/or stratigraphic condition.

FPSO – Floating production, storage, and offloading vessel.

Gross acres – Acreage in which a working interest is held by the Corporation.

Gross well – A well in which a working interest is held by the Corporation.

LIBOR – The London Interbank Offered Rate.

Mcf – One thousand cubic feet of natural gas.

Mmcfd – One thousand mcf of natural gas per day.

Net acreage or Net wells – The sum of the fractional working interests owned by us in gross acres or gross wells.

NGL or Natural gas liquids – Naturally occurring hydrocarbon substances that are separated and produced by fractionating natural gas, including ethane, butane, isobutane, propane and natural gasoline.  NGL do not sell at prices equivalent to crude oil.

Non-operated – Projects in which the Corporation has a working interest but does not perform the role of Operator.

OPEC – Organization of Petroleum Exporting Countries.

Operator – The entity responsible for conducting and managing exploration, development, and/or production operations for an oil or gas project.

Plug and perf completion – A well completion technique which involves creating perforations in the well casing that penetrate the hydrocarbon reservoir section between set plugs.

Participating interest – Reflects the proportion of exploration and production costs each party will bear as set out in an operating agreement.

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Production sharing contract – An agreement between a host government and the owners (or co-owners) of a well or field regarding the percentage of production each party will receive after the parties have recovered a specified amount of capital and operational expenses.

Productive well – A well that is capable of producing hydrocarbons in sufficient quantities to justify commercial exploitation.

Proved properties – Properties with proved reserves.

Proved reserves – In accordance with the Securities and Exchange Commission regulations and practices recognized in the publication of the Society of Petroleum Engineers entitled, “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information,” those quantities of crude oil and condensate, NGL and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved developed reserves – Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or for which the cost of the required equipment is relatively minor compared to the cost of a new well.

Proved undeveloped reserves – Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

Unproved properties – Properties with no proved reserves.

Working interest – An interest in an oil and gas property that provides the owner of the interest the right to participate in the drilling for and production of oil and gas on the relevant acreage and requires the owner to pay a share of the costs of drilling and production operations.

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PART I

Items 1 and 2.  Business and Properties

Hess Corporation, incorporated in the State of Delaware in 1920, is a global Exploration and Production (E&P) company engaged in exploration, development, production, transportation, purchase and sale of crude oil, NGL, and natural gas with production operations and development activities located primarily in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA), Malaysia and Denmark.  We conduct exploration activities primarily offshore Guyana, the U.S. Gulf of Mexico, and offshore Suriname and Canada.  At the Stabroek Block (Hess 30%), offshore Guyana, we have announced sixteen significant discoveries.  The Liza Phase 1 development achieved first production in December 2019, with peak production expected to reach up to 120,000 gross bopd.  The Liza Phase 2 development was sanctioned in the second quarter of 2019 and is expected to start up 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 FPSOs producing more than 750,000 gross bopd by 2025.

Our Midstream operating segment, which is comprised of Hess Corporation’s 47% consolidated ownership interest in Hess Midstream LP at December 31, 2019, provides fee-based services, including gathering, compressing and processing natural gas and fractionating NGL; gathering, terminaling, loading and transporting crude oil and NGL; storing and terminaling propane, and water handling services primarily in the Bakken shale play in the Williston Basin area of North Dakota.  See Midstream on page 13.  

Exploration and Production

Proved Reserves

Proved reserves are calculated using the average price during the twelve-month period ending December 31 determined as an unweighted arithmetic average of the price on the first day of each month within the year, unless prices are defined by contractual agreements, and exclude escalations based on future conditions.  Crude oil prices used in the determination of proved reserves at December 31, 2019 were $55.73 per barrel for West Texas Intermediate (WTI) (2018: $65.55) and $62.54 per barrel for Brent (2018: $72.08).  Our total proved developed and undeveloped reserves at December 31 were as follows:

	Crude Oil & Condensate				Natural Gas Liquids				Natural Gas				Total Barrels of Oil Equivalent (BOE)
	2019		2018		2019		2018		2019		2018		2019		2018
	(Millions of bbls)				(Millions of bbls)				(Millions of mcf)				(Millions of bbls)
Developed
United States		293		266		90		85		400		432		450		423
Europe		32		38		—		—		65		77		43		51
Africa		107		111		—		—		118		115		127		130
Asia and other (a)		36		4		—		—		500		585		119		102
		468		419		90		85		1,083		1,209		739		706
Undeveloped
United States		215		235		79		90		300		381		344		389
Europe		8		1		—		—		16		1		11		1
Africa		14		15		—		—		2		13		14		17
Asia and other (a)		57		44		—		—		192		211		89		79
		294		295		79		90		510		606		458		486
Total
United States		508		501		169		175		700		813		794		812
Europe		40		39		—		—		81		78		54		52
Africa		121		126		—		—		120		128		141		147
Asia and other (a)		93		48		—		—		692		796		208		181
		762		714		169		175		1,593		1,815		1,197		1,192

(a) Asia and other includes Guyana proved developed reserves of 31 million boe and proved undeveloped reserves of 56 million boe at December 31, 2019 (December 31, 2018: proved developed - 0 million boe; proved undeveloped - 42 million boe).

Proved undeveloped reserves were 38% of our total proved reserves at December 31, 2019 on a boe basis (2018: 41%).  Proved reserves held under production sharing contracts totaled 12% of our crude oil reserves and 43% of our natural gas reserves at December 31, 2019 (2018: 7% and 44%, respectively).

For additional information regarding our proved oil and gas reserves, see the Supplementary Oil and Gas Data to the Consolidated Financial Statements presented on pages 90 through 98.

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Production

Worldwide crude oil, NGL, and natural gas net production was as follows:

	2019		2018		2017
Crude oil – Thousands of barrels
United States
Bakken		34,090		27,663		24,439
Other Onshore (a)		209		389		2,053
Total Onshore		34,299		28,052		26,492
Offshore		16,628		15,026		14,411
Total United States		50,927		43,078		40,903
Europe
Denmark		2,167		2,231		2,988
Norway (a)		—		—		7,236
		2,167		2,231		10,224
Africa
Libya		6,994		6,654		3,542
Equatorial Guinea (a)		—		—		9,201
		6,994		6,654		12,743
Asia and Other
JDA		555		546		586
Malaysia		924		851		289
Guyana		67		—		—
		1,546		1,397		875
Total		61,634		53,360		64,745

Natural gas liquids – Thousands of barrels
United States
Bakken	14,828	10,767	10,107
Other Onshore (a)	322	1,647	2,972
Total Onshore	15,150	12,414	13,079
Offshore	1,942	1,703	1,733
Total United States	17,092	14,117	14,812
Europe - Norway (a)	—	—	340
Total	17,092	14,117	15,152

Natural gas – Thousands of mcf
United States
Bakken	38,993	25,625	22,621
Other Onshore (a)	1,229	16,167	33,478
Total Onshore	40,222	41,792	56,099
Offshore	33,212	24,452	20,987
Total United States	73,434	66,244	77,086
Europe
Denmark	2,500	2,958	5,124
Norway (a)	—	—	6,739
	2,500	2,958	11,863
Asia and Other
JDA	66,127	68,477	73,444
Malaysia (b)	61,944	59,995	27,225
Libya	4,644	4,288	—
	132,715	132,760	100,669
Total	208,649	201,962	189,618
Total Barrels of Oil Equivalent (in millions) (a) (b)	114	101	112

(a) In August 2018, the Corporation sold its joint venture interests in the Utica shale play, onshore U.S.  Utica net production was 3.3 million boe for calendar year 2018 (2017: 6.9 million boe).  In 2017, the Corporation sold its assets in Equatorial Guinea (November), Norway (December), and the Permian, onshore U.S. (August).  Permian produced 1.5 million boe for calendar year 2017.

(b) Includes 7,122 thousand mcf of net production for 2019 (2018: 6,442 thousand mcf; 2017: 4,256 thousand mcf) from Block PM301, which is unitized into Block A-18 of the JDA.

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E&P Operations

At December 31, 2019, our significant E&P assets included the following:

United States

Our production in the U.S. was from onshore properties, principally in the Bakken shale play in the Williston Basin of North Dakota (Bakken) and from offshore properties in the Gulf of Mexico.

Onshore:

Bakken:  At December 31, 2019, we held approximately 534,000 operated net acres in the Bakken with varying working interest percentages.  Net production averaged 152,000 boepd in 2019.  During the year, we operated six rigs, drilled 160 wells and brought 156 wells on production, bringing the total operated production wells to 1,575 by year-end.  Effective 2019, all new production wells use plug and perf completions.  We were able to reduce the average cost of a plug and perf well in 2019 to $6.8 million per well from $7.6 million in 2018.  

During 2020, we plan to operate six rigs, drill approximately 170 wells and bring approximately 175 wells on production.  We forecast net production to average approximately 180,000 boepd in 2020 and to reach approximately 200,000 boepd by the end of 2020.  In the third quarter of 2020, the Tioga Gas Plant will be shut down for approximately 45 days for a planned turnaround and tie-in of the plant expansion project which will increase gas processing capacity to 400 million cubic feet per day from 250 million cubic feet per day and is expected to be in service by mid-2021.  The shutdown for the turnaround is expected to reduce 2020 average net production, mostly natural gas liquids and natural gas, by approximately 6,000 boepd.  Commencing in 2021, we plan to reduce our rig count to four operated rigs and, at this level of activity, expect to hold net production relatively flat at approximately 200,000 boepd for at least five years.

Offshore:

Gulf of Mexico:  At December 31, 2019, we held approximately 73,000 net developed acres, with our production operations principally at the Baldpate (Hess 50%), Conger (Hess 38%), Hack Wilson (Hess 25%), Llano (Hess 50%), Penn State (Hess 50%), Shenzi (Hess 28%), Stampede (Hess 25%) and Tubular Bells (Hess 57%) fields.  At December 31, 2019, we held approximately 344,000 net undeveloped acres, of which leases covering approximately 81,000 acres are due to expire in the next three years.

In 2019, the Corporation announced a discovery at the Hess operated Esox-1 exploration well in Mississippi Canyon Block No. 726 (Hess 57%).  First production from the well was achieved in February 2020 as a tie-back to the Tubular Bells production facilities.  In 2020, we expect to drill up to two exploration wells in the Gulf of Mexico.

Guyana

Stabroek Block:  The Stabroek Block (Hess 30%), offshore Guyana, covers approximately 6.6 million acres, which is equivalent to approximately 1,150 Gulf of Mexico blocks.  The operator, Esso Exploration and Production Guyana Limited, has made sixteen significant discoveries since 2015.  The discovered resources to date on the Stabroek Block are expected to underpin the potential for at least five FPSOs producing more than 750,000 gross bopd by 2025.

Under the terms of our agreement with the government, the contractors (collectively affiliates of ExxonMobil – 45%, Hess – 30%, and CNOOC – 25%) are generally entitled to recover contract costs for exploration, development and production activities within the Stabroek Block (Cost Recovery) in an amount up to 75% of gross production in any month, with any excess Cost Recovery carried over to future periods.  All production not allocated to Cost Recovery in a given month (profit oil) is further allocated 50% to the government and 50% to the contractors.  The contractors must also pay a royalty of 2% based on gross production, either in cash or in-kind, at the election of the government.  Our resulting entitlement is 30% of the contractors’ share of production.

The Liza Phase 1 development, which was sanctioned in 2017, began producing oil in December 2019 from the Liza Destiny FPSO.  Production is expected to ramp up to the full capacity of 120,000 gross bopd in 2020.  We forecast net production for 2020 to average approximately 25,000 bopd.

The Liza Phase 2 development was sanctioned in 2019 and will utilize the Liza Unity FPSO to produce up to 220,000 gross bopd, with first production expected by early 2022.  Six drill centers are planned with a total of 30 wells, including 15 production wells, nine water injection wells and six gas injection wells.  In 2020, the operator plans to commence development drilling, installation of subsea flow lines and equipment, and installation of topside facilities modules on the Liza Unity FPSO.

A third development, at the Payara Field, is expected to be sanctioned following government and regulatory approvals and is expected to produce up to 220,000 gross bopd with startup as early as 2023.  In addition to the first three developments, planning is underway for

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additional FPSOs.  The ultimate sizing and timing of these potential developments will be a function of further exploration and appraisal drilling.

The operator is currently utilizing four drillships for exploration, appraisal and development drilling activities, and intends to bring in a fifth drillship in 2020.  

In 2019, the following exploration and appraisal wells were drilled on the Stabroek Block (in chronological order):

Tilapia: The Tilapia-1 well encountered approximately 305 feet of high-quality, oil-bearing sandstone reservoir and is located approximately 3.4 miles west of the Longtail-1 well.

Haimara: The Haimara-1 well encountered approximately 207 feet of high-quality, gas condensate bearing sandstone reservoir and is located approximately 19 miles east of the Pluma-1 well.

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.  

Hammerhead: The Hammerhead-2 well, located approximately 0.9 miles from the Hammerhead-1 discovery well, and the Hammerhead-3 well, located approximately 1.9 miles from Hammerhead-1, were both successfully drilled and encountered high quality, oil-bearing sandstone reservoir.  A drill stem test was also performed on Hammerhead-3.  Results are under evaluation.

Tripletail: The Tripletail-1 well encountered approximately 108 feet of high-quality oil-bearing sandstone reservoir and is located approximately 3 miles northeast of the Longtail discovery.  Additional oil-bearing reservoirs were subsequently encountered below the previously announced Tripletail discovery, which are still under evaluation.

Ranger:  The Ranger-2 appraisal well was completed, and a drill stem test was performed.  Results are under evaluation.

Mako: The Mako-1 well encountered approximately 164 feet of high-quality oil-bearing sandstone reservoir and is located approximately 6 miles southeast of the Liza Field.  

In January 2020, the operator announced the sixteenth discovery on the Stabroek Block at the Uaru-1 well.  The Uaru-1 well encountered approximately 94 feet of high-quality oil-bearing sandstone reservoir and is located approximately 10 miles northeast of the Liza Field.  The operator’s plans for 2020 exploration and appraisal drilling activities include focusing the first half of the year primarily on appraisal of discoveries in the greater Turbot area, and the second half of the year to include the drilling of several exploration wells, which is expected to include further tests of emerging deeper plays on the Stabroek Block.

Kaieteur Block:  In 2018, we acquired a participating interest in the Kaieteur Block (Hess 15%), which is adjacent to the Stabroek Block.  The operator, Esso Exploration and Production Guyana Limited, completed a 2D seismic shoot in 2019 and expects to drill the Tanager-1 exploration well in 2020.

Asia

Malaysia/Thailand Joint Development Area (JDA):  Production comes from the Carigali Hess operated offshore Block A-18 in the Gulf of Thailand (Hess 50%).  A multi-year drilling program is planned to commence in the fourth quarter of 2020.

Malaysia:  Our production in Malaysia comes from our interest in Block PM301 (Hess 50%), which is adjacent to and is unitized with Block A‑18 of the JDA and Block PM302 (Hess 50%) located in the North Malay Basin (NMB), offshore Peninsular Malaysia.  In 2020, we plan to continue drilling and development activities.

Europe

Denmark:  Production comes from our operated interest in the South Arne Field (Hess 62%).  In 2019, at the Hess operated License 6/16 (Hess 80%), the Corporation drilled the Jill-1 exploration commitment well, which did not encounter commercial quantities of hydrocarbons.

Africa

Libya:  At the onshore Waha concession in Libya, which includes the Defa, Faregh, Gialo, North Gialo and Belhedan fields (Hess 8%), net production averaged approximately 21,000 boepd in 2019 (2018: 20,000 boepd; 2017: 10,000 boepd).  In January 2020, the Libyan National Oil Company declared force majeure after oil exports were ceased at five oil export terminals.  The Company’s net investment in Libya was approximately $100 million at December 31, 2019.

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Other Non-Producing Countries

Suriname:  We hold a 33% non-operated participating interest in Block 42, offshore Suriname.  In 2021, the operator, Kosmos Energy Ltd., plans to drill an exploration well.  We also hold a 33% non-operated participating interest in Block 59, offshore Suriname, where the operator, ExxonMobil Exploration and Production Suriname B.V., is conducting a seismic program.  

Canada:  We hold a 50% non-operated participating interest in four exploration licenses offshore Nova Scotia and a 25% non-operated participating interest in three exploration licenses offshore Newfoundland.  In 2022, the operator BP Canada plans to drill one exploration well in Newfoundland.

Sales Commitments

We have certain long-term contracts with fixed minimum sales volume commitments for natural gas and NGL production.  At the JDA in the Gulf of Thailand, we have annual minimum net sales commitments of approximately 80 billion cubic feet of natural gas per year through 2025 and approximately 40 billion cubic feet per year in 2026 and 2027.  At the North Malay Basin development project offshore Peninsular Malaysia, we have annual net sales commitments of approximately 55 billion cubic feet per year through 2024.  Our estimated total volume of production subject to these sales commitments is approximately 835 billion cubic feet of natural gas.  We also have multiple minimum delivery commitments in the Bakken for natural gas and NGL with various end dates up through 2032, with total commitments of approximately 120 million boe over the remaining life of the contracts.

We have not experienced any significant constraints in satisfying the committed quantities required by our sales commitments, and we anticipate being able to meet future requirements from available proved and probable reserves, as well as projected third-party supply in the case of NGL.

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Selling Prices and Production Costs

The following table presents our average selling prices and average production costs:

	2019		2018		2017
Average selling prices (a)
Crude oil – per barrel (including hedging)
United States
Onshore	$	53.19	$	56.90	$	46.04
Offshore		59.18		62.02		47.34
Total United States		55.15		58.69		46.50
Europe		66.29		70.08		55.03
Africa		64.91		69.64		53.17
Asia		61.81		70.42		56.99
Worldwide		56.77		60.77		49.23
Crude oil – per barrel (excluding hedging)
United States
Onshore	$	53.18	$	60.64	$	46.76
Offshore		59.17		65.73		48.15
Total United States		55.14		62.41		47.25
Europe		66.29		70.08		55.14
Africa		64.91		69.64		53.25
Asia		61.81		70.42		56.99
Worldwide		56.76		63.80		49.75
Natural gas liquids – per barrel
United States
Onshore	$	13.20	$	21.29	$	17.67
Offshore		13.31		25.58		21.34
Total United States		13.21		21.81		18.10
Europe		—		—		29.04
Worldwide		13.21		21.81		18.35
Natural gas – per mcf
United States
Onshore	$	1.59	$	2.29	$	1.96
Offshore		2.12		2.68		2.22
Total United States		1.83		2.43		2.03
Europe		3.81		3.61		4.42
Asia and other		5.04		5.07		4.27
Worldwide		3.90		4.18		3.37
Average production (lifting) costs per barrel of oil equivalent produced (b)
United States
Onshore (c)	$	20.42	$	22.34	$	19.64
Offshore		11.27		13.80		11.89
Total United States		17.66		19.74		17.42
Europe		26.35		26.23		21.95
Africa		4.22		4.42		14.40
Asia and other		7.70		6.16		7.83
Worldwide		14.93		15.73		16.07

(a) Includes inter‑company transfers valued at approximate market prices, primarily onshore U.S., which include certain processing and distribution fees.

(b) Production (lifting) costs consist of amounts incurred to operate and maintain our producing oil and gas wells, related equipment and facilities and transportation costs, including Midstream tariff expense.  Lifting costs do not include costs of finding and developing proved oil and gas reserves, production and severance taxes, or the costs of related general and administrative expenses, interest expense and income taxes.

(c) Includes Midstream tariff expense of $12.89 per boe in 2019 (2018: $13.69 per boe; 2017: $11.10 per boe).

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Gross and Net Undeveloped Acreage

At December 31, 2019, gross and net undeveloped acreage amounted to:

	Undeveloped
	Acreage (a)
	Gross		Net
	(In thousands)
United States		389		362
South America		14,236		3,915
Europe		94		68
Africa		3,334		272
Asia and other (b)		6,350		2,755
Total (c)		24,403		7,372

(a) Includes acreage held under production sharing contracts.

(b) Includes 5.1 million gross acres (2.1 million net acres) offshore Canada.

(c) At December 31, 2019, 58% of our net undeveloped acreage, primarily offshore Canada and Suriname, is scheduled to expire during the next three years pending results of exploration activities.

Gross and Net Developed Acreage, and Productive Wells

At December 31, 2019 gross and net developed acreage and productive wells amounted to:

	Developed Acreage
	Applicable to				Productive Wells (a)
	Productive Wells				Oil				Gas
	Gross		Net		Gross		Net		Gross		Net
	(In thousands)
United States		1,008		591		2,897		1,336		15		7
South America		95		29		5		2		—		—
Europe		23		14		19		12		—		—
Africa		9,564		782		1,125		92		10		1
Asia and other		452		226		—		—		128		62
Total		11,142		1,642		4,046		1,442		153		70

(a) Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 112 gross wells and 65 net wells.

Exploratory and Development Wells

Net exploratory and net development wells completed during the years ended December 31 were:

	Net Exploratory Wells						Net Development Wells
	2019		2018		2017		2019		2018		2017
Productive wells
United States		—		—		—		140		92		65
South America		2		2		2		2		—		—
Europe		—		—		—		—		—		1
Africa		—		—		—		2		—		—
Asia and other		—		2		—		3		1		1
		2		4		2		147		93		67
Dry holes
United States		—		—		—		—		—		—
Europe		1		—		—		—		—		—
Africa (a)		—		—		—		—		—		—
Asia and other		—		2		—		—		—		—
		1		2		—		—		—		—
Total		3		6		2		147		93		67

(a) In 2017, we expensed seven wells in our Deepwater Tano/Cape Three Points Block, offshore Ghana, which were drilled in prior years.

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Number of Wells in the Process of Being Drilled

At December 31, 2019, the number of wells in the process of drilling amounted to:

	Gross		Net
	Wells		Wells
United States		194		54
South America		2		1
Asia and other		4		2
Total		200		57

Midstream

Prior to December 16, 2019, the Midstream segment was primarily comprised of Hess Infrastructure Partners LP (HIP), a 50/50 joint venture between Hess Corporation and Global Infrastructure Partners (GIP), formed to own, operate, develop and acquire a diverse set of midstream assets to provide fee-based services to Hess and third-party customers.  HIP was initially formed on May 21, 2015, with Hess selling 50% of HIP to GIP for approximately $2.6 billion on July 1, 2015.

On April 10, 2017, HIP completed an initial public offering (IPO) of 16,997,000 common units, representing 30.5% limited partnership interests in its subsidiary Hess Midstream Partners LP (Hess Midstream Partners), for net proceeds of approximately $365.5 million.  In connection with the IPO, HIP contributed a 20% controlling economic interest in each of Hess North Dakota Pipeline Operations LP, Hess TGP Operations LP, and Hess North Dakota Export Logistics Operations LP, and a 100% economic interest in Hess Mentor Storage Holdings LLC (collectively the “Contributed Businesses”).  In exchange for the contributed businesses, Hess and GIP each received common and subordinated units representing a direct 33.75% limited partner interest in Hess Midstream Partners and a 50% indirect ownership interest through HIP in Hess Midstream Partners’ general partner, which had a 2% economic interest in Hess Midstream Partners plus incentive distribution rights.  

On March 1, 2019, HIP acquired Hess’s existing Bakken 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 Hess Midstream Partners 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.  On January 25, 2018, Hess Midstream Partners entered into a 50/50 joint venture with Targa Resources Corp. to construct a new 200 million standard cubic feet per day gas processing plant call Little Missouri 4.  The plant, which is operated by Targa, was placed into service in the third quarter of 2019.

On December 16, 2019, Hess Midstream Partners acquired HIP, including HIP’s 80% interest in Hess Midstream Partners’ oil and gas midstream assets, HIP’s water services business and the outstanding economic general partner interest and incentive distribution rights in Hess Midstream Partners LP.  In addition, Hess Midstream Partners’ organizational structure converted from a master limited partnership into an “Up-C” structure in which Hess Midstream Partners’ public unitholders received newly issued Class A shares in a new public entity  named Hess Midstream LP (Hess Midstream), which is taxed as a corporation for U.S. Federal and State income tax purposes.  Hess Midstream Partners changed its name to “Hess Midstream Operations LP” (HESM Opco) and became a consolidated subsidiary of Hess Midstream, the new publicly listed entity.  As consideration for the acquisition, we received a cash payment of $301 million and approximately 115 million newly issued HESM Opco Class B units.  After giving effect to the acquisition and related transactions, public shareholders of Class A shares in Hess Midstream own 6% of the consolidated entity on an as-exchanged basis and Hess and GIP each own 47% of the consolidated entity on an as-exchanged basis, primarily through the sponsors’ ownership of Class B units in HESM Opco that are exchangeable into Class A shares of Hess Midstream on a one-for-one basis, or referred to as “Hess Corporation’s 47% consolidated ownership interest in Hess Midstream LP”.

At December 31, 2019, Midstream assets included the following:

• Natural Gas Gathering and Compression: A natural gas gathering and compression system located primarily in McKenzie, Williams and Mountrail Counties, North Dakota connecting Hess and third-party owned or operated wells to the Tioga Gas Plant, Little Missouri 4 Gas Plant, and third-party pipeline facilities.  This gathering system consists of approximately 1,350 miles of high and low pressure natural gas and NGL gathering pipelines with a current capacity of up to approximately 450 mmcfd, including an aggregate compression capacity of approximately 240 mmcfd.  The system also includes the Hawkeye Gas Facility, which contributes approximately 50 mmcfd of the system’s current compression capacity.

• Crude Oil Gathering: A crude oil gathering system located primarily in McKenzie, Williams and Mountrail Counties, North Dakota, connecting Hess and third-party owned or operated wells to the Ramberg Terminal Facility, the Tioga Rail Terminal

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and the Johnson’s Corner Header System.  The crude oil gathering system consists of approximately 550 miles of crude oil gathering pipelines with a current capacity of up to approximately 240,000 bopd.  The system also includes the Hawkeye Oil Facility, which contributes approximately 75,000 bopd of the system’s current capacity.

• Tioga Gas Plant: A natural gas processing and fractionation plant located in Tioga, North Dakota, with a current processing capacity of approximately 250 mmcfd and fractionation capacity of approximately 60,000 boepd.  In 2019, Hess Midstream LP announced plans to expand processing capacity at the plant by 150 mmcfd for total processing capacity of 400 mmcfd.  Capital expenditures for the expansion are expected to be $150 million and the expansion is expected to be in service by mid-2021.  The Tioga Gas Plant is expected to commence a shut down in the third quarter of 2020 for approximately 45 days for a planned turnaround and tie-in of the plant expansion project.

• Little Missouri 4: A natural gas processing plant in McKenzie County, North Dakota, with processing capacity of approximately 200 mmcfd, which was placed in service during the third quarter of 2019 and is operated by Targa Resources Corp.  Hess Midstream LP owns a 50% interest in Little Missouri 4 through a joint venture with Targa Resources Corp. and is entitled to half of the plant’s processing capacity.

• Mentor Storage Terminal: A propane storage cavern and rail and truck loading and unloading facility located in Mentor, Minnesota, with approximately 330,000 boe of working storage capacity.

• Ramberg Terminal Facility: A crude oil pipeline and truck receipt terminal located in Williams County, North Dakota with a delivery capacity of up to approximately 285,000 bopd of crude oil into an interconnecting pipeline for transportation to the Tioga Rail Terminal and to multiple third-party pipelines and storage facilities.

• Tioga Rail Terminal: A 140,000 bopd crude oil and 30,000 boepd NGL rail loading terminal in Tioga, North Dakota that is connected to the Tioga Gas Plant, the Ramberg Terminal Facility and our crude oil gathering system.  

• Crude Oil Rail Cars: A total of 550 crude oil rail cars, which we operate as unit trains consisting of approximately 100 to 110 crude oil rail cars.  These crude oil rail cars have been constructed to DOT-117 standards.

• Johnson’s Corner Header System: A crude oil pipeline header system located in McKenzie County, North Dakota that receives crude oil by pipeline from Hess and third parties and delivers crude oil to third-party interstate pipeline systems.  The facility has a delivery capacity of approximately 100,000 bopd of crude oil.

• Produced Water Gathering and Disposal: A produced water gathering system located primarily in Williams and Mountrail Counties, North Dakota, that transports produced water from the wellsite by approximately 250 miles of pipeline in gathering systems or by third-party trucking to water handling facilities for disposal.  We also transport produced water to twelve water handling and disposal facilities operated by third parties that have a combined permitted disposal capacity of 170,000 barrels per day.  In 2019, we completed construction of two water handling and disposal facilities with a disposal capacity of 20,000 barrels per day.

Competition and Market Conditions

See Item 1A. Risk Factors for a discussion of competition and market conditions.

Other Items

Emergency Preparedness and Response Plans and Procedures

We have in place a series of business and asset-specific emergency preparedness, response and business continuity plans that detail procedures for rapid and effective emergency response and environmental mitigation activities.  These plans are maintained, reviewed and updated as necessary to confirm their accuracy and suitability.  Where applicable, they are also reviewed and approved by the relevant host government authorities.

Responder training and drills are routinely held worldwide to assess and continually improve the effectiveness of our plans.  Our contractors, service providers, representatives from government agencies and, where applicable, joint venture partners participate in the drills to help ensure that emergency procedures are comprehensive and can be effectively implemented.

To complement internal capabilities and to help ensure coverage for our global operations, we maintain membership contracts with a network of local, regional and global oil spill response and emergency response organizations.  At the regional and global level, these organizations include Clean Gulf Associates (CGA), Marine Spill Response Corporation (MSRC), Marine Well Containment Company (MWCC), Wild Well Control (WWC) and Oil Spill Response Limited (OSRL).  CGA and MSRC are domestic spill response organizations and MWCC provides the equipment and personnel to contain underwater well control incidents in the Gulf of Mexico.  

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WWC provides firefighting, well control and engineering services globally.  OSRL is a global response organization and is available, when needed, to assist us with any of our assets.  In addition to owning response assets in their own right, the organization maintains business relationships that provide immediate access to additional critical response support services if required.  OSRL’s response assets include nearly 300 recovery and storage vessels and barges, more than 250 skimmers, over 600,000 feet of boom, 9 capping stacks and significant quantities of dispersants and other ancillary equipment, including aircraft.  In addition to external well control and oil spill response support, we have contracts with wildlife, environmental, meteorology, incident management, medical and security resources.  If we were to engage these organizations to obtain additional critical response support services, we would fund such services and, where appropriate, seek reimbursement under our insurance coverage, as described below.  In certain circumstances, we pursue and enter into mutual aid agreements with other companies and government cooperatives to receive and provide oil spill response equipment and personnel support.  We maintain close associations with emergency response organizations through our representation on the Executive Committees of CGA and MSRC, as well as the Board of Directors of OSRL.

We continue to participate in several industry-wide task forces that are studying better ways to assess the risk of and prevent onshore and offshore incidents, access and control blowouts in subsea environments, and improve containment and recovery methods.  The task forces are working closely with the oil and gas industry and international government agencies to implement improvements and increase the effectiveness of oil spill prevention, preparedness, response and recovery processes.

Insurance Coverage and Indemnification

We maintain insurance coverage that includes coverage for physical damage to our property, third-party liability, workers’ compensation and employers’ liability, general liability, sudden and accidental pollution and other coverage.  This insurance coverage is subject to deductibles, exclusions and limitations and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.

The amount of insurance covering physical damage to our property and liability related to negative environmental effects resulting from a sudden and accidental pollution event, excluding Atlantic Named Windstorm coverage for which we are self‑insured, varies by asset, based on the asset's estimated replacement value or the estimated maximum loss.  In the case of a catastrophic event, first party coverage consists of two tiers of insurance.  The first $400 million of coverage is provided through an industry mutual insurance group.  Above this $400 million threshold, insurance is carried which ranges in value up to $1.31 billion in total, depending on the asset coverage level, as described above.  The insurance programs covering physical damage to our property exclude business interruption protection for our E&P operations.  Additionally, we carry insurance that provides third-party coverage for general liability, and sudden and accidental pollution, up to $1.08 billion, which coverage under a standard joint operating arrangement would be reduced to our participating interest.  Our insurance policies renew at various dates each year.  Future insurance coverage could increase in cost and may include higher deductibles or retentions, or additional exclusions or limitations.  In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are deemed economically acceptable.

Generally, our drilling contracts (and most of our other offshore services contracts) provide for a mutual hold harmless indemnity structure whereby each party to the contract (the Corporation and Contractor) indemnifies the other party for injuries or damages to their personnel and property (and, often, those of its contractors/subcontractors) regardless of fault.  Variations may include indemnity exclusions to the extent a claim is attributable to the gross negligence and/or willful misconduct of a party.  Third‑party claims, on the other hand, are generally allocated on a fault basis.

We are customarily responsible for, and indemnify the Contractor against, all claims including those from third parties, to the extent attributable to pollution or contamination by substances originating from our reservoirs or other property and the Contractor is responsible for and indemnifies us for all claims attributable to pollution emanating from the Contractor’s property.  Variations may include indemnity exclusions to the extent a claim is attributable to the gross negligence and/or willful misconduct of a party.  Additionally, we are generally liable for all of our own losses and most third‑party claims associated with catastrophic losses such as damage to reservoirs, blowouts, cratering and loss of hole, regardless of cause, although exceptions for losses attributable to gross negligence and/or willful misconduct do exist.  Lastly some offshore services contracts include overall limitations of the Contractor’s liability equal to a fixed negotiated amount.  Variations may include exclusions of all contractual indemnities from the liability cap.

Under a standard joint operating agreement (JOA), each party is liable for all claims arising under the JOA, to the extent of its participating interest (operator or non-operator).  Variations include indemnity exclusions when the claim is based upon the gross negligence and/or willful misconduct of the operator, in which case the operator is solely liable.  The parties to the JOA may continue to be jointly and severally liable for claims made by third parties in some jurisdictions.  Further, under some production sharing contracts between a governmental entity and commercial parties, liability of the commercial parties to the government entity is joint and several.

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Environmental

Compliance with various existing environmental and pollution control regulations imposed by federal, state, local and foreign governments is not expected to have a material adverse effect on our financial condition or results of operations but increasingly stringent environmental regulations have resulted and will likely continue to result in higher capital expenditures and operating expenses for us and the oil and gas industry in general.  We spent approximately $20 million in 2019 for environmental remediation.  The level of other expenditures to comply with federal, state, local and foreign country environmental regulations is difficult to quantify as such costs are captured as mostly indistinguishable components of our capital expenditures and operating expenses.  For further discussion of environmental matters see Environment, Health and Safety in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Information about our Executive Officers

The following table presents information as of February 20, 2020 regarding executive officers of the Corporation:

Name	Age	Office Held* and Business Experience	Year Individual Became an Executive Officer
John B. Hess	65	Chief Executive Officer and Director	1983
		Mr. Hess has been Chief Executive Officer of the Corporation since 1995 and employed by the Corporation since 1977.  He has over 40 years of experience in the oil and gas industry.
Gregory P. Hill	58	President and Chief Operating Officer	2009
		Mr. Hill has been Chief Operating Officer since 2014 and President of the Corporation’s worldwide Exploration and Production business since joining the Corporation in January 2009.  Prior to joining the Corporation, Mr. Hill spent 25 years at Royal Dutch Shell and its affiliates in a variety of operations, engineering, technical and managerial roles in Asia-Pacific, Europe and the United States.
Timothy B. Goodell	62	Senior Vice President, General Counsel, Corporate Secretary and Chief	2009
		Compliance Officer
		Mr. Goodell has been the Senior Vice President and General Counsel of the Corporation since 2009, Corporate Secretary since 2016 and Chief Compliance Officer since 2017.  Prior to joining the Corporation in 2009, he was a partner at the law firm of White & Case, LLP where he spent 25 years.
John P. Rielly	57	Senior Vice President and Chief Financial Officer	2002
		Mr. Rielly has been the Senior Vice President and Chief Financial Officer of the Corporation since 2004.  Mr. Rielly previously served as Vice President and Controller of the Corporation from 2001 to 2004.  Prior to joining the Corporation in 2001, he was a Partner at Ernst & Young, LLP where he was employed for 17 years.
Richard Lynch	62	Senior Vice President, Technology and Services	2018
		Mr. Lynch has been Senior Vice President, Technology and Services of the Corporation since 2018.  Mr. Lynch previously was Senior Vice President Global Developments, Drilling and Completions from 2014.  Prior to joining the Corporation in 2014, Mr. Lynch spent over 30 years in well delivery and operations, as well as project and asset management, with BP plc and ARCO.
Gerbert Schoonman	54	Senior Vice President, Global Production	2020
		Mr. Schoonman has been Senior Vice President, Global Production of the Corporation since January 2020.  Since joining the Company in 2011, he served in various operational leadership roles, including as Vice President, Production – Asia Pacific, from January 2011 through August 2012; Vice President, Onshore – Bakken from September 2012 through December 2016; and most recently, as Vice President, Offshore since January 2017.  Prior to joining the Corporation, he spent 20 years with Royal Dutch Shell where he served in operational and leadership roles.

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Name	Age	Office Held* and Business Experience	Year Individual Became an Executive Officer
Andrew Slentz	58	Senior Vice President, Human Resources and Office Management	2016
		Mr. Slentz has been Senior Vice President, Human Resources of the Corporation since April 2016 and responsible for Office Management since 2018.  Prior to joining the Corporation in 2016, Mr. Slentz served as Executive Vice President of Administration and Human Resources at Peabody Energy since 2010.  Mr. Slentz has over 25 years in human resources experience at large international public companies.
Michael R. Turner	60	Senior Vice President	2014
		Mr. Turner has been Senior Vice President of the Corporation since January 2020.  He previously served as Senior Vice President, Global Production from January 2017 until December 2019 and Senior Vice President, Onshore from June 2009 to December 2016.  Prior to joining the Corporation in 2009, Mr. Turner spent 28 years with Royal Dutch Shell and its affiliates in a variety of production leadership positions around the world.  Mr. Turner will retire from the Corporation effective April 3, 2020.
Barbara Lowery-Yilmaz	63	Senior Vice President, Exploration	2014
		Ms. Lowery-Yilmaz has been the Senior Vice President, Exploration of the Corporation since August 2014.  Ms. Lowery-Yilmaz has over 30 years of oil and gas industry experience in exploration and technology with BP plc and its affiliates including senior leadership roles.

* All officers referred to herein hold office in accordance with the By-laws until the first meeting of directors in connection with the annual meeting of stockholders of the Registrant and until their successors shall have been duly chosen and qualified.  Each of said officers was elected to the office opposite their name on June 4, 2019 except Mr. Schoonman who was elected effective January 1, 2020.

Except for Mr. Slentz, each of the above officers has been employed by the Corporation or its affiliates in various managerial and executive capacities for more than five years.  Prior to joining the Corporation, Mr. Slentz served in senior executive positions in human resources at Peabody Energy and its affiliates.

Number of Employees

At December 31, 2019, we had 1,775 employees.

Website Access to Our Reports

We make available free of charge through our website, www.hess.com, our annual report on Form 10‑K, quarterly reports on Form 10‑Q, current reports on Form 8‑K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission.  The information on our website is not incorporated by reference in this report.  Our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and the charters for the Audit Committee, Compensation and Management Development Committee, Corporate Governance and Nominating Committee and Environmental, Health and Safety Committee of the Board of Directors are available on our website and are also available free of charge upon request to Investor Relations at our principal executive office.  We also file with the New York Stock Exchange (NYSE) an annual certification that our Chief Executive Officer is unaware of any violation of the NYSE’s corporate governance standards.

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Item 1A.  Risk Factors

Our business activities and the value of our securities are subject to significant risks, including the risk factors described below.  These risk factors could negatively affect our operations, financial condition, liquidity and results of operations, and as a result, holders and purchasers of our securities could lose part or all of their investments.  It is possible that additional risks relating to our securities may be described in a prospectus supplement if we issue securities in the future.

Our business and operating results are highly dependent on the market prices of crude oil, NGL and natural gas, which can be very volatile.  Our estimated proved reserves, revenue, operating cash flows, operating margins, liquidity, financial condition and future earnings are highly dependent on the benchmark market prices of crude oil, NGL and natural gas, and our associated realized price differentials, which are volatile and influenced by numerous factors beyond our control.  The major foreign oil producing countries, including members of OPEC, may exert considerable influence over the supply and price of crude oil and refined petroleum products.  Their ability to agree on a common policy on rates of production and other matters may have a significant impact on the oil markets.  Other factors include, but are not limited to: worldwide and domestic supplies of and demand for crude oil, NGL and natural gas, political conditions and events (including instability, changes in governments, armed conflict, economic sanctions and outbreaks of infectious diseases) around the world and in particular in crude oil or natural gas producing regions, the cost of exploring for, developing and producing crude oil, NGL and natural gas, the price and availability of alternative fuels or other forms of energy, the effect of energy conservation and environmental protection efforts and overall economic conditions globally.  The sentiment of commodities trading markets as well as other supply and demand factors may also influence the selling prices of crude oil, NGL and natural gas.  Average benchmark prices for 2019 were $57.04 per barrel for WTI (2018: $64.90; 2017: $50.85) and $64.16 per barrel for Brent (2018: $71.69; 2017: $54.74).  In order to manage the potential volatility of cash flows and credit requirements, we maintain significant bank credit facilities.  An inability to access, renew or replace such credit facilities or access other sources of funding as they mature would negatively impact our liquidity.  Furthermore, from time to time we have entered into, and may in the future, enter into or modify commodity price hedging arrangements to manage commodity price volatility.  These arrangements may limit potential upside from commodity price increases, or expose us to additional risks, such as counterparty credit risk, which could adversely impact our cash flow, liquidity or financial condition.

If we fail to successfully increase our reserves, our future crude oil and natural gas production will be adversely impacted.  We own or have access to a finite amount of oil and gas reserves, which will be depleted over time.  Replacement of oil and gas production and reserves, including proved undeveloped reserves, is subject to successful exploration drilling, development activities, and enhanced recovery programs.  Therefore, future oil and gas production is dependent on technical success in finding and developing additional hydrocarbon reserves.  Exploration activity involves the interpretation of seismic and other geological and geophysical data, which does not always successfully predict the presence of commercial quantities of hydrocarbons.  Drilling risks include unexpected adverse conditions, irregularities in pressure or formations, equipment failure, blowouts and weather interruptions.  Future developments may be affected by unforeseen reservoir conditions, which negatively affect recovery factors or flow rates.  Similar risks may be encountered in the production of oil and gas on properties acquired from others.  In addition, replacing reserves and developing future production are also influenced by the price of crude oil and natural gas and costs of drilling and development activities.  Lower crude oil and natural gas prices may reduce capital available for our exploration and development activities, render certain development projects uneconomic or delay their completion, and result in negative revisions to existing reserves while increasing drilling and development costs could negatively affect expected economic returns.

There are inherent uncertainties in estimating quantities of proved reserves and discounted future net cash flows, and actual quantities may be lower than estimated.  Numerous uncertainties exist in estimating quantities of proved reserves and future net revenues from those reserves.  Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses, and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates and could materially affect the estimated quantities of our proved reserves and the related future net revenues.  In addition, reserve estimates may be subject to downward or upward changes based on production performance, purchases or sales of properties, results of future development, prevailing oil and gas prices, production sharing contracts, which may decrease reserves as crude oil and natural gas prices increase, and other factors.  Crude oil prices declined in 2019, relative to 2018, resulting in reductions to our reported proved reserves.  In contrast, crude oil prices improved in 2017 and 2018, relative to preceding years, resulting in increases to our reported proved reserves.  If crude oil prices in 2020 average below prices used to determine proved reserves at December 31, 2019, it could have an adverse effect on our estimates of proved reserve volumes and on the value of our business.  See Crude Oil and Natural Gas Reserves in Critical Accounting Policies and Estimates in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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Catastrophic and other events, whether naturally occurring or man‑made, may materially affect our operations and financial condition.  Our oil and gas operations are subject to numerous risks and hazards inherent to operating in the crude oil and natural gas industry, including catastrophic events, which may damage or destroy assets, interrupt operations, result in personal injury and have other significant adverse effects.  These events include unexpected drilling conditions, pressure conditions or irregularities in reservoir formations, equipment malfunctions or failures, fires, explosions, blowouts, cratering, pipeline interruptions and ruptures, hurricanes, severe weather, geological events, shortages in availability of skilled labor or cyber‑attacks. We maintain insurance coverage against many, but not all, potential losses and liabilities in amounts we deem prudent, including for property and casualty losses.  There can be no assurance that such insurance will adequately protect us against liability from all potential consequences and damages.  Moreover, some forms of insurance may be unavailable in the future or be available only on terms that are deemed economically unacceptable.

We do not always control decisions made under joint operating agreements and the parties under such agreements may fail to meet their obligations.  We conduct many of our E&P operations through joint operating agreements with other parties under which we may not control decisions, either because we do not have a controlling interest or are not operator under the agreement.  There is risk that these parties may at any time have economic, business, or legal interests or goals that are inconsistent with ours, and therefore decisions may be made which are not what we believe is in our best interest.  Moreover, parties to these agreements may be unable to meet their economic or other obligations and we may be required to fulfill those obligations alone.  In either case, the value of our investment may be adversely affected.

We are subject to changing laws and regulations and other governmental actions that can significantly and adversely affect our business.  Political or regulatory developments and governmental actions, including Federal, state, local, territorial and foreign laws and regulations relating to tax increases and retroactive tax claims, disallowance of tax credits and deductions; expropriation or nationalization of property; mandatory government participation, cancellation or amendment of contract rights; imposition of capital controls or blocking of funds; changes in import and export regulations; reduction of sulfur content in bunker fuel; the imposition of tariffs, limitations on access to exploration and development opportunities; prohibition on hydraulic fracturing of wells; and anti-bribery or anti-corruption laws, may adversely affect our operations and those of our counterparties with whom we have contracted, which may affect our financial results.

We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms.  The exploration, development and production of crude oil and natural gas involve substantial costs, which may not be fully funded from operations.  Two of the three major credit rating agencies that rate our debt have assigned an investment grade rating.  Although, currently we do not have any borrowings under our long-term credit facility, a ratings downgrade, continued weakness in the oil and gas industry or negative outcomes within commodity and financial markets could adversely impact our access to capital markets by increasing the costs of financing, or by impacting our ability to obtain financing on satisfactory terms.  In addition, a ratings downgrade may require that we issue letters of credit or provide other forms of collateral under certain contractual requirements.  Any inability to access capital markets could adversely impact our financial adaptability and our ability to execute our strategy and may also expose us to heightened exposure to credit risk.  In addition, borrowings on credit facilities may use LIBOR as a benchmark for establishing the rate.  LIBOR is the subject of recent national, international and other regulatory guidance and proposals for reform.  These reforms and other pressures may cause LIBOR to be discontinued or to perform differently than in the past.  The consequences of these developments cannot be entirely predicted, but could include fluctuations in interest rates or an increase in the cost of credit facility borrowings.

Political instability in areas where we operate can adversely affect our business.  Some of the international areas in which we operate are politically less stable than other areas and may be subject to civil unrest, conflict, insurgency, corruption, security risks and labor unrest.  Political instability and civil unrest in North Africa, South America and the Middle East has affected and may continue to affect our interests in these areas as well as oil and gas markets generally.  In addition, geographic territorial border disputes may affect our business in certain areas, such as the border dispute between Guyana and Venezuela over a portion of the Stabroek Block.  Political instability exposes our operations to increased risks, including increased difficulty in obtaining required permits and government approvals, enforcing our agreements in those jurisdictions and potential adverse actions by local government authorities.  The threat of terrorism around the world also poses additional risks to our operations and the operations of the oil and gas industry in general.

Our oil and gas operations are subject to environmental risks and environmental laws and regulations that can result in significant costs and liabilities.  Our oil and gas operations are subject to environmental risks such as oil spills, produced water spills, gas leaks and ruptures and discharges of substances or gases that could expose us to substantial liability for pollution or other environmental damage.  Our operations are also subject to numerous U.S. federal, state, local and foreign environmental laws and regulations.  Non‑compliance with these laws and regulations may subject us to administrative, civil or criminal penalties, remedial clean-ups, natural resource damages and other liabilities.  In addition, increasingly stringent environmental regulations have resulted and will likely continue to result in higher capital expenditures and operating expenses for us.  Similarly, we have material legal obligations to dismantle, remove and abandon production facilities and wells that will

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occur many years in the future, in most cases.  These estimates may be impacted by future changes in regulations and other uncertainties.

Concerns have been raised in certain jurisdictions where we have operations concerning the safety and environmental impact of the drilling and development of shale oil and gas resources, particularly hydraulic fracturing, water usage, flaring of associated natural gas and air emissions.  While we believe that these operations can be conducted safely and with minimal impact on the environment, regulatory bodies are responding to these concerns and may impose moratoriums and new regulations on such drilling operations that would likely have the effect of prohibiting or delaying such operations and increasing their cost.

Climate change and sustainability initiatives may result in significant operational changes and expenditures, reduced demand for our products and adversely affect our business.  We recognize that climate change and sustainability is a growing global environmental concern.  Continuing political and social attention to the issue of climate change and sustainability has resulted in both existing and pending international agreements and national, regional or local legislation and regulatory measures to limit greenhouse gas emissions.  These agreements and measures may require, or could result in future legislation and regulatory measures that require, significant equipment modifications, operational changes, taxes, or purchase of emission credits to reduce emission of greenhouse gases from our operations, which may result in substantial capital expenditures and compliance, operating, maintenance and remediation costs.  In addition, our production is sold to third parties that produce petroleum fuels, which through normal end user consumption result in the emission of greenhouse gases.  As a result of heightened public awareness and attention to climate change and sustainability as well as continued regulatory initiatives to reduce the use of these fuels, demand for crude oil and other hydrocarbons may be reduced, which may have an adverse effect on our sales volumes, revenues and margins.  The imposition and enforcement of stringent greenhouse gas emissions reduction requirements could severely and adversely impact the oil and gas industry and therefore significantly reduce the value of our business.  In addition, certain financial institutions, institutional investors and other sources of capital have begun to limit or eliminate their investment in oil and gas activities due to concerns about climate change, which could make it more difficult to finance our business.  Furthermore, increasing attention to climate change risks and sustainability has resulted in governmental investigations, and public and private litigation, which could increase our costs or otherwise adversely affect our business.  For example, in 2017 certain municipalities and private associations in California, Rhode Island, and Maryland separately filed lawsuits against over 30 fossil fuel producers, including us, for alleged damages purportedly caused by climate change.

Our industry is highly competitive and many of our competitors are larger and have greater resources and more diverse portfolios than we have.  The petroleum industry is highly competitive and very capital intensive.  We encounter competition from numerous companies, including acquiring rights to explore for crude oil and natural gas.  To a lesser extent, we are also in competition with producers of alternative fuels or other forms of energy, including wind, solar and electric power, and in the future, could face increasing competition due to the development and adoption of new technologies.  Many competitors, including national oil companies, are larger and have substantially greater resources to acquire and develop oil and gas assets.  In addition, competition for drilling services, technical expertise and equipment may affect the availability of technical personnel and drilling rigs, resulting in increased capital and operating costs.  Many of our competitors have a more diverse portfolio of assets, which may minimize the impact of adverse events occurring at any one location.

Significant time delays between the estimated and actual occurrence of critical events associated with development projects may result in material negative economic consequences.  As part of our business, we are involved in large development projects, the completion of which may be delayed beyond what was originally planned.  Such examples include, but are not limited to, delays in receiving necessary approvals from project members or regulatory or other government agencies, timely access to necessary equipment, availability of necessary personnel, construction delays, unfavorable weather conditions, equipment failures, and outbreaks of infectious diseases.  These delays could impact our future results of operations and cash flows.

Departures of key members from our senior management team, and/or difficulty in recruiting and retaining adequate numbers of experienced technical personnel, could negatively impact our ability to deliver on our strategic goals.  Our future success depends upon the continued service of key members of our senior management team, who play an important role in developing and implementing our strategy.  The departure of key members of senior management or an inability to recruit and retain adequate numbers of experienced technical and professional personnel in the necessary locations may prevent us from executing our strategy in full or, in part, which could negatively impact our business.

We are dependent on oilfield service companies for items including drilling rigs, equipment, supplies and skilled labor.  An inability or significant delay in securing these services, or a high cost thereof, may result in material negative economic consequences.  The availability and cost of drilling rigs, equipment, supplies and skilled labor will fluctuate over time given the cyclical nature of the E&P industry.  As a result, we may encounter difficulties in obtaining required services or

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could face an increase in cost, which may impact our ability to run our operations and deliver projects on time with the potential for material negative economic consequences.

We engage in risk management transactions designed to mitigate commodity price volatility and other risks but such activities may impede our ability to benefit from commodity price increases and can expose us to similar potential counterparty credit risk as amounts due from the sale of hydrocarbons.  We may enter into commodity price hedging arrangements to protect us from commodity price declines.  These arrangements may, depending on the instruments used and the level of additional hedges involved, limit any potential upside from commodity price increases.  As with accounts receivable from the sale of hydrocarbons, we may be exposed to potential economic loss should a counterparty be unable or unwilling to perform their obligations under the terms of a hedging agreement.  In addition, we are exposed to risks related to changes in interest rates and foreign currency values, and may engage in hedging activities to mitigate related volatility.

One of our subsidiaries is the general partner of a publicly traded limited partnership, Hess Midstream LP.  The responsibilities associated with being a general partner expose us to a broader range of legal liabilities.  Our control of Hess Midstream LP bestows upon us additional duties and obligations including, but not limited to, the obligations associated with managing potential conflicts of interests and additional reporting requirements from the Securities and Exchange Commission.  These heightened duties expose us to additional potential for legal claims that may have a material negative economic impact on our shareholders.  Moreover, these increased duties may lead to an increase in compliance costs.

Disruption, failure or cyber security breaches affecting or targeting computer, telecommunications systems, and infrastructure used by the Corporation or our business partners may materially impact our business and operations.  Computers and telecommunication systems are an integral part of our exploration, development and production activities and the activities of our business partners.  We use these systems to analyze and store financial and operating data and to communicate within our corporation and with outside business partners.  Technical system flaws, power loss, cyber security risks, including cyber or phishing-attacks, unauthorized access, malicious software, data privacy breaches by employees or others with authorized access, ransomware, and other cyber security issues could compromise our computer and telecommunications systems or those of our business partners and result in disruptions to our business operations or the access, disclosure or loss of our data and proprietary information.  In addition, computers control oil and gas production, processing equipment, and distribution systems globally and are necessary to deliver our production to market.  A disruption, failure or a cyber breach of these operating systems, or of the networks and infrastructure on which they rely, could damage critical production, distribution and/or storage assets, delay or prevent delivery to markets, and make it difficult or impossible to accurately account for production and settle transactions.  As a result, any such disruption, failure or cyber breach and any resulting investigation or remediation costs, litigation or regulatory action could have a material adverse impact on our cash flows and results of operations, reputation and competitiveness.  We routinely experience attempts by external parties to penetrate and attack our networks and systems.  Although such attempts to date have not resulted in any material breaches, disruptions, financial loss, or loss of business-critical information, our systems and procedures for protecting against such attacks and mitigating such risks may prove to be insufficient in the future and such attacks could have an adverse impact on our business and operations, including damage to our reputation and competitiveness, remediation costs, litigation or regulatory actions.  In addition, as technologies evolve and these cyber security attacks become more sophisticated, we may incur significant costs to upgrade or enhance our security measures to protect against such attacks and we may face difficulties in fully anticipating or implementing adequate preventive measures or mitigating potential harm.

Item 1B.  Unresolved Staff Comments

None.

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Item 3.  Legal Proceedings

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

We, along with many companies that have been or continue to be engaged in refining and marketing of gasoline, have been a party to lawsuits and claims related to the use of methyl tertiary butyl ether (MTBE) in gasoline.  A series of similar lawsuits, many involving water utilities or governmental entities, were filed in jurisdictions across the U.S. against producers of MTBE and petroleum refiners who produced gasoline containing MTBE, including us.  The principal allegation in all cases was that gasoline containing MTBE was a defective product and that these producers and refiners are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE.  The majority of the cases asserted against us have been settled.  There are three remaining active cases, filed by Pennsylvania, Rhode Island, and Maryland.  In June 2014, the Commonwealth of Pennsylvania filed a lawsuit alleging that we and all major oil companies with operations in Pennsylvania, have damaged the groundwater by introducing thereto gasoline with MTBE.  The Pennsylvania suit has been forwarded to the existing MTBE multidistrict litigation pending in the Southern District of New York.  In September 2016, the State of Rhode Island also filed a lawsuit alleging that we and other major oil companies damaged the groundwater in Rhode Island by introducing thereto gasoline with MTBE.  The suit filed in Rhode Island is proceeding in Federal court.  In December 2017, the State of Maryland filed a lawsuit alleging that we and other major oil companies damaged the groundwater in Maryland by introducing thereto gasoline with MTBE.  The suit filed in Maryland state court, was served on us in January 2018 and has been removed to Federal court by the defendants.

In September 2003, we received a directive from the New Jersey Department of Environmental Protection (NJDEP) to remediate contamination in the sediments of the Lower Passaic River.  The NJDEP is also seeking natural resource damages.  The directive, insofar as it affects us, relates to alleged releases from a petroleum bulk storage terminal in Newark, New Jersey we previously owned.  We and over 70 companies entered into an Administrative Order on Consent with the 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.  Our alleged liability derives from our former ownership and operation of a fuel oil terminal and connected shipbuilding and repair facility adjacent to the Canal.  The remedy selected by the EPA includes dredging of surface sediments and the placement of a cap over the deeper sediments throughout the Canal and in-situ stabilization of certain contaminated sediments that will remain in place below the cap.  The EPA’s original estimate was that this remedy would cost $506 million; however, the ultimate costs that will be incurred in connection with the design and implementation of the remedy remain uncertain.  We have complied with the EPA’s March 2014 Administrative Order and contributed funding for the Remedial Design based on an allocation of costs among the parties determined by a third-party expert.  In January 2020, we received an additional Administrative Order from the EPA requiring us and several other parties to begin Remedial Action along the uppermost portion of the Canal.  We intend to comply with this Administrative Order.  The remediation work is anticipated to begin in the fourth quarter of 2020.  The costs will continue to be allocated amongst the parties, as they were for the Remedial Design.

We periodically receive notices from the EPA that we are a “potential responsible party” under the Superfund legislation with respect to various waste disposal sites.  Under this legislation, all potentially responsible parties may be jointly and severally liable.  For any site for which we have received such a notice, the EPA’s claims or assertions of liability against us relating to these sites have not been fully developed, or the EPA’s claims have been settled or a settlement is under consideration, in all cases for amounts that are not material.  The ultimate impact of these proceedings, and of any related proceedings by

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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.

Item 4.  Mine Safety Disclosures

None.

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PART II

Item 5.  Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities

Stock Market Information, Holders and Dividends

Our common stock is traded principally on the New York Stock Exchange (ticker symbol: HES).  At January 31, 2020, there were 2,944 stockholders (based on the number of holders of record) who owned a total of 305,214,587 shares of common stock.  In 2019, 2018 and 2017, cash dividends on common stock totaled $1.00 per share per year ($0.25 per quarter).

Performance Graph

Set forth below is a line graph comparing the five-year shareholder returns on a $100 investment in our common stock assuming reinvestment of dividends, against the cumulative total returns for the following:

• Standard & Poor’s (S&P) 500 Stock Index, which includes us.

• Proxy Peer Group comprising 12 oil and gas peer companies, including us, as disclosed in our 2019 Proxy Statement, excluding Anadarko Petroleum Corporation, which was acquired in August 2019.

Comparison of Five‑Year Shareholder Returns

Years Ended December 31,

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Share Repurchase Activities

Our share repurchases for the year ended December 31, 2019, were as follows:

2019	Total Number of Shares Purchased (a) (b)		Average Price Paid per Share (a)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (c)		Maximum Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs (d) (In millions)
March 1, 2019 through March 31, 2019		32,260	$	56.62		—	$	650
Total for 2019		32,260	$	56.62		—

(a) Repurchased in open‑market transactions.  The average price paid per share was inclusive of transaction fees.

(b) All of the shares repurchased were subsequently granted to Directors in accordance with the Non-Employee Directors’ Stock Award Plan.

(c) Since initiation of the buyback program in August 2013, total shares repurchased through December 31, 2019 amounted to 91.9 million at a total cost of $6.85 billion including transaction fees.

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

Equity Compensation Plans

Following is information related to our equity compensation plans at December 31, 2019.

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights *			Weighted Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column*)
Equity compensation plans approved by security holders		4,300,802	(a)	$	63.24		16,385,179	(b)
Equity compensation plans not approved by security holders (c)		—			—		—

(a) This amount includes 4,300,802 shares of common stock issuable upon exercise of outstanding stock options.  This amount excludes 929,025 performance share units (PSUs) for which the number of shares of common stock to be issued may range from 0% to 200%, based on our total shareholder return (TSR) relative to the TSR of a predetermined group of peer companies over a three‑year performance period ending December 31 of the year prior to settlement of the grant.  In addition, this amount also excludes 2,014,306 shares of common stock issued as restricted stock pursuant to our equity compensation plans.

(b) These securities may be awarded as stock options, restricted stock, PSUs or other awards permitted under our equity compensation plan.

(c) We have a Non-Employee Director’s Stock Award Plan pursuant to which each of our non-employee directors received $175,000 in value of our common stock.  These awards are made from shares we have purchased in the open market.

See Note 11, Share‑based Compensation in the Notes to Consolidated Financial Statements for further discussion of our equity compensation plans.

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Item 6.  Selected Financial Data

The following is a five‑year summary of selected financial data that should be read in conjunction with both our Consolidated Financial Statements and Accompanying Notes, and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included elsewhere in this Annual Report:

	2019				2018				2017				2016				2015
	(In millions, except per share amounts)
Income Statement Selected Financial Data
Sales and other operating revenues
Crude oil (a)	$	5,233			$	4,960			$	4,239			$	3,639			$	5,259
Natural gas liquids (a)		347				533				457				264				244
Natural gas (a)		876				965				750				766				1,052
Other operating revenues (b)		39				(135	)			20				93				81
Total Sales and other operating revenues	$	6,495			$	6,323			$	5,466			$	4,762			$	6,636
Income (loss) from continuing operations	$	(240	)		$	(115	)		$	(3,941	)		$	(6,076	)		$	(2,959	)
Income (loss) from discontinued operations		—				—				—				—				(48	)
Net income (loss)	$	(240	)		$	(115	)		$	(3,941	)		$	(6,076	)		$	(3,007	)
Less: Net income (loss) attributable to noncontrolling interests		168				167				133				56				49
Net income (loss) attributable to Hess Corporation	$	(408	)	(d)	$	(282	)	(e)	$	(4,074	)	(f)	$	(6,132	)	(g)	$	(3,056	)	(h)
Net Income (Loss) Attributable to Hess Corporation Per Common Share:
Basic:
Continuing operations	$	(1.37	)		$	(1.10	)		$	(13.12	)		$	(19.92	)		$	(10.61	)
Discontinued operations		—				—				—				—				(0.17	)
Net income (loss) per share	$	(1.37	)		$	(1.10	)		$	(13.12	)		$	(19.92	)		$	(10.78	)
Diluted:
Continuing operations	$	(1.37	)		$	(1.10	)		$	(13.12	)		$	(19.92	)		$	(10.61	)
Discontinued operations		—				—				—				—				(0.17	)
Net income (loss) per share	$	(1.37	)		$	(1.10	)		$	(13.12	)		$	(19.92	)		$	(10.78	)
Balance Sheet Selected Financial Data
Total assets	$	21,782			$	21,433			$	23,112			$	28,621			$	34,157
Total debt and Finance lease obligations (c)	$	7,397			$	6,672			$	6,977			$	6,806			$	6,592
Total equity	$	9,706			$	10,888			$	12,354			$	15,591			$	20,401
Dividends Per Share
Dividends per share of common stock	$	1.00			$	1.00			$	1.00			$	1.00			$	1.00

(a) Represents sales of Hess net production and purchased third-party volumes.

(b) Commencing with the adoption of Accounting Standards Codification (ASC) 606, Revenue from Contracts with Customers, using the modified retrospective method effective January 1, 2018, gains (losses) on commodity derivatives are included within Other operating revenue.  Prior to January 1, 2018, gains (losses) on commodity derivatives were included within Crude oil revenues.

(c) At December 31, 2019 includes debt from our Midstream operating segment of $1,753 million that is non-recourse to Hess Corporation (2018: $981 million; 2017: $980 million; 2016: $733 million; 2015: $704 million).

(d) Includes an allocation of noncash income tax expense of $86 million that was previously a component of accumulated other comprehensive income related to our 2019 crude oil hedge contracts, an after-tax charge of $88 million related to a pension settlement, a charge after income taxes and noncontrolling interests of $16 million for transaction related costs for Hess Midstream Partners LP acquisition of HIP and corporate restructuring, and an after-tax charge of $19 million related to a settlement on historical cost recovery balances in the JDA.  These charges were partially offset by a noncash income tax benefit of $60 million to reverse a valuation allowance against net deferred tax assets in Guyana upon achieving first production, and an after-tax gain of $22 million related to the sale of our remaining acreage in the Utica shale play.

(e) Includes after-tax charges of $221 million related to exit costs, settlement of legal claims related to a former downstream interest, and a loss from debt extinguishment.  These charges were, partially offset by a noncash income tax benefit of $91 million primarily related to intraperiod income tax allocation requirements resulting from changes in fair value of our 2019 crude oil hedging program, and gains totaling $24 million related to asset sales.

(f) Includes after-tax impairment charges of $2,250 million (Gulf of Mexico and Norway), an after-tax dry hole and lease impairment charge of $280 million (Ghana), a combined after-tax loss of $91 million related to asset sales (Norway, Equatorial Guinea and Permian), and after-tax charges of $52 million primarily for de-designated crude oil hedging contracts and other exit costs.

(g) Includes noncash charges of $3,749 million to establish valuation allowances on deferred tax assets following a three-year cumulative loss and after-tax charges of $894 million primarily for dry hole and other exploration expenses, loss on debt extinguishment, offshore rig costs, severance, and impairment of older specification rail cars.

(h) Includes total after-tax charges of $1,943 million, including noncash charges of $1,483 million to write-off all goodwill associated with our Exploration and Production operating segment.

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Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Form 10-K in Item 8, the information set forth in Risk Factors under Item 1A.

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations omits certain discussions of our financial condition and results of operations for the year ended December 31, 2017 compared with the year ended December 31, 2018, which can be found in Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2018 Annual Report on Form 10-K, which was filed with the Securities and Exchange Commission on February 21, 2019, and such comparisons are incorporated herein by reference. 

Index

Overview

Hess Corporation is a global Exploration and Production (E&P) company engaged in exploration, development, production, transportation, purchase and sale of crude oil, NGL, and natural gas with production operations and development activities located primarily in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA), Malaysia, and Denmark.  We conduct exploration activities primarily offshore Guyana, the U.S. Gulf of Mexico, and offshore Suriname and Canada.  At the Stabroek Block (Hess 30%), offshore Guyana, we have announced sixteen significant discoveries.  The Liza Phase 1 development achieved first production in December 2019, with peak production expected to reach up to 120,000 gross bopd.  The Liza Phase 2 development was sanctioned in the second quarter of 2019 and is expected to start up by early 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 FPSOs producing more than 750,000 gross bopd by 2025.

Our Midstream operating segment, which is comprised of Hess Corporation’s 47% consolidated ownership interest in Hess Midstream LP at December 31, 2019, provides fee-based services, including gathering, compressing and processing natural gas and fractionating NGL; gathering, terminaling, loading and transporting crude oil and NGL; storing and terminaling propane, and water handling services primarily in the Bakken shale play in the Williston Basin area of North Dakota.  See Note 6, Hess Midstream in the Notes to Consolidated Financial Statements.

2020 Outlook

Our E&P capital and exploratory expenditures are projected to be approximately $3.0 billion in 2020.  Capital investment for our Midstream operations is expected to be approximately $350 million.  Oil and gas net production in 2020 is forecast to be in the range of 330,000 boepd to 335,000 boepd excluding Libya, up from 290,000 boepd in 2019, excluding Libya.  Currently, we have West Texas Intermediate (WTI) put options for calendar year 2020 with an average monthly floor price of $55 per barrel for 130,000 bopd, and Brent put options for calendar year 2020 with an average monthly floor price of $60 per barrel for 20,000 bopd.

Net cash provided by operating activities was $1,642 million in 2019, compared with $1,939 million in 2018, while net cash provided by operating activities before changes in operating assets and liabilities was $2,237 million in 2019 and $2,129 million in 2018.  Capital expenditures for 2019 and 2018 were $2,992 million and $2,180 million, respectively.  In 2020, based on current forward strip crude oil prices, we expect cash flow from operating activities, cash and cash equivalents existing at December 31, 2019 of $1.5 billion, and our available committed revolving credit facility will be sufficient to fund our capital investment program and dividends.

Consolidated Results

Net loss attributable to Hess Corporation was $408 million in 2019 (2018: $282 million).  Excluding items affecting comparability of earnings between periods summarized on page 30, the adjusted net loss was $281 million in 2019 (2018: $176 million).  Annual net production averaged 311,000 boepd in 2019 (2018: 277,000 boepd).  Total proved reserves were 1,197 million boe at December 31, 2019 (2018: 1,192 million boe).

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Significant 2019 Activities

The following is an update of significant E&P activities during 2019:

E&P assets:

• In North Dakota, net production from the Bakken shale play averaged 152,000 boepd (2018: 117,000 boepd), with net oil production up 22% to 93,000 bopd from 76,000 bopd in the prior year, primarily due to increased drilling activity and new plug and perf completion design.  Natural gas and NGL production was also higher due to the increased drilling activity, additional natural gas captured with the start-up of the Little Missouri 4 natural gas processing plant in the third quarter of 2019 and additional NGL received under percentage of proceeds contracts resulting from lower NGL commodity pricing.  During the year, we operated six rigs, drilled 160 wells and brought on production 156 wells.  Effective 2019, all new production wells use plug and perf completions.  We were able to reduce the average cost of a plug and perf well in 2019 to $6.8 million per well from $7.6 million in 2018.  

During 2020, we plan to operate six rigs, drill approximately 170 wells and bring approximately 175 wells on production.  We forecast net production to average approximately 180,000 boepd in 2020 and to reach approximately 200,000 boepd by the end of 2020.  In the third quarter of 2020, the Tioga Gas Plant will be shut down for approximately 45 days for a planned turnaround and tie-in of the plant expansion project which will increase gas processing capacity to 400 million cubic feet per day from 250 million cubic feet per day and is expected to be in service by mid-2021.  The shutdown for the turnaround is expected to reduce 2020 average net production, mostly natural gas liquids and natural gas, by approximately 6,000 boepd.  Commencing in 2021, we plan to reduce our rig count to four operated rigs and, at this level of activity, expect to hold net production relatively flat at approximately 200,000 boepd for at least five years.

• In the Gulf of Mexico, net production averaged 66,000 boepd (2018: 57,000 boepd).  The increase in production was primarily due to the Conger and Penn State fields and a new well brought online at the Llano Field.  We forecast Gulf of Mexico net production for 2020 to average approximately 65,000 boepd, which reflects the impact of planned maintenance at the Conger and Llano fields in the second quarter.

In 2019, the Corporation announced a discovery at the Hess operated Esox-1 exploration well in Mississippi Canyon Block No. 726 (Hess 57%), which encountered approximately 191 feet of net pay in high-quality oil-bearing Miocene reservoirs.  First production from the well was achieved in February 2020 as a tie-back to the Tubular Bells production facilities.  

During the fourth quarter of 2019, the operator, Kosmos Energy Ltd., commenced drilling of the Oldfield-1 exploration well (Hess 60%), located approximately 6 miles east of Esox-1.  The well, which was completed in January 2020, did not encounter commercial quantities of hydrocarbons and 2019 results include $15 million in exploration expense for well costs incurred through December 31, 2019.  We estimate approximately $15 million of exploration expense will be recognized in the first quarter of 2020 for well costs incurred after December 31, 2019.

• At the Stabroek Block (Hess 30%), offshore Guyana, which covers approximately 6.6 million acres, the operator Esso Exploration and Production Guyana Limited has made sixteen significant discoveries since 2015.  The discovered resources to date on the Stabroek Block are expected to underpin the potential for at least five FPSOs producing more than 750,000 gross bopd by 2025.

The Liza Phase 1 development, which was sanctioned in 2017, began producing oil in December 2019 from the Liza Destiny FPSO.  Production is expected to ramp up to the full capacity of 120,000 gross bopd in 2020.  We forecast net production for 2020 to average approximately 25,000 bopd.

The Liza Phase 2 development was sanctioned in 2019 and will utilize the Liza Unity FPSO to produce up to 220,000 gross bopd, with first production expected by early 2022.  Six drill centers are planned with a total of 30 wells, including 15 production wells, nine water injection wells and six gas injection wells.  In 2020, the operator plans to commence development drilling, installation of subsea flow lines and equipment, and installation of topside facilities modules on the Liza Unity FPSO.  

A third development, at the Payara Field, is expected to be sanctioned following government and regulatory approvals and is expected to produce up to 220,000 gross bopd with startup as early as 2023.  In addition to the first three developments, planning is underway for additional FPSOs.  The ultimate sizing and timing of these potential developments will be a function of further exploration and appraisal drilling.

In 2019, five successful exploration wells and three successful appraisal wells were drilled on the Stabroek Block.  See detailed well results on page 9 of Items 1 and 2.  Business and Properties.

• In the Gulf of Thailand, net production from Block A‑18 of the JDA averaged 35,000 boepd for the year (2018: 36,000 boepd), including contribution from unitized acreage in Malaysia, while net production from North Malay

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Basin averaged 28,000 boepd for the year (2018: 27,000 boepd).  During 2019, we drilled six production wells at North Malay Basin, and plan to continue the drilling program and development activities in 2020.  We also expect to commence drilling activities in the fourth quarter of 2020 at the JDA.  Combined net production from our JDA and North Malay Basin assets is forecast to average approximately 60,000 boepd in 2020.

The following is an update of significant Midstream activities during 2019:

• In March, Hess Infrastructure Partners LP (HIP) completed the acquisition of Hess’ water services business for $225 million in cash.

• In March, HIP and Hess Midstream Partners LP 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.

• The Little Missouri 4 gas processing plant, a 50/50 joint venture between Hess Midstream LP and Targa Resources Corp., was placed in service during the third quarter.

• In December, Hess Midstream Partners LP completed the acquisition of HIP and converted its organizational structure from a master limited partnership into an “Up-C” structure in which Hess Midstream Partners LP’s public unitholders received newly issued Class A shares in a new public entity named Hess Midstream LP (Hess Midstream).  Upon completion of the transaction, we received consideration of $301 million in cash and additional equity interests in Hess Midstream LP, resulting in Hess Corporation’s 47% consolidated ownership in Hess Midstream LP.  See Note 6, Hess Midstream and Note 8, Debt in the Notes to Consolidated Financial Statements.

Liquidity and Capital and Exploratory Expenditures

In 2019, net cash provided by operating activities was $1,642 million (2018: $1,939 million).  At December 31, 2019, consolidated cash and cash equivalents were $1,545 million (2018: $2,694 million), consolidated debt was $7,142 million (2018: $6,672 million, including capital lease obligations), and our consolidated debt to capitalization ratio was 43.2% (2018: 38.0%).  Hess Midstream debt, which is nonrecourse to Hess Corporation, was $1,753 million at December 31, 2019 (2018: $981 million).

Capital and exploratory expenditures were as follows (in millions):

	2019		2018		2017
E&P Capital and Exploratory Expenditures:
United States
Bakken	$	1,312	$	967	$	624
Other Onshore		45		43		30
Total Onshore		1,357		1,010		654
Offshore		426		368		702
Total United States		1,783		1,378		1,356
Guyana		783		383		236
Europe		40		8		142
Asia and Other		137		300		313
E&P - Capital and Exploratory Expenditures	$	2,743	$	2,069	$	2,047

Exploration Expenses Charged to Income Included Above:
United States	$	105	$	106	$	90
International		62		54		105
Total Exploration Expenses Charged to Income included above	$	167	$	160	$	195

Midstream Capital Expenditures:
Midstream - Capital Expenditures (a)	$	416	$	271	$	121

(a) Excludes equity investments of $33 million in 2019 (2018: $67 million).

In 2020, we project our E&P capital and exploratory expenditures will be approximately $3.0 billion and Midstream capital expenditures to be approximately $350 million.

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Consolidated Results of Operations

Results by Segment:

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

	2019			2018			2017
	(In millions, except per share amounts)
Net Income (Loss) Attributable to Hess Corporation:
Exploration and Production	$	53		$	51		$	(3,653	)
Midstream		144			120			42
Corporate, Interest and Other		(605	)		(453	)		(463	)
Total	$	(408	)	$	(282	)	$	(4,074	)
Net Income (Loss) Attributable to Hess Corporation Per Common Share - Diluted (a)	$	(1.37	)	$	(1.10	)	$	(13.12	)

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

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.

Items affecting comparability of earnings between periods:

The following table summarizes items of income (expense) that are included in net income (loss) and affect comparability of earnings between periods.  The items in the table below are explained on pages 36 through 39.

	2019			2018			2017
	(In millions)
Items Affecting Comparability of Earnings Between Periods, After Income Taxes:
Exploration and Production	$	63		$	(86	)	$	(2,609	)
Midstream		(16	)		—			(34	)
Corporate, Interest and Other		(174	)		(20	)		(30	)
Total	$	(127	)	$	(106	)	$	(2,673	)

The following table presents the pre-tax amount of items affecting comparability of income (expense) by financial statement line item in the Statement of Consolidated Income on page 55.  The items in the table below are explained on pages 36 through 39.

	Before Income Taxes
	2019			2018			2017
	(In millions)
Sales and other operating revenues	$	—		$	—		$	(22	)
Gains (losses) on asset sales, net		22			24			(98	)
Other, net		(88	)		—			—
Marketing, including purchased oil and gas		(21	)		—			—
Operating costs and expenses		—			(19	)		—
Exploration expenses, including dry holes and lease impairment		—			(3	)		(280	)
General and administrative expenses		(30	)		(130	)		(11	)
Loss on debt extinguishment		—			(53	)		—
Depreciation, depletion and amortization		—			(16	)		(19	)
Impairment		—			—			(4,203	)
Total Items Affecting Comparability of Earnings Between Periods, Pre-Tax	$	(117	)	$	(197	)	$	(4,633	)

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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:

	2019			2018			2017
	(In millions)
Adjusted Net Income (Loss) Attributable to Hess Corporation:
Net income (loss) attributable to Hess Corporation	$	(408	)	$	(282	)	$	(4,074	)
Less: Total items affecting comparability of earnings between periods, after-tax		(127	)		(106	)		(2,673	)
Adjusted Net Income (Loss) Attributable to Hess Corporation	$	(281	)	$	(176	)	$	(1,401	)

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

	2019			2018			2017
	(In millions)
Net cash provided by operating activities before changes in operating assets and liabilities:
Net cash provided by (used in) operating activities	$	1,642		$	1,939		$	945
Less: Changes in operating assets and liabilities		(595	)		(190	)		(799	)
Net cash provided by (used in) operating activities before changes in operating assets and liabilities	$	2,237		$	2,129		$	1,744

Adjusted net income (loss) attributable to Hess Corporation is a non-GAAP financial measure, which we define as reported net income (loss) attributable to Hess Corporation excluding items identified as affecting comparability of earnings between periods, which are summarized on pages 36 through 39.  Management uses adjusted net income (loss) to evaluate the Corporation’s operating performance and believes that investors’ understanding of our performance is enhanced by disclosing this measure, which excludes certain items that management believes are not directly related to ongoing operations and are not indicative of future business trends and operations.  

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

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

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Comparison of Results

Exploration and Production

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

	2019		2018		2017
	(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues	$	6,495	$	6,323	$	5,460
Gains (losses) on asset sales, net		22		27		(39	)
Other, net		51		53		(1	)
Total revenues and non-operating income		6,568		6,403		5,420
Costs and Expenses
Marketing, including purchased oil and gas		1,849		1,833		1,335
Operating costs and expenses		971		941		1,248
Production and severance taxes		184		171		119
Midstream tariffs		722		648		543
Exploration expenses, including dry holes and lease impairment		233		362		507
General and administrative expenses		204		258		224
Depreciation, depletion and amortization		1,977		1,748		2,736
Impairment		—		—		4,203
Total costs and expenses		6,140		5,961		10,915
Results of Operations Before Income Taxes		428		442		(5,495	)
Provision (benefit) for income taxes (a)		375		391		(1,842	)
Net Income (Loss) Attributable to Hess Corporation	$	53	$	51	$	(3,653	)

(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 86 for further details.

Excluding the E&P items affecting comparability of earnings between periods in the table on page 36, the changes in E&P results are primarily attributable to changes in selling prices, production and sales volumes, marketing expenses, cash operating costs, Midstream tariffs, depreciation, depletion and amortization, exploration expenses and income taxes, as discussed below.

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Selling Prices: Average worldwide realized crude oil selling prices, including hedging, were 7% lower in 2019 compared with the prior year, primarily due to the decrease in Brent and WTI crude oil prices.  In addition, realized worldwide selling prices for NGL decreased in 2019 by 39% and worldwide natural gas prices decreased in 2019 by 7%, compared with the prior year.  In total, lower realized selling prices decreased 2019 financial results by approximately $380 million after income taxes, compared with 2018.  Our average selling prices were as follows:

	2019 (a)		2018 (a)		2017
Crude Oil - Per Barrel (Including Hedging)
United States
Onshore	$	53.19	$	56.90	$	46.04
Offshore		59.18		62.02		47.34
Total United States		55.15		58.69		46.50
Europe		66.29		70.08		55.03
Africa		64.91		69.64		53.17
Asia		61.81		70.42		56.99
Worldwide		56.77		60.77		49.23
Crude Oil - Per Barrel (Excluding Hedging)
United States
Onshore	$	53.18	$	60.64	$	46.76
Offshore		59.17		65.73		48.15
Total United States		55.14		62.41		47.25
Europe		66.29		70.08		55.14
Africa		64.91		69.64		53.25
Asia		61.81		70.42		56.99
Worldwide		56.76		63.80		49.75
Natural Gas Liquids - Per Barrel
United States
Onshore	$	13.20	$	21.29	$	17.67
Offshore		13.31		25.58		21.34
Total United States		13.21		21.81		18.10
Europe		—		—		29.04
Worldwide		13.21		21.81		18.35
Natural Gas - Per Mcf
United States
Onshore	$	1.59	$	2.29	$	1.96
Offshore		2.12		2.68		2.22
Total United States		1.83		2.43		2.03
Europe		3.81		3.61		4.42
Asia and other		5.04		5.07		4.27
Worldwide		3.90		4.18		3.37

(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 2019 would be $59.95 per barrel for crude oil (including hedging) (2018: $63.77), $59.94 per barrel for crude oil (excluding hedging) (2018: $66.80), $13.40 per barrel for NGL (2018: $22.00) and $3.97 per mcf for natural gas (2018: $4.25).

Crude oil hedging activities were a net gain of $1 million before and after income taxes in 2019, and a loss of $183 million before and after income taxes in 2018.  For calendar year 2020, we have WTI put options with an average monthly floor price of $55 per barrel for 130,000 bopd, and Brent put options with an average monthly floor price of $60 per barrel for 20,000 bopd.  We expect noncash put option premium amortization, which will be reflected in realized selling prices, to reduce our 2020 results by approximately $70 million per quarter.

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

	2019			2018			2017
	(In thousands)
Crude Oil - Barrels
United States
Bakken		93			76			67
Other Onshore (a)		1			1			6
Total Onshore		94			77			73
Offshore		46			41			39
Total United States		140			118			112
Europe (b)		6			6			28
Africa (c)		19			18			35
Asia and other		4			4			2
Worldwide		169			146			177
Natural Gas Liquids - Barrels
United States
Bakken		41			29			28
Other Onshore (a)		1			5			8
Total Onshore		42			34			36
Offshore		5			5			5
Total United States		47			39			41
Europe (b)		—			—			1
Worldwide		47			39			42
Natural Gas - Mcf
United States
Bakken		107			70			62
Other Onshore (a)		3			44			92
Total Onshore		110			114			154
Offshore		91			67			57
Total United States		201			181			211
Europe (b)		7			8			33
Asia and other		364			364			276
Worldwide		572			553			520
Barrels of Oil Equivalent		311			277			306
Crude oil and natural gas liquids as a share of total production		69	%		67	%		72	%

(a) The Corporation sold its Utica assets in August 2018.  Production was 9,000 boepd for the year ended December 31, 2018 and 19,000 boepd for the year ended December 31, 2017.  The Corporation sold its Permian assets in August 2017.  Production was 4,000 boepd for the year ended December 31, 2017.

(b) The Corporation sold its Norway assets in December 2017.  Production was 24,000 boepd for the year ended December 31, 2017.

(c) The Corporation sold its Equatorial Guinea assets in November 2017.  Production was 25,000 boepd for the year ended December 31, 2017.

In 2020, we expect net production, excluding Libya, to average between 330,000 boepd and 335,000 boepd, compared with 2019 net production, excluding Libya, of 290,000 boepd.  

Net production variances related to 2019 and 2018 are summarized as follows:

United States:  Bakken net oil production was higher in 2019, primarily due to increased drilling activity and new plug and perf completion design.  Bakken net natural gas and NGL production was higher in 2019 also due to the increased drilling activity, additional natural gas captured with the start-up of the Little Missouri 4 natural gas processing plant in the third quarter of 2019 and additional NGL received under percentage of proceeds contracts resulting from lower NGL commodity pricing.  The decline in U.S. other onshore net production from 2018 reflects the sale of our interests in the Utica shale play in August 2018.  U.S. offshore net production increased in 2019, primarily due to higher production from the Conger and Penn State fields and a new well brought online at the Llano Field.

International:  In Europe, Africa and Asia, net production was comparable in 2019 with 2018.

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Sales Volumes:  The impact of higher sales volumes from our net production improved after-tax results by approximately $560 million in 2019, compared with 2018.  

Net worldwide sales volumes from Hess net production, which excludes sales volumes of crude oil, NGL and natural gas purchased from third parties, were as follows:

	2019		2018		2017
	(In thousands)
Crude oil – barrels		61,061		52,742		63,367
Natural gas liquids – barrels		17,067		14,019		15,152
Natural gas – mcf		208,665		202,041		190,089
Barrels of Oil Equivalent		112,906		100,435		110,201
Crude oil - barrels per day		167		144		173
Natural gas liquids - barrels per day		47		39		42
Natural gas - mcf per day		572		553		520
Barrels of Oil Equivalent Per Day		309		275		302

Marketing, including purchased oil and gas (Marketing expense):  Marketing expense is mainly comprised of costs to purchase crude oil, NGL and natural gas from our partners in Hess operated wells or other third parties, primarily in the U.S., and transportation and other distribution costs for U.S. marketing activities.  Marketing expense for 2019 is comparable to 2018 primarily due to lower benchmark crude oil prices on the cost of purchased volumes being largely offset by higher purchases of third-party volumes.

Cash Operating Costs:  Cash operating costs, consisting of operating costs and expenses, production and severance taxes and E&P general and administrative expenses, decreased $11 million in 2019, compared to 2018.  Cash operating costs in 2018 included pre-tax charges totaling $91 million for vacated office space and severance costs, which more than offset increased costs from higher production in 2019.  On a per-unit basis, cash operating costs improved from 2018 reflecting higher net production volumes in 2019.  See Exit Costs and Other in Items Affecting Comparability of Earnings Between Periods on page 37.  

Midstream Tariffs Expense:  Tariffs expense increased from 2018, primarily due to higher throughput volumes in 2019.  In 2020, we estimate Midstream tariffs expense to be in the range of $940 million to $965 million.  

Depreciation, Depletion and Amortization (DD&A):  DD&A costs increased by $229 million from 2018 primarily due to higher net production volumes in the Bakken and Gulf of Mexico.  

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

	Actual						Forecast range (a)
	2019		2018		2017		2020
Cash operating costs (b)	$	11.99	$	12.66	$	14.27	$11.50  — $12.50
DD&A (c)		17.43		17.14		24.53	16.50  —  17.50
Total Production Unit Costs	$	29.42	$	29.80	$	38.80	$28.00 — $30.00

(a) Forecast information excludes any contribution from Libya.

(b) Cash operating costs per boe, excluding Libya, was $12.54 in 2019 (2018: $13.32).  

(c) DD&A per boe, excluding Libya, was $18.52 in 2019 (2018: $18.29).

Exploration Expenses:  Exploration expenses, including items affecting comparability of earnings described below, were as follows:

	2019		2018		2017
	(In millions)
Exploratory dry hole costs	$	49	$	165	$	268
Exploration lease and other impairment		17		37		44
Geological and geophysical expense and exploration overhead		167		160		195
	$	233	$	362	$	507

In 2019, dry hole costs primarily related to the Jill-1 well on License 6/16 in Denmark and the Oldfield-1 well in the Gulf of Mexico.  In 2018, dry hole costs primarily related to the Aspy well, offshore Nova Scotia, Canada; the Pontoenoe-1 well, offshore Suriname and the Sorubim-1 well on the Stabroek Block, offshore Guyana.  In 2020, we estimate exploration expenses, excluding dry hole expense, to be in the range of $210 million to $220 million.

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Income Taxes:  In 2019, income tax expense was $375 million (2018: $391 million), primarily related to our operations in Libya.  Commencing in 2017, we are generally not recognizing deferred tax benefit or expense in certain countries, primarily the U.S., Denmark (hydrocarbon tax only), Malaysia and Guyana (until December 2019), while we maintain valuation allowances against net deferred tax assets in these jurisdictions in accordance with the requirements of U.S. accounting standards.  At December 31, 2019 the valuation allowance established against the net deferred tax asset in Guyana for the Stabroek Block was released as a result of the positive evidence from first production in December 2019, and the significant forecasted pre-tax income from operations.  The cumulative pre-tax losses in Guyana were driven by pre-production activities.  See E&P items affecting comparability of earnings below.

Actual effective tax rates are as follows:

	2019		2018		2017
	%		%		%
Effective income tax benefit (expense) rate		(88)		(88)		34
Adjusted effective income tax benefit (expense) rate (a)		(36)		60		7

(a) Excludes any contribution from Libya and items affecting comparability of earnings.

In 2020, we estimate income tax expense, excluding Libya and items affecting comparability of earnings between periods, to be in the range of $80 million to $90 million.

Items Affecting Comparability of Earnings Between Periods:  Reported E&P earnings include the following items affecting comparability of income (expense) before and after income taxes:

	Before Income Taxes									After Income Taxes
	2019			2018			2017			2019			2018			2017
	(In millions)
Gains (losses) on asset sales, net	$	22		$	24		$	(41	)	$	22		$	24		$	(57	)
Cost recovery settlement		(21	)		—			—			(19	)		—			—
Exit costs and other		—			(110	)		—			—			(110	)		—
Impairment		—			—			(4,203	)		—			—			(2,250	)
Dry hole, lease impairment and other exploration expenses		—			—			(280	)		—			—			(280	)
Noncash charges on de-designated crude oil collars		—			—			(22	)		—			—			(22	)
Reversal of deferred tax asset valuation allowance		—			—			—			60			—			—
	$	1		$	(86	)	$	(4,546	)	$	63		$	(86	)	$	(2,609	)

The pre-tax amounts of E&P items affecting comparability of income (expense) as presented in the Statement of Consolidated Income are as follows:

	Before Income Taxes
	2019			2018			2017
	(In millions)
Sales and other operating revenues	$	—		$	—		$	(22	)
Gains (losses) on asset sales, net		22			24			(41	)
Marketing, including purchased oil and gas		(21	)		—			—
Operating costs and expenses		—			(19	)		—
Exploration expenses, including dry holes and lease impairment		—			(3	)		(280	)
General and administrative expenses		—			(72	)		—
Depreciation, depletion and amortization		—			(16	)		—
Impairment		—			—			(4,203	)
	$	1		$	(86	)	$	(4,546	)

2019:

• Gains (losses) on asset sales, net:  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.

• Cost recovery settlement:  We recorded a pre-tax charge of $21 million ($19 million after income taxes) related to a settlement on historical cost recovery balances in the JDA that was paid in cash.

• Reversal of deferred tax asset valuation allowance:  We recorded a noncash income tax benefit of $60 million, which resulted from the reversal of a valuation allowance against net deferred tax assets in Guyana upon achieving first production from the Liza Phase 1 development.

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2018:

• Gains (losses) on asset sales, net:  We recorded a pre-tax gain of $14 million ($14 million after income taxes) associated with the sale of our joint venture interests in the Utica shale play in eastern Ohio and a pre-tax gain of $10 million ($10 million after income taxes) associated with the sale of our interests in Ghana.

• Exit costs and other: We incurred noncash pre-tax charges of $73 million ($73 million after income taxes) in connection with vacated office space.  In addition, we recorded a pre-tax severance charge of $37 million ($37 million after income taxes), related to a cost reduction program undertaken to reflect the reduced scale of our business following significant asset sales in 2017.

2017:

• Gains (losses) on asset sales, net:  We recognized a pre-tax gain of $486 million ($486 million after income taxes) related to the sale of our assets in Equatorial Guinea, and a pre-tax gain of $330 million ($314 million after income taxes) related to the sale of our enhanced oil recovery assets in the Permian Basin.  We also incurred a pre-tax loss of $857 million ($857 million after income taxes) on the sale of our interests in Norway.  The loss included the recognition of $900 million in earnings for cumulative translation adjustments previously reflected within accumulated other comprehensive income.  See Note 3, Dispositions in the Notes to Consolidated Financial Statements.

• Impairment:  We recorded a noncash impairment charge related to our interests in Norway totaling $2,503 million pre-tax ($550 million after income taxes) in the third quarter prior to the sale of our interests in the fourth quarter.  In addition, we recognized pre-tax impairment charges to reduce the carrying value of our interests in the Stampede Field by $1,095 million ($1,095 million after income taxes), and the Tubular Bells Field by $605 million ($605 million after income taxes) primarily because of a lower long-term crude oil price outlook.  The Stampede Field had significant capitalized exploration and appraisal costs that were incurred on a 100% working interest basis on the Pony discovery prior to unitizing into the Stampede project.  See Note 13, Impairment in the Notes to Consolidated Financial Statements.

• Dry hole, lease impairment and other exploration expenses:  We recorded a pre-tax charge of $280 million ($280 million after income taxes) to fully impair the carrying value of our interest at the Hess operated offshore Deepwater Tano/Cape Three Points license, offshore Ghana (Hess 50% license interest) as a result of management’s decision in the fourth quarter of 2017 to not develop the previously discovered fields.  These costs were incurred in periods prior to 2017.

• Noncash charges on de-designated crude oil collars: We recorded a pre-tax charge of $22 million ($22 million after income taxes) related to certain crude oil collars not designated as cash flow hedges.  The de-designation was a result of production downtime caused by a fire at the third-party operated Enchilada platform in the Gulf of Mexico during the fourth quarter.

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Midstream

Following is a summarized statement of income for our Midstream operations:

	2019		2018		2017
	(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues	$	848	$	713	$	617
Losses on asset sales, net		—		—		(51	)
Other, net		4		6		—
Total revenues and non-operating income		852		719		566
Costs and Expenses
Operating costs and expenses		279		193		195
General and administrative expenses		56		14		16
Depreciation, depletion and amortization		142		127		123
Interest expense		63		60		26
Total costs and expenses		540		394		360
Results of Operations Before Income Taxes		312		325		206
Provision (benefit) for income taxes (a)		—		38		31
Net income (loss)		312		287		175
Less: Net income (loss) attributable to noncontrolling interests		168		167		133
Net Income (Loss) Attributable to Hess Corporation	$	144	$	120	$	42

(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 86 for further details.

Sales and other operating revenues increased from 2018 primarily due to higher throughput volumes, increased rail transportation and water trucking revenues associated with third-party services, and higher tariff rates.

Operating costs and expenses increased from 2018, primarily due to higher maintenance activity, and increased third party rail transportation and water trucking charges.  General and administrative expenses increased in 2019, compared to 2018, as a result of expenditures incurred from Hess Midstream Partners LP’s acquisition of HIP and its corporate restructuring.  See Items Affecting Comparability of Earnings Between Periods below.  DD&A expenses increased from 2018 primarily due to additional assets places in service, including those related to the Summit acquisition.  

The increase in interest expense from 2018 reflects higher borrowings by the Midstream business.

In 2020, we estimate net income attributable to Hess Corporation from the Midstream segment to be in the range of $205 million to $215 million.  

Items Affecting Comparability of Earnings Between Periods:  In 2019, we recognized a pre-tax charge of $30 million ($16 million after income taxes and noncontrolling interests) for transaction related costs for Hess Midstream Partners LP’s acquisition of HIP and associated corporate restructuring.  See Note 6, Hess Midstream in the Notes to Consolidated Financial Statements.  In 2017, we recognized a pre-tax loss of $57 million ($34 million after income taxes and noncontrolling interests) related to the sale of our Midstream assets in the Permian Basin.

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Corporate, Interest and Other

The following table summarizes Corporate, Interest and Other expenses:

	2019			2018			2017
	(In millions)
Corporate and other expenses (excluding items affecting comparability)	$	114		$	97		$	160
Interest expense		355			359			385
Less: Capitalized interest		(38	)		(20	)		(86	)
Interest expense, net		317			339			299
Corporate, Interest and Other expenses before income taxes		431			436			459
Provision (benefit) for income taxes		—			(3	)		(26	)
Net Corporate, Interest and Other expenses after income taxes		431			433			433
Items affecting comparability of earnings between periods, after income taxes		174			20			30
Total Corporate, Interest and Other Expenses After Income Taxes	$	605		$	453		$	463

Corporate and other expenses, excluding items affecting comparability, increased from 2018 primarily due to lower interest income and a reduction in other non-operating income.  In 2020, after-tax Corporate and other expenses, excluding items affecting comparability of earnings between periods, are estimated to be in the range of $115 million to $125 million.

Interest expense for 2019 is comparable to 2018.  Capitalized interest increased from 2018 due to ongoing development activity in Guyana, including the sanction of the Liza Field Phase 2 development during 2019.  In 2020, after-tax interest expense, net is estimated to be in the range of $350 million to $360 million.  The estimated increase in 2020 is due to ceasing interest capitalization at the Liza Field, which commenced production in December 2019.

Items Affecting Comparability of Earnings Between Periods:  Corporate, Interest and Other results included the following items affecting comparability of income (expense) before and after income taxes:

2019:

• Pension settlement:  We recorded a noncash pension settlement charge of $88 million ($88 million after income taxes) associated with the purchase of a single premium annuity contract by the Hess Corporation Employees’ Pension Plan to settle and transfer certain of its obligations to a third party.  The charge is included in Other, net in the Statement of Consolidated Income.  See Note 10, Retirement Plans, in the Notes to Consolidated Financial Statements.

• Income tax:  We recorded an allocation of noncash income tax expense of $86 million that was previously a component of accumulated other comprehensive income related to our 2019 crude oil hedge contracts.

2018:

• Loss on debt extinguishment:  We recorded a pre-tax charge of $53 million ($53 million after income taxes) related to the premium paid for debt repurchases.  See Note 8, Debt, in the Notes to Consolidated Financial Statements.

• Exit costs and other: 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.

• Income tax:  We recorded an allocation of noncash income tax benefit of $91 million to offset the recognition of a noncash income tax expense recorded in other comprehensive income resulting primarily from changes in fair value of our 2019 crude oil hedge contracts.

2017:

• Exit costs and other: We recorded a pre-tax charge of $30 million ($30 million after income taxes) in connection with vacated office space, of which $11 million is included in General and administrative expenses and $19 million is included in Depreciation, depletion and amortization in the Statement of Consolidated Income.

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Liquidity and Capital Resources

The following table sets forth certain relevant measures of our liquidity and capital resources at December 31:

	2019			2018
	(In millions, except ratio)
Cash and cash equivalents (a)	$	1,545		$	2,694
Current maturities of long-term debt		—			67
Total debt (b)		7,142			6,672
Total equity		9,706			10,888
Debt to capitalization ratio (c)		43.2	%		38.0	%

(a) Includes $3 million of cash attributable to our Midstream Segment at December 31, 2019 (2018: $109 million).

(b) Includes $1,753 million of debt outstanding from our Midstream Segment at December 31, 2019 (2018: $981 million) that is non-recourse to Hess Corporation.

(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 sets forth a summary of our cash flows:

	2019			2018			2017
	(In millions)
Net cash provided by (used in):
Operating activities	$	1,642		$	1,939		$	945
Investing activities		(2,843	)		(1,566	)		1,358
Financing activities		52			(2,526	)		(188	)
Net Increase (Decrease) in Cash and Cash Equivalents	$	(1,149	)	$	(2,153	)	$	2,115

Operating Activities:  Net cash provided by operating activities was $1,642 million in 2019 (2018: $1,939 million), while net cash provided by operating activities before changes in operating assets and liabilities was $2,237 million in 2019 (2018: $2,129 million).  Net cash provided by operating activities before changes in operating assets and liabilities increased from 2018 primarily due to higher net production volumes, partially offset by lower commodity prices.  Changes in operating assets and liabilities in 2019 reduced net cash provided by operating activities by $595 million (2018: $190 million reduction), primarily from premiums paid on crude oil hedge contracts, abandonment expenditures, pension contributions and an increase in accounts receivable.  Changes in operating assets and liabilities in 2018 primarily related to premiums on crude oil hedge contracts and abandonment expenditures.

Investing Activities:  Total Additions to Property, Plant and Equipment were $2,829 million in 2019 (2018: $2,097 million).  The increase in Additions to property, plant and equipment from 2018 is primarily related to increased drilling activity in the Bakken, increased exploration and development activity on the Stabroek Block, offshore Guyana, and the Midstream operating segment’s acquisition of assets from Summit Midstream Partners LP.  In 2019, Midstream equity investments in its 50/50 joint venture with Targa Resources were $33 million (2018: $67 million).  Proceeds from asset sales were $22 million in 2019 (2018: $607 million; 2017: $3,296 million).  See Note 3, Dispositions in the Notes to Consolidated Financial Statements.

Financing Activities:  Repayments of debt were $8 million in 2019 (2018: $633 million) while borrowings with maturities in excess of 90 days of $760 million in 2019 related to our Midstream operating segment.  Common and preferred stock dividends paid were $316 million in 2019 (2018: $345 million).  We settled $25 million of common stock purchases in 2019 (2018: $1,365 million).  Net cash outflows to noncontrolling interests were $353 million in 2019 (2018: $211 million).

Future Capital Requirements and Resources

At December 31, 2019, Hess Corporation, had $1.5 billion in cash and cash equivalents, excluding Midstream, and total liquidity, including available committed credit facilities, of approximately $5.4 billion.  The Corporation has no significant near-term debt maturities.  Currently, we have WTI put options for calendar year 2020 with an average monthly floor price of $55 per barrel for 130,000 bopd, and Brent put options for calendar year 2020 with an average monthly floor price of $60 per barrel for 20,000 bopd.

Net production in 2020 is forecast to be in the range of 330,000 boepd to 335,000 boepd, excluding Libya, and we expect our 2020 E&P capital and exploratory expenditures will be approximately $3.0 billion.  In 2020, based on current forward strip crude oil prices, we expect cash flow from operating activities, cash and cash equivalents existing at December 31, 2019, and our available committed revolving credit facility will be sufficient to fund our capital investment program and dividends.

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The table below summarizes the capacity, usage, and available capacity of our borrowing and letter of credit facilities at December 31, 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 (b)	December 2024	$	1,000	$	32	$	—	$	32	$	968
Total -  Midstream		$	1,000	$	32	$	—	$	32	$	968

(a) Committed and uncommitted lines have expiration dates throughout 2020.

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

Hess Corporation:

In 2019, the Corporation entered into a new $3.5 billion revolving credit facility with a maturity date of May 15, 2023, which replaced the Corporation’s previous revolving credit facility that was scheduled to mature on January 21, 2021.  The new facility, which is fully undrawn, can be used for borrowings and letters of credit.  Borrowings on the new facility will generally bear interest at 1.30% above 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 65%, and customary events of default.  At December 31, 2019, the Corporation was in compliance with its financial covenants.

We had $272 million in letters of credit outstanding at December 31, 2019 (2018: $284 million), which primarily relate to our international operations.  See also Note 19, Financial Risk Management Activities in the Notes to Consolidated Financial Statements.

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

Midstream:

At December 31, 2019, Hess Midstream Operations LP (formerly Hess Midstream Partners LP, or HESM Opco), a consolidated subsidiary of Hess Midstream LP, had $1.4 billion of senior secured syndicated credit facilities maturing December 16, 2024, consisting of a $1.0 billion 5-year revolving credit facility and a fully drawn $400 million 5-year Term Loan A facility.  The revolving credit facility can be used for borrowings and letters of credit to fund HESM Opco’s operating activities, capital expenditures, distributions and for other general corporate purposes.  Borrowings under the 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%.  Pricing levels for the facility fee and interest-rate margins are based on HESM Opco’s ratio of total debt to EBITDA (as defined in the credit facilities).  If HESM Opco obtains an investment grade credit rating, the pricing levels will be based on HESM Opco’s credit ratings in effect from time to time.  The credit facilities contain covenants that require HESM Opco to maintain a ratio of total debt to EBITDA (as defined in the credit facilities) for the prior four fiscal quarters of not greater than 5.00 to 1.00 as of the last day of each fiscal quarter (5.50 to 1.00 during the specified period following certain acquisitions) and, prior to HESM Opco obtaining an investment grade credit rating, a ratio of secured debt to EBITDA for the prior four fiscal quarters of not greater than 4.00 to 1.00 as of the last day of each fiscal quarter.  HESM Opco was in compliance with these financial covenants at December 31, 2019.  The credit facilities are secured by first-priority perfected liens on substantially all the presently owned and after-acquired assets of HESM Opco and its direct and indirect wholly owned material domestic subsidiaries, including equity interests directly owned by such entities, subject to certain customary exclusions.  At December 31, 2019, borrowings of $32 million were drawn under HESM Opco’s revolving credit facility, and borrowings of $400 million, excluding deferred issuance costs, were drawn under HESM Opco’s Term Loan A facility.  Borrowings under these credit facilities are non-recourse to Hess Corporation.

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Credit Ratings

Two of the three major credit rating agencies that rate the Corporation’s debt have assigned an investment grade rating.  At December 31, 2019, we have investment grade credit ratings from Standard and Poor’s Ratings Services (BBB-) and Fitch Ratings (BBB-).  Moody’s Investors Service has rated our debt at Ba1.  The consequence of lower credit ratings is an increase in interest rates and facility fees on our credit facilities, and the potential for additional required collateral under operating agreements, which are not material at December 31, 2019.

At December 31, 2019, HESM Opco’s senior unsecured debt is rated BB+ by Standard and Poor’s Ratings Services and Fitch Ratings, and Ba3 by Moody’s Investors Service.

Contractual Obligations and Contingencies

The following table shows aggregate information about certain contractual obligations at December 31, 2019:

			Payments Due by Period
					2021 and		2023 and
	Total		2020		2022		2024		Thereafter
	(In millions)
Total Debt (excludes interest) (a)	$	7,220	$	—	$	30	$	702	$	6,488
Finance Leases (b)		392		36		72		72		212
Operating Leases (b)		599		200		137		129		133
Purchase Obligations:
Capital expenditures (b)		1,743		913		755		75		—
Operating expenses (b)		190		158		20		9		3
Transportation and related contracts (b)		1,009		231		424		246		108
Asset retirement obligations		2,172		127		202		45		1,798
Other liabilities		565		114		113		100		238

(a) We anticipate cash payments for interest on Total Debt of $422 million for 2020, $831 million for 2021-2022, $817 million for 2023-2024, and $3,640 million thereafter for a total of $5,710 million.  These interest payments reflect our contractual obligations at December 31, 2019.

(b) Comprises obligations, including where we, as operator, have contracted directly with suppliers.

Capital expenditures represent amounts that we were contractually committed at December 31, 2019, including the portion of our planned capital expenditure program for 2020.  Obligations for operating expenses include commitments for oil and gas production expenses, seismic purchases and other normal business expenses.  Other liabilities reflect contractually committed obligations in the Consolidated Balance Sheet at December 31, 2019, including pension plan liabilities and estimates for uncertain income tax positions.  The Corporation and certain of its subsidiaries primarily lease drilling rigs, equipment, logistical assets (offshore vessels, aircraft, and shorebases), and office space for varying periods.  See Note 7, Leases in Notes to Consolidated Financial Statements.

Off-Balance Sheet Arrangements

At December 31, 2019, we had $272 million in letters of credit.  See also Note 17, Guarantees, Contingencies and Commitments in the Notes to Consolidated Financial Statements.

Foreign Operations

We conduct E&P activities outside the U.S., principally in Guyana, the Joint Development Area of Malaysia/Thailand and Malaysia, Denmark, Libya, Suriname, and Canada.  Therefore, we are subject to the risks associated with foreign operations, including political risk, tax law changes, currency risk, corruption, and acts of terrorism.  See Item 1A. Risk Factors for further details.

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Critical Accounting Policies and Estimates

Accounting policies and estimates affect the recognition of assets and liabilities in the Consolidated Balance Sheet and revenues and expenses in the Statement of Consolidated Income.  The accounting methods used can affect net income, equity and various financial statement ratios.  However, our accounting policies generally do not change cash flows or liquidity.

Accounting for Exploration and Development Costs:  E&P activities are accounted for using the successful efforts method.  Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized.  Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred.  Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized.

The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found.  Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operational viability of the project.  If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of the project, the capitalized well costs are charged to expense.  Indicators of sufficient progress in assessing reserves, and the economic and operating viability of a project include: commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors and firm plans for additional drilling and other factors.

Crude Oil and Natural Gas Reserves:  The determination of estimated proved reserves is a significant element in arriving at the results of operations of E&P activities.  The estimates of proved reserves affect well capitalizations, the unit of production depreciation rates of proved properties and wells and equipment, as well as impairment testing of oil and gas assets.

For reserves to be booked as proved they must be determined with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations.  In addition, government and project operator approvals must be obtained and, depending on the amount of the project cost, senior management or the Board of Directors must commit to fund the project.  We maintain our own internal reserve estimates that are calculated by technical staff that work directly with the oil and gas properties.  Our technical staff update reserve estimates throughout the year based on evaluations of new wells, performance reviews, new technical data and other studies.  To provide consistency throughout the Corporation, standard reserve estimation guidelines, definitions, reporting reviews and approval practices are used.  The internal reserve estimates are subject to internal technical audits and senior management review.  We also engage an independent third-party consulting firm to audit approximately 80% of our total proved reserves each year.

Proved reserves are calculated using the average price during the twelve-month period ending December 31 determined as an unweighted arithmetic average of the price on the first day of each month within the year, unless prices are defined by contractual agreements, excluding escalations based on future conditions.  As discussed in Item 1A. Risk Factors, crude oil prices are volatile which can have an impact on our proved reserves.  If crude oil prices in 2020 are at levels below that used in determining 2019 proved reserves, we may recognize negative revisions to our December 31, 2020 proved undeveloped reserves.  In addition, we may recognize negative revisions to proved developed reserves, which can vary significantly by asset due to differing operating cost structures.  Conversely, price increases in 2020 above those used in determining 2019 proved reserves could result in positive revisions to proved developed and proved undeveloped reserves at December 31, 2020.  It is difficult to estimate the magnitude of any potential net negative or positive change in proved reserves at December 31, 2020, due to numerous currently unknown factors, including 2020 crude oil prices, any revisions based on 2020 reservoir performance, and the levels to which industry costs will change in response to movements in commodity prices.  A 10% change in proved developed and proved undeveloped reserves at December 31, 2019 would result in an approximate $200 million pre-tax change in depreciation, depletion, and amortization expense for 2020 based on projected production volumes.  See the Supplementary Oil and Gas Data on pages 90 through 98 in the accompanying financial statements for additional information on our oil and gas reserves.

Impairment of Long-lived Assets:  We review long‑lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered.  Long‑lived assets are tested based on identifiable cash flows that are largely independent of the cash flows of other assets and liabilities.  If the carrying amounts of the long-lived assets are not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is recorded.  The amount of impairment is determined based on the estimated fair value of the assets generally determined by discounting anticipated future net cash flows, an income valuation approach, or by a market‑based valuation approach, which are Level 3 fair value measurements.

In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes and discounted at a risk-adjusted rate.  The projected production volumes represent reserves, including probable reserves, expected to be produced based on a stipulated amount of capital expenditures.  The production volumes,

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prices and timing of production are consistent with internal projections and other externally reported information.  Oil and gas prices used for determining asset impairment will generally differ from those used in the standardized measure of discounted future net cash flows, since the standardized measure requires the use of historical twelve-month average prices.

Our impairment tests of long-lived E&P producing assets are based on our best estimates of future production volumes (including recovery factors), selling prices, operating and capital costs, the timing of future production and other factors, which are updated each time an impairment test is performed.  While crude oil prices in 2019 were lower than last year, we could experience an asset impairment in the future if the projected production volumes from oil and gas fields decrease, crude oil and natural gas selling prices decline significantly for an extended period or future estimated capital and operating costs increase significantly.

Midstream Joint Venture: We consolidate the activities of our interest in Hess Midstream LP, which qualifies as a variable interest entity (VIE) under U.S. generally accepted accounting principles.  We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power through Hess Corporation’s 47% consolidated ownership interest in Hess Midstream LP to direct those activities that most significantly impact the economic performance of Hess Midstream LP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to Hess Midstream LP.  This conclusion was based on a qualitative analysis that considered Hess Midstream LP’s governance structure, the commercial agreements between Hess Midstream LP and us, and the voting rights established between the members, which provide us the ability to control the operations of Hess Midstream LP.

Income Taxes:  Judgments are required in the determination and recognition of income tax assets and liabilities in the financial statements.  These judgments include the requirement to recognize the financial statement effect of a tax position only when management believes it is more likely than not, based on the technical merits, that the position will be sustained upon examination.

We have net operating loss carryforwards or credit carryforwards in multiple jurisdictions and have recorded deferred tax assets for those losses and credits.  Additionally, we have deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities.  Regular assessments are made as to the likelihood of those deferred tax assets being realized.  If, when tested under the relevant accounting standards, it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount that is expected to be realized.  

The accounting standards require the evaluation of all available positive and negative evidence giving weight based on the evidence’s relative objectivity.  In evaluating potential sources of positive evidence, we consider the reversal of taxable temporary differences, taxable income in carryback and carryforward periods, the availability of tax planning strategies, the existence of appreciated assets, estimates of future taxable income, and other factors.  Estimates of future taxable income are based on assumptions of oil and gas reserves, selling prices, and other subjective operating assumptions that are consistent with internal business forecasts.  In evaluating potential sources of negative evidence, we consider a cumulative loss in recent years, any history of operating losses or tax credit carryforwards expiring unused, losses expected in early future years, unsettled circumstances that, if unfavorably resolved, would adversely affect future operations and profit levels on a continuing basis in future years, and any carryback or carryforward period so brief that a significant deductible temporary difference expected to reverse in a single year would limit realization of tax benefits.  Due to a sustained low commodity price environment, we remained in a three-year cumulative consolidated loss position at December 31, 2019.  A three-year cumulative consolidated loss constitutes objective negative evidence to which the accounting standards require we assign significant weight relative to subjective evidence such as our estimates of future taxable income.  We are generally not recognizing deferred tax benefit or expense in certain countries, primarily the U.S., Denmark (hydrocarbon tax only) and Malaysia while we maintain valuation allowances against net deferred tax assets in these jurisdictions.  In December 2019, we reversed the valuation allowance of $60 million for Guyana upon achieving first production from the Liza Phase 1 development.

At December 31, 2019, the Consolidated Balance Sheet reflects a $4,734 million valuation allowance against the net deferred tax assets for multiple jurisdictions based on the evaluation of the accounting standards described above.  The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income change or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as expected future growth.  

Asset Retirement Obligations:  We have material legal obligations to remove and dismantle long‑lived assets and to restore land or seabed at certain E&P locations.  In accordance with generally accepted accounting principles, we recognize a liability for the fair value of required asset retirement obligations.  In addition, the fair value of any legally required conditional asset retirement obligation is recorded if the liability can be reasonably estimated.  We capitalize such costs as a component of the carrying amount of the underlying assets in the period in which the liability is incurred.  In subsequent periods, the liability is accreted, and the asset is depreciated over the useful life of the related asset.  We estimate the fair value of these obligations by discounting projected future payments that will be required to satisfy the obligations.  In determining these estimates, we are

44

required to make several assumptions and judgments related to the scope of dismantlement, timing of settlement, interpretation of legal requirements, inflationary factors and discount rate.  In addition, there are other external factors, which could significantly affect the ultimate settlement costs or timing for these obligations including changes in environmental regulations and other statutory requirements, fluctuations in industry costs and foreign currency exchange rates and advances in technology.  As a result, our estimates of asset retirement obligations are subject to revision due to the factors described above.  Changes in estimates prior to settlement result in adjustments to both the liability and related asset values, unless the field has ceased production, in which case changes are recognized in our Consolidated Statement of Income.  See Note 9, Asset Retirement Obligations.

Retirement Plans:  We have funded non-contributory defined benefit pension plans, an unfunded supplemental pension plan and an unfunded postretirement medical plan.  We recognize the net change in the funded status of the projected benefit obligation for these plans in the Consolidated Balance Sheet.  The determination of the obligations and expenses related to these plans are based on several actuarial assumptions.  These assumptions represent estimates made by us, some of which can be affected by external factors.  The most significant assumptions relate to:

Discount rate used for measuring the present value of future plan obligations:  The discount rate used to estimate our projected benefit obligations is based on a portfolio of high‑quality, fixed income debt instruments with maturities that approximate the expected payment of plan obligations.  At December 31, 2019, a 0.25% decrease in the discount rate assumption would increase projected benefit obligations by approximately $120 million and forecasted 2020 annual benefit expense by approximately $10 million.  The increase in the projected benefit obligations would decrease the funded status of our pension plans, but any decrease in the funded status would be partially mitigated by increases in the fair value of fixed income investments in the asset portfolios.

Expected long-term rates of returns on plan assets:  The expected return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of pension assets to that asset category.  The future expected return assumptions for individual asset categories are largely based on inputs from various investment experts regarding their future return expectations for particular asset categories.  At December 31, 2019, a 0.25% decrease in the expected long-term rates of return on plan assets assumption would increase forecasted 2020 annual benefit expense by approximately $5 million.

Other assumptions include the rate of future increases in compensation levels and participant mortality level.

Derivatives:  We utilize derivative instruments, including futures, forwards, options and swaps, individually or in combination to mitigate our exposure to fluctuations in the prices of crude oil and natural gas, as well as changes in interest and foreign currency exchange rates.  All derivative instruments are recorded at fair value in our Consolidated Balance Sheet.  Our policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative.  The changes in fair value of derivatives that are not designated as hedges are recognized currently in earnings.  Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges), or hedges of changes in fair value of recognized assets and liabilities or of unrecognized firm commitments (fair value hedges).  Changes in fair value of derivatives that are designated as cash flow hedges are recorded as a component of other comprehensive income (loss).  Amounts included in Accumulated other comprehensive income (loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings.  Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings.  The change in fair value of the related hedged commitment is recorded as an adjustment to its carrying amount and recognized currently in earnings.

Fair Value Measurements:  We use various valuation approaches in determining fair value for financial instruments, including the market and income approaches.  Our fair value measurements also include non-performance risk and time value of money considerations.  Counterparty credit is considered for receivable balances, and our credit is considered for accrued liabilities.

We also record certain nonfinancial assets and liabilities at fair value when required by generally accepted accounting principles.  These fair value measurements are recorded in connection with business combinations, qualifying non-monetary exchanges, the initial recognition of asset retirement obligations and any impairment of long-lived assets, equity method investments or goodwill.

We determine fair value in accordance with the fair value measurements accounting standard which established a hierarchy for the inputs used to measure fair value based on the source of the inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3), including discounted cash flows and other unobservable data.  Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2.  When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market.  Multiple inputs

45

may be used to measure fair value; however, the level of fair value assigned for each physical derivative and financial asset or liability is based on the lowest significant input level within this fair value hierarchy.  

Environment, Health and Safety

Our long-term vision and values provide a foundation for how we do business and define our commitment to meeting high standards of corporate citizenship and creating a long lasting positive impact on the communities where we do business.  Our strategy is reflected in our environment, health, safety and social responsibility (EHS & SR) policies and by a management system framework that helps protect our workforce, customers and local communities.  Our management systems are intended to promote internal consistency, adherence to policy objectives and continual improvement in EHS & SR performance.  Improved performance may, in the short‑term, increase our operating costs and could also require increased capital expenditures to reduce potential risks to our assets, reputation and license to operate.  In addition to enhanced EHS & SR performance, improved productivity and operational efficiencies may be realized from investments in EHS & SR.  We have programs in place to evaluate regulatory compliance, audit facilities, train employees, prevent and manage risks and emergencies and to generally meet corporate EHS & SR goals and objectives.

We recognize that climate change is a global environmental concern.  We assess, monitor and take measures to reduce our carbon footprint at existing and planned operations.  We are committed to complying with all Greenhouse Gas (GHG) emissions regulations and the responsible management of GHG emissions at our facilities.

We will have continuing expenditures for environmental assessment and remediation.  Sites where corrective action may be necessary include E&P facilities, sites from discontinued operations where we retained liability and, although not currently significant, “Superfund” sites where we have been named a potentially responsible party.

We accrue for environmental assessment and remediation expenses when the future costs are probable and reasonably estimable.  At December 31, 2019, our reserve for estimated remediation liabilities was approximately $70 million.  We expect that existing reserves for environmental liabilities will adequately cover costs to assess and remediate known sites.  Our remediation spending was approximately $20 million in 2019 (2018: $15 million; 2017: $15 million).  The amount of other expenditures incurred to comply with federal, state, local and foreign country environmental regulations is difficult to quantify as such costs are captured as mostly indistinguishable components of our capital expenditures and operating expenses.

46

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

In the normal course of our business, we are exposed to commodity risks related to changes in the prices of crude oil, NGL, and natural gas as well as changes in interest rates and foreign currency values.  In the disclosures that follow, financial risk management activities refer to the mitigation of these risks through hedging activities.

Controls:  We maintain a control environment under the direction of our Chief Risk Officer.  Controls over instruments used in financial risk management activities include volumetric and term limits.  Our Treasury department is responsible for administering and monitoring foreign exchange rate and interest rate hedging programs using similar controls and processes, where applicable.  Hedging strategies are reviewed annually by the Audit Committee of the Board of Directors.

Instruments:  We primarily use forward commodity contracts, foreign exchange forward contracts, futures, swaps, and options in our risk management activities.  These contracts are generally widely traded instruments with standardized terms.  The following describes these instruments and how we use them:

• Swaps:  We use financially settled swap contracts with third parties as part of our financial risk management activities.  Cash flows from swap contracts are determined based on underlying commodity prices or interest rates and are typically settled over the life of the contract.

• Forward Foreign Exchange Contracts:  We enter into forward contracts, primarily for the British Pound and Danish Krone, which commit us to buy or sell a fixed amount of those currencies at a predetermined exchange rate on a future date.

• Exchange-traded Contracts:  We may use exchange-traded contracts, including futures, on a number of different underlying energy commodities.  These contracts are settled daily with the relevant exchange and may be subject to exchange position limits.

• Options:  Options on various underlying energy commodities include exchange-traded and third-party contracts and have various exercise periods.  As a seller of options, we receive a premium at the outset and bear the risk of unfavorable changes in the price of the commodity underlying the option.  As a purchaser of options, we pay a premium at the outset and have the right to participate in the favorable price movements in the underlying commodities.

Financial Risk Management Activities

At December 31, 2019, outstanding total debt, which was substantially comprised of fixed rate debt instruments, had a carrying value of $7,142 million and a fair value of $8,242 million.  A 15% increase or decrease in interest rates would decrease or increase the fair value of our fixed rate debt by approximately $450 million or $490 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.  

We have WTI put options for calendar year 2020 with an average monthly floor price of $55 per barrel for 130,000 bopd, and Brent put options for calendar year 2020 with an average monthly floor price of $60 per barrel for 20,000 bopd.  As of December 31, 2019, an assumed 10% increase in the forward WTI and Brent crude oil prices used in determining the fair value of our put options would reduce the fair value of these derivatives instruments by approximately $60 million, while an assumed 10% decrease in the same crude oil prices would increase the fair value of these derivative instruments by approximately $110 million. 

We have outstanding foreign exchange contracts with a total notional amount of $90 million at December 31, 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 of the U.S. Dollar exchange rate is estimated to be a loss of approximately $5 million at December 31, 2019.

See Note 19, Financial Risk Management Activities in the Notes to Consolidated Financial Statements for further details.

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Item 8.  Financial Statements and Supplementary Data

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS

	Page Number
Management’s Report on Internal Control over Financial Reporting		49
Reports of Independent Registered Public Accounting Firm		50
Consolidated Balance Sheet at December 31, 2019, and 2018		54
Statement of Consolidated Income for each of the Three Years in the Period Ended December 31, 2019		55
Statement of Consolidated Comprehensive Income for each of the Three Years in the Period Ended December 31, 2019		56
Statement of Consolidated Cash Flows for each of the Three Years in the Period Ended December 31, 2019		57
Statement of Consolidated Equity for each of the Three Years in the Period Ended December 31, 2019		58
Notes to Consolidated Financial Statements		59
Note 1 - Nature of Operations, Basis of Presentation and Summary of Accounting Policies		59
Note 2 - Revenue		65
Note 3 - Dispositions		65
Note 4 - Inventories		66
Note 5 - Property, Plant and Equipment		66
Note 6 - Hess Midstream		68
Note 7 - Leases		69
Note 8 - Debt		71
Note 9 - Asset Retirement Obligations		73
Note 10 - Retirement Plans		74
Note 11 - Share-based Compensation		78
Note 12 - Exit and Disposal Costs		79
Note 13 - Impairment		79
Note 14 - Income Taxes		80
Note 15 - Outstanding and Weighted Average Common Shares		82
Note 16 - Supplementary Cash Flow Information		84
Note 17 - Guarantees, Contingencies and Commitments		84
Note 18 - Segment Information		86
Note 19 - Financial Risk Management Activities		87
Note 20 - Subsequent Event		89
Supplementary Oil and Gas Data		90
Quarterly Financial Data		99

   Schedules have been omitted because of the absence of the conditions under which they are required or because the required information is presented in the financial statements or the notes thereto.

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Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a‑15(f).  Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes‑Oxley Act, based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework).  Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2019.

The Corporation’s independent registered public accounting firm, Ernst & Young LLP, has audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2019, as stated in their report, which is included herein.

By	/s/ John P. Rielly	By	/s/ John B. Hess
	John P. Rielly Senior Vice President and Chief Financial Officer		John B. Hess Chief Executive Officer

February 20, 2020

49

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Hess Corporation

Opinion on Internal Control over Financial Reporting

We have audited Hess Corporation and consolidated subsidiaries’ (the “Corporation”) internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria).  In our opinion, Hess Corporation and consolidated subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Corporation as of December 31, 2019 and 2018, the related statements of consolidated income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2019, and the related notes and our report dated February 20, 2020 expressed an unqualified opinion thereon.

Basis for Opinion

The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting.  Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit.  We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB.  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

New York, New York

February 20, 2020

50

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Hess Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Hess Corporation and consolidated subsidiaries (the “Corporation”) as of December 31, 2019 and 2018, the related statements of consolidated income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”).  In our opinion, the financial statements present fairly, in all material respects, the consolidated financial position of the Corporation at December 31, 2019 and 2018, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Corporation’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 20, 2020 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Corporation’s management.  Our responsibility is to express an opinion on the Corporation’s financial statements based on our audits.  We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission (SEC) and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB.  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud.  Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks.  Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements.  Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements.  We believe that our audits provide a reasonable basis for our opinion.  

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments.  The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Depreciation, depletion and amortization of proved oil and natural gas properties

51

Description of the Matter

The net book value of the Corporation’s exploration and production assets was $13,792 million at December 31, 2019, and depreciation, depletion and amortization (DD&A) expense was $1,977 million for the year then ended.  As described in Note 1 to the financial statements, the Corporation follows the successful efforts method of accounting for its oil and gas exploration and production activities.  Under the successful efforts method of accounting, DD&A expense is recorded using the units-of-production method, based on proved oil and gas reserves, as estimated by petroleum engineering specialists, for property acquisition costs and proved developed oil and gas reserves, also estimated by petroleum engineering specialists, for oil and gas production facilities and wells.  Proved oil and gas reserves are based on geological and engineering evaluations of estimated in-place hydrocarbon volumes using financial and non-financial inputs.  Significant judgment is required by the Corporations’ internal engineering staff in evaluating the geological and engineering data used to estimate reserves.  Estimating proved reserves also requires the selection of inputs, including oil and natural gas price assumptions, future operating and capital costs assumptions and tax rates by jurisdiction, among others.  Management used independent petroleum engineering specialists to audit approximately 80 percent of the Corporation’s proved reserves at December 31, 2019 as prepared by the Corporation’s internal engineering staff. Auditing the Corporation’s DD&A expense calculation is complex because of our need to assess the reasonableness of management’s determination of the inputs described above used in estimating proved oil and gas reserves and to use the work of the internal engineering staff and independent petroleum engineering specialists.

How We Addressed the Matter in Our Audit

We obtained an understanding, evaluated the design and tested the operating effectiveness of internal controls that address the risks of material misstatement relating to the DD&A expense calculation.  This included controls over the completeness and accuracy of the financial data used in estimating proved oil and gas reserves. Our testing of the Corporation’s DD&A expense calculation included, among other procedures, evaluating the professional qualifications and objectivity of the Corporation’s internal petroleum engineering specialist responsible for overseeing the preparation of the Corporation’s reserve estimates and of the independent petroleum engineering specialist used to audit the estimates.  In addition, we tested the completeness and accuracy of the financial data used in the estimation of proved oil and gas reserves by agreeing significant inputs to source documentation, where available, on a sample basis and assessing the inputs for reasonableness based on review of corroborative evidence and consideration of any contrary evidence. For proved undeveloped reserves, we evaluated management’s development plans for compliance with the SEC rule that undrilled locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time, by assessing consistency of the development projection with the Corporation’s drill plan and the availability of capital relative to the drill plan.  Additionally, we performed analytic and lookback procedures on inputs into the oil and gas reserve estimate as well as on the outputs.  Finally, we tested the mathematical accuracy of the DD&A expense calculations, including comparing the proved oil and gas reserves to the Corporation’s reserve report.

Assessment of realizability of deferred tax assets

Description of the Matter

At December 31, 2019, the Corporation had $1,028 million of total deferred tax assets, net of valuation allowances, related to deductible temporary differences and net operating loss carryforwards in multiple jurisdictions.  As described in Note 1 to the financial statements, the Corporation records a valuation allowance against its deferred tax assets if, based on the weight of all available evidence, in management’s judgment it is more likely than not that some portion, or all, of the deferred tax assets will not be realized.  Valuation allowances on deferred tax assets totaled $4,734 million as of December 31, 2019. Auditing management’s assessment of the realizability of deferred tax assets was subjective because management’s estimate was judgmental and involved assessing the weight of positive and negative evidence, often based on significant assumptions that may be affected by future market or economic conditions.  This included, among other things, evaluation of the history of operating income or losses, the reversal of existing taxable temporary differences and forecasts of future taxable income (exclusive of reversing temporary differences and carryforwards).

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How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Corporation’s controls that address the risks of material misstatement relating to the realizability of deferred tax assets, including, where applicable, controls over projections of future taxable income. We also tested management’s controls over the completeness and accuracy of the data used in the estimates.
Our audit procedures included, among others, evaluating management’s weighting of positive and negative evidence in determining whether a valuation allowance was required as well as testing the material assumptions used by the Corporation to develop estimates of future taxable income, where applicable, by jurisdiction.  We tested the underlying data used in the Corporation’s projections, by comparing key inputs used to develop future taxable income with historical information as well as evaluating management’s consideration of current industry conditions and economic trends incorporated in such projections.  

/s/ Ernst & Young LLP

We have served as the Corporation’s auditor since 1971

New York, New York

February 20, 2020

53

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

	December 31,
	2019			2018
	(In millions,
	except share amounts)
Assets
Current Assets:
Cash and cash equivalents	$	1,545		$	2,694
Accounts receivable:
From contracts with customers		940			771
Joint venture and other		230			230
Inventories		261			245
Other current assets		180			519
Total current assets		3,156			4,459
Property, plant and equipment:
Total — at cost		35,820			33,222
Less: Reserves for depreciation, depletion, amortization and lease impairment		19,006			17,139
Property, plant and equipment — net		16,814			16,083
Operating lease right-of-use assets — net		447			—
Finance lease right-of-use assets — net		299			—
Goodwill		360			360
Deferred income taxes		80			21
Other assets		626			510
Total Assets	$	21,782		$	21,433
Liabilities
Current Liabilities:
Accounts payable	$	411		$	495
Accrued liabilities		1,803			1,560
Taxes payable		97			81
Current maturities of long-term debt		—			67
Current portion of operating and finance lease obligations		199			—
Total current liabilities		2,510			2,203
Long-term debt		7,142			6,605
Long-term operating lease obligations		353			—
Long-term finance lease obligations		238			—
Deferred income taxes		415			421
Asset retirement obligations		897			741
Other liabilities and deferred credits		521			575
Total Liabilities		12,076			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 —  zero shares (2018: 574,997)		—			1
Common stock, par value $1.00; Authorized — 600,000,000 shares:
Issued — 304,955,472 shares (2018: 291,434,534)		305			291
Capital in excess of par value		5,591			5,386
Retained earnings		3,535			4,257
Accumulated other comprehensive income (loss)		(699	)		(306	)
Total Hess Corporation stockholders’ equity		8,732			9,629
Noncontrolling interests		974			1,259
Total equity		9,706			10,888
Total Liabilities and Equity	$	21,782		$	21,433

The consolidated financial statements reflect the successful efforts method of accounting for oil and gas exploration and production activities.

See accompanying Notes to Consolidated Financial Statements.

54

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED INCOME

	Years Ended December 31,
	2019			2018			2017
	(In millions, except per share amounts)
Revenues and Non-Operating Income
Sales and other operating revenues	$	6,495		$	6,323		$	5,466
Gains (losses) on asset sales, net		22			32			(86	)
Other, net		(7	)		111			11
Total revenues and non-operating income		6,510			6,466			5,391
Costs and Expenses
Marketing, including purchased oil and gas		1,736			1,771			1,267
Operating costs and expenses		1,237			1,134			1,443
Production and severance taxes		184			171			119
Exploration expenses, including dry holes and lease impairment		233			362			507
General and administrative expenses		397			473			422
Interest expense		380			399			325
Loss on debt extinguishment		—			53			—
Depreciation, depletion and amortization		2,122			1,883			2,883
Impairment		—			—			4,203
Total costs and expenses		6,289			6,246			11,169
Income (Loss) Before Income Taxes		221			220			(5,778	)
Provision (benefit) for income taxes		461			335			(1,837	)
Net Income (Loss)		(240	)		(115	)		(3,941	)
Less: Net income (loss) attributable to noncontrolling interests		168			167			133
Net Income (Loss) Attributable to Hess Corporation		(408	)		(282	)		(4,074	)
Less: Preferred stock dividends		4			46			46
Net Income (Loss) Attributable to Hess Corporation Common Stockholders	$	(412	)	$	(328	)	$	(4,120	)
Net Income (Loss) Attributable to Hess Corporation Per Common Share
Basic	$	(1.37	)	$	(1.10	)	$	(13.12	)
Diluted	$	(1.37	)	$	(1.10	)	$	(13.12	)
Weighted Average Number of Common Shares Outstanding (Diluted)		301.2			298.2			314.1
Common Stock Dividends Per Share	$	1.00		$	1.00		$	1.00

See accompanying Notes to Consolidated Financial Statements.

55

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME

	Years Ended December 31,
	2019			2018			2017
	(In millions)
Net Income (Loss)	$	(240	)	$	(115	)	$	(3,941	)
Other Comprehensive Income (Loss):
Derivatives designated as cash flow hedges
Effect of hedge (gains) losses reclassified to income		(1	)		173			18
Income taxes on effect of hedge (gains) losses reclassified to income		—			—			—
Net effect of hedge (gains) losses reclassified to income		(1	)		173			18
Change in fair value of cash flow hedges		(462	)		330			(156	)
Income taxes on change in fair value of cash flow hedges		86			(86	)		—
Net change in fair value of cash flow hedges		(376	)		244			(156	)
Change in derivatives designated as cash flow hedges, after taxes		(377	)		417			(138	)
Pension and other postretirement plans
(Increase) reduction in unrecognized actuarial losses		(160	)		29			35
Income taxes on actuarial changes in plan liabilities		—			(6	)		—
(Increase) reduction in unrecognized actuarial losses, net		(160	)		23			35
Amortization of net actuarial losses		144			41			77
Income taxes on amortization of net actuarial losses		—			—			—
Net effect of amortization of net actuarial losses		144			41			77
Change in pension and other postretirement plans, after taxes		(16	)		64			112
Foreign currency translation adjustment
Foreign currency translation adjustment		—			—			144
Asset disposition		—			—			900
Change in foreign currency translation adjustment		—			—			1,044
Other Comprehensive Income (Loss)		(393	)		481			1,018
Comprehensive Income (Loss)		(633	)		366			(2,923	)
Less: Comprehensive income (loss) attributable to noncontrolling interests		168			167			133
Comprehensive Income (Loss) Attributable to Hess Corporation	$	(801	)	$	199		$	(3,056	)

See accompanying Notes to Consolidated Financial Statements.

56

HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

	Years Ended December 31,
	2019			2018			2017
	(In millions)
Cash Flows From Operating Activities
Net income (loss)	$	(240	)	$	(115	)	$	(3,941	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
(Gains) losses on asset sales, net		(22	)		(32	)		86
Depreciation, depletion and amortization		2,122			1,883			2,883
Impairment		—			—			4,203
Exploratory dry hole costs		49			165			268
Exploration lease and other impairment		17			37			44
Pension settlement loss		93			4			19
Stock compensation expense		85			72			86
Noncash (gains) losses on commodity derivatives, net		116			182			97
Provision (benefit) for deferred income taxes and other tax accruals		17			(120	)		(2,001	)
Loss on debt extinguishment		—			53			—
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(383	)		(138	)		(340	)
(Increase) decrease in inventories		(16	)		(12	)		(64	)
Increase (decrease) in accounts payable and accrued liabilities		4			88			(44	)
Increase (decrease) in taxes payable		16			(2	)		(34	)
Changes in other operating assets and liabilities		(216	)		(126	)		(317	)
Net cash provided by (used in) operating activities		1,642			1,939			945
Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P		(2,433	)		(1,854	)		(1,788	)
Additions to property, plant and equipment - Midstream		(396	)		(243	)		(149	)
Payments for Midstream equity investments		(33	)		(67	)		—
Proceeds from asset sales, net of cash sold		22			607			3,296
Other, net		(3	)		(9	)		(1	)
Net cash provided by (used in) investing activities		(2,843	)		(1,566	)		1,358
Cash Flows From Financing Activities
Net borrowings (repayments) of debt with maturities of 90 days or less		32			—			(153	)
Debt with maturities of greater than 90 days:
Borrowings		760			—			800
Repayments		(8	)		(633	)		(459	)
Payments on finance lease obligations		(49	)		—			—
Proceeds from issuance of Hess Midstream Partnership LP units		—			—			366
Common stock acquired and retired		(25	)		(1,365	)		(110	)
Cash dividends paid		(316	)		(345	)		(363	)
Noncontrolling interests, net		(353	)		(211	)		(243	)
Other, net		11			28			(26	)
Net cash provided by (used in) financing activities		52			(2,526	)		(188	)
Net Increase (Decrease) in Cash and Cash Equivalents		(1,149	)		(2,153	)		2,115
Cash and Cash Equivalents at Beginning of Year		2,694			4,847			2,732
Cash and Cash Equivalents at End of Year	$	1,545		$	2,694		$	4,847

See accompanying Notes to Consolidated Financial Statements.

57

 HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES

STATEMENT OF CONSOLIDATED EQUITY

	Mandatory Convertible Preferred Stock			Common Stock			Capital in Excess of Par			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Hess Stockholders' Equity			Noncontrolling Interests			Total Equity
	(In millions)
Balance at December 31, 2016	$	1		$	317		$	5,773		$	10,147		$	(1,704	)	$	14,534		$	1,057		$	15,591
Cumulative effect of adoption of new accounting standards		—			—			2			(39	)		—			(37	)		—			(37	)
Net income (loss)		—			—			—			(4,074	)		—			(4,074	)		133			(3,941	)
Other comprehensive income (loss)		—			—			—			—			1,018			1,018			—			1,018
Share-based compensation		—			1			92			—			—			93			—			93
Dividends on preferred stock		—			—			—			(46	)		—			(46	)		—			(46	)
Dividends on common stock		—			—			—			(317	)		—			(317	)		—			(317	)
Common stock acquired and retired		—			(3	)		(43	)		(74	)		—			(120	)		—			(120	)
Hess Midstream Partners LP units issuance		—			—			—			—			—			—			356			356
Noncontrolling interests, net		—			—			—			—			—			—			(243	)		(243	)
Balance at December 31, 2017	$	1		$	315		$	5,824		$	5,597		$	(686	)	$	11,051		$	1,303		$	12,354
Cumulative effect of adoption of new accounting standards		—			—			—			101			(101	)		—			—			—
Net income (loss)		—			—			—			(282	)		—			(282	)		167			(115	)
Other comprehensive income (loss)		—			—			—			—			481			481			—			481
Share-based compensation		—			1			103			—			—			104			—			104
Dividends on preferred stock		—			—			—			(46	)		—			(46	)		—			(46	)
Dividends on common stock		—			—			—			(299	)		—			(299	)		—			(299	)
Common stock acquired and retired		—			(25	)		(541	)		(814	)		—			(1,380	)		—			(1,380	)
Noncontrolling interests, net		—			—			—			—			—			—			(211	)		(211	)
Balance at December 31, 2018	$	1		$	291		$	5,386		$	4,257		$	(306	)	$	9,629		$	1,259		$	10,888
Net income (loss)		—			—			—			(408	)		—			(408	)		168			(240	)
Other comprehensive income (loss)		—			—			—			—			(393	)		(393	)		—			(393	)
Preferred stock conversion		(1	)		12			(11	)		—			—			—			—			—
Share-based compensation		—			2			123			—			—			125			—			125
Dividends on preferred stock		—			—			—			(4	)		—			(4	)		—			(4	)
Dividends on common stock		—			—			—			(310	)		—			(310	)		—			(310	)
Conversion of Midstream structure		—			—			15			—			—			15			(22	)		(7	)
Sale of water business to Hess Infrastructure Partners		—			—			78			—			—			78			(78	)		—
Noncontrolling interests, net		—			—			—			—			—			—			(353	)		(353	)
Balance at December 31, 2019	$	—		$	305		$	5,591		$	3,535		$	(699	)	$	8,732		$	974		$	9,706

See accompanying Notes to Consolidated Financial Statements.

58

1.  Nature of Operations, Basis of Presentation and Summary of Accounting Policies

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

Nature of Business:  Hess Corporation, incorporated in the State of Delaware in 1920, is a global Exploration and Production (E&P) company engaged in exploration, development, production, transportation, purchase and sale of crude oil, NGL, and natural gas with production operations and development activities located primarily in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA), Malaysia and Denmark.  We conduct exploration activities primarily offshore Guyana, the U.S. Gulf of Mexico, and offshore Suriname and Canada.

Our Midstream operating segment, which is comprised of Hess Corporation’s 47% consolidated ownership interest in Hess Midstream LP at December 31, 2019 (see Note 6, Hess Midstream) provides fee-based services, including gathering, compressing and processing natural gas and fractionating NGL; gathering, terminaling, loading and transporting crude oil and NGL; storing and terminaling propane, and water handling services primarily in the Bakken shale play in the Williston Basin area of North Dakota.

Basis of Presentation and Principles of Consolidation: The consolidated financial statements include the accounts of Hess Corporation and entities in which we own more than a 50% voting interest.  Commencing December 16, 2019, we consolidate Hess Midstream LP, a variable interest entity that acquired Hess Infrastructure Partners LP (HIP), based on our conclusion that we have the power through Hess Corporation’s 47% consolidated ownership interest in Hess Midstream LP to direct those activities that most significantly impact the economic performance of Hess Midstream LP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to Hess Midstream LP.  Prior to December 16, 2019, we consolidated HIP, also a variable interest entity based on the conclusion we had the power to direct the activities that most significantly impact the economic performance of HIP.  Our undivided interests in unincorporated oil and gas E&P ventures are proportionately consolidated.  Investments in affiliated companies, 20% to 50% owned and where we have the ability to influence the operating or financial decisions of the affiliate, are accounted for using the equity method.  

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