HESS CORP - Annual Report: 2019 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

For the fiscal year ended December 31, 2019

or

For the transition period from                 to                

Commission File Number 1-1204

Hess Corporation

(Exact name of Registrant as specified in its charter)

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

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

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:

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

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:

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:

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:

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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:

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Gross and Net Undeveloped Acreage

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

Gross and Net Developed Acreage, and Productive Wells

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

Exploratory and Development Wells

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

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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:

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:

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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:

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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:

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:

Equity Compensation Plans

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

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: