hes-20231231

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, 2023


☐			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

☐

Smaller reporting company

☐

Emerging Growth Company

☐

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. Yes ☑ No ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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 $37,598,000,000, computed using the outstanding Common Stock and closing market price on June 30, 2023, the last business day of the Registrant’s most recently completed second fiscal quarter.

At January 31, 2024, there were 307,152,064 shares of Common Stock outstanding.

Part III is incorporated by reference from the Proxy Statement for the 2024 annual meeting of stockholders.

HESS CORPORATION

Form 10-K

TABLE OF CONTENTS


Item No.		Page
	PART I
1 and 2.	Business and Properties	7
	Information about our Executive Officers	18
1A.	Risk Factors	20
1B.	Unresolved Staff Comments	26
1C.	Cybersecurity	26
3.	Legal Proceedings	27
4.	Mine Safety Disclosures	27
	PART II
5.	Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities	28
6.	[Reserved]	29
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
7A.	Quantitative and Qualitative Disclosures About Market Risk	50
8.	Financial Statements and Supplementary Data	51
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	102
9A.	Controls and Procedures	102
9B.	Other Information	102
9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	102
	PART III
10.	Directors, Executive Officers and Corporate Governance	102
11.	Executive Compensation	102
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	102
13.	Certain Relationships and Related Transactions, and Director Independence	102
14.	Principal Accounting Fees and Services	102
	PART IV
15.	Exhibits, Financial Statement Schedules	103
	Signatures	106

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.

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; information about sustainability goals and targets and planned social, safety and environmental policies, programs and initiatives; future economic and market conditions in the oil and gas industry; and expected benefits, timing and completion of the proposed merger with Chevron Corporation (Chevron).

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;

•reduced demand for our products, including due to perceptions regarding the oil and gas industry, competing or alternative energy products and political conditions and events;

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

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

•operational changes and expenditures due to climate change and sustainability related initiatives;

•disruption or interruption of our operations due to catastrophic and other events, such as accidents, severe weather, geological events, shortages of skilled labor, cyber-attacks, public health measures, or climate change;

•the ability of our contractual counterparties to satisfy their obligations to us, including the operation of joint ventures under which we may not control and exposure to decommissioning liabilities for divested assets in the event the current or future owners are unable to perform;

•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 limitations on investment in oil and gas activities, rising interest rates or negative outcomes within commodity and financial markets;

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

•risks and uncertainties associated with the proposed Merger (as defined herein) with Chevron, including the following:

•the risk that regulatory approvals are not obtained or are obtained subject to conditions that are not anticipated by Chevron and Hess;

•potential delays in consummating the potential transaction, including as a result of regulatory approvals and the request for additional information and documentary material from the Federal Trade Commission;

•Chevron’s ability to integrate Hess’ operations in a successful manner and in the expected time period;

•the possibility that any of the anticipated benefits and projected synergies of the potential transaction will not be realized or will not be realized within the expected time period;

•the occurrence of any event, change or other circumstance that could give rise to the termination of the Merger Agreement (as defined herein);

•risks that the anticipated tax treatment of the potential transaction is not obtained, or other unforeseen or unknown liabilities;

•customer, shareholder, regulatory and other stakeholder approvals and support, or unexpected future capital expenditures;

•potential litigation relating to the potential transaction that could be instituted against Chevron and Hess or their respective directors, and the possibility that the transaction may be more expensive to complete than anticipated, including as a result of unexpected factors or events;

•the effect of the announcement, pendency or completion of the potential transaction on the parties’ business relationships and business generally, and the risks that the potential transaction disrupts current plans and operations of Chevron or Hess and potential difficulties in Hess employee retention as a result of the transaction, as well as the risk of disruption of Chevron’s or Hess’ management and business disruption during the pendency of, or following, the potential transaction;

•the receipt of required Chevron board of directors’ authorizations to implement capital allocation strategies, including future dividend payments, and uncertainties as to whether the potential transaction will be consummated on the anticipated timing or at all, or if consummated, will achieve its anticipated economic benefits, including as a result of risks associated with third party contracts containing material consent, anti-assignment, transfer, other provisions that may be related to the potential transaction which are not waived or otherwise satisfactorily resolved, or changes in commodity prices;

•negative effects of the announcement of the transaction, and the pendency or completion of the proposed acquisition on the market price of Chevron’s or Hess’ common stock and/or operating results;

•rating agency actions and Chevron’s and Hess’ ability to access short and long-term debt markets on a timely and affordable basis; 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.

Glossary

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

API – American Petroleum Institute.

ART Registry – Architecture for REDD+ Transactions Registry.

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.

CGA – Clean Gulf Associates.

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.

DD&A – Depreciation, depletion and amortization.

DEI – Diversity, Equity and Inclusion.

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.

EPA – Environmental Protection Agency.

EHS & SR – Environment, health, safety and social responsibility.

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.

E&P – Exploration and production.

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.

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.

GAAP – Generally accepted accounting principles in the United States.

GHG – Greenhouse gas.

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.

ICE – Integrity critical equipment.

IEA – International Energy Agency.

JOA – Joint operating agreement.

LTIP – Long Term Incentive Plans.

Mcf – One thousand cubic feet of natural gas.

Mmcfd – One thousand mcf of natural gas per day.

MSRC – Marine Spill Response Corporation.

MTBE – Methyl tertiary butyl ether.

MWCC – Marine Well Containment Company.

Net acreage or Net wells – The sum of the fractional working interests owned by the Corporation 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.

NIST CSF – National Institute of Standards and Technology Cybersecurity Framework.

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.

OSHA – Occupational Safety and Health Administration.

OSRL – Oil Spill Response Limited.

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

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.

PSU – Performance Share Units.

REDD+ – Reducing Emissions from Deforestation and Forest Degradation.

ROU – Right-of-use.

SOFR – Secured Overnight Financing Rate.

Unproved properties – Properties with no proved reserves.

VLCC – Very large crude carrier.

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.

WWC – Wild Well Control.

PART I

Items 1 and 2. Business and Properties

Hess Corporation, incorporated in the State of Delaware in 1920, is a global E&P company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA) and Malaysia. We conduct exploration activities primarily offshore Guyana, in the U.S. Gulf of Mexico, and offshore Suriname. At the Stabroek Block (Hess 30%), offshore Guyana, we and our partners have discovered a significant resource base and are executing a multi-phased development of the block. We currently have three FPSOs producing, and plan to have six FPSOs with an aggregate expected production capacity of more than 1.2 million gross bopd producing by the end of 2027. The discovered resources to date on the block are expected to underpin the potential for up to ten FPSOs.

Our Midstream operating segment, which includes Hess Corporation’s approximate 38% consolidated ownership interest in Hess Midstream LP at December 31, 2023, 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.

On October 22, 2023, we entered into an Agreement and Plan of Merger (the Merger Agreement) with Chevron and Yankee Merger Sub Inc. (Merger Subsidiary), a direct, wholly-owned subsidiary of Chevron. The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, Merger Subsidiary will be merged with and into Hess, and Hess will be the surviving corporation in the Merger as a direct, wholly-owned subsidiary of Chevron (such transaction, the Merger). Under the terms of the Merger Agreement, if the Merger is completed, our stockholders will receive at the effective time of the Merger consideration consisting of 1.025 shares of Chevron common stock for each share of our common stock. The transaction is expected to close mid-2024, subject to shareholder and regulatory approvals and other closing conditions. See Item 1A. Risk Factors for a discussion of risks related to the Merger.

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, 2023 were $78.10 per barrel for West Texas Intermediate (WTI) (2022: $94.13) and $82.51 per barrel for Brent (2022: $97.98). Our total proved developed and undeveloped reserves at December 31 were as follows:


	Crude Oil & Condensate		Natural Gas Liquids		Natural Gas		Total
	2023	2022	2023	2022	2023	2022	2023	2022

	(Millions of bbls)		(Millions of bbls)		(Millions of mcf)		(Millions of boe)
Developed
United States	265	277	173	156	656	648	547	541
Guyana	201	116	—	—	71	37	213	122
Malaysia and JDA	3	3	—	—	288	304	51	54
	469	396	173	156	1,015	989	811	717
Undeveloped
United States	204	206	89	89	336	356	349	354
Guyana	186	164	—	—	114	54	205	173
Malaysia and JDA	—	—	—	—	27	71	5	12
	390	370	89	89	477	481	559	539
Total
United States	469	483	262	245	992	1,004	896	895
Guyana	387	280	—	—	185	91	418	295
Malaysia and JDA	3	3	—	—	315	375	56	66
	859	766	262	245	1,492	1,470	1,370	1,256

Proved undeveloped reserves were 41% of our total proved reserves at December 31, 2023 on a boe basis (2022: 43%). Proved reserves held under production sharing contracts totaled 45% of our crude oil reserves and 34% of our natural gas reserves at December 31, 2023 (2022: 37% and 32%, 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 92 through 101.

Production

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


	2023	2022	2021

Crude oil – Thousands of barrels
United States
North Dakota	30,271	27,238	29,176
Offshore	8,111	7,995	10,451
Total United States	38,382	35,233	39,627
Guyana	41,831	28,526	10,920



Malaysia and JDA	1,728	1,393	1,264



Other (a)	—	5,524	7,791
Total	81,941	70,676	59,602


Natural gas liquids – Thousands of barrels
United States
North Dakota	24,634	19,488	17,889
Offshore	550	681	1,517
Total United States	25,184	20,169	19,406


Natural gas – Thousands of mcf
United States
North Dakota	69,781	56,903	59,013
Offshore	15,565	16,024	26,276
Total United States	85,346	72,927	85,289


Malaysia and JDA	134,404	131,509	126,743



Other (a)	—	3,565	3,557
Total	219,750	208,001	215,589

Total Barrels of Oil Equivalent (in millions) (a)	143.8	125.5	114.9

(a)Other includes our interests in Libya (sold in November 2022) and Denmark (sold in August 2021). Net production from Libya was 6.1 million boe for 2022 (2021: 7.2 million boe). Net production from Denmark was 1.2 million boe for 2021.

E&P Operations

At December 31, 2023, our significant E&P assets included the following:

United States

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

North Dakota:

Bakken: At December 31, 2023, we held approximately 466,000 net acres in the Bakken. Net production averaged 182,000 boepd in 2023. We drilled 118 wells and brought 113 wells on production in 2023, bringing the total operated production wells to 1,757 at December 31, 2023. We added a fourth operated rig in July 2022 and during 2024, we plan to operate four rigs.

Offshore:

Gulf of Mexico: At December 31, 2023, we held approximately 44,000 net developed acres, with our production operations principally at the Baldpate (Hess 50%), Conger (Hess 38%), Llano (Hess 50%), Penn State (Hess 50%), Stampede (Hess 25%) and Tubular Bells (Hess 57%) Fields. At December 31, 2023, we held approximately 234,000 net undeveloped acres, of which leases covering approximately 113,000 net acres are due to expire in the next three years. In the fourth quarter of 2023, we were the high bidder on 20 leases in the U.S. Department of Interior’s Lease Sale 261 covering approximately 37,000 net acres, and we expect to be awarded these leases in the first quarter of 2024. In 2023, we completed drilling operations on the Hess operated Pickerel-1 exploration well (Hess 100%) located in Mississippi Canyon Block 727, where oil bearing reservoirs were encountered. The well will be a tie-back to the Tubular Bells production facility. We also spud the Hess operated Black Pearl development well (Hess 25%) in the fourth quarter of 2023. The well is planned as a tie-back to the Stampede production facility. In 2024, we plan to participate in two wells.

Guyana

Stabroek Block: The Stabroek Block (Hess 30%), offshore Guyana, covers approximately 6.6 million acres. The operator, ExxonMobil Guyana Ltd, has made more than 30 discoveries since 2015, with the discovered resources to date on the block expected to underpin the potential for up to ten FPSOs. The first six FPSOs are expected to have an aggregate expected production capacity of more than 1.2 million gross bopd by the end of 2027.

The Liza Phase 1 development began producing oil in December 2019 utilizing the Liza Destiny FPSO and in the fourth quarter of 2023 increased its production capacity to within the range of 150,000 gross bopd to 160,000 gross bopd. The Liza Phase 2 development, which commenced producing oil in February 2022 from the Liza Unity FPSO, reached its initial production capacity of approximately 220,000 gross bopd in July 2022, and increased its production capacity to approximately 250,000 gross bopd in the third quarter of 2023. Further production optimization work is planned in 2024. The third development, Payara, began producing oil in November 2023 from the Prosperity FPSO and reached its initial production capacity of approximately 220,000 gross bopd in January 2024.

A fourth development, Yellowtail, was sanctioned in April 2022 and will utilize the ONE GUYANA FPSO with an expected initial production capacity of approximately 250,000 gross bopd, with first production expected in 2025. Six drill centers are planned with up to 26 production wells and 25 injection wells.

A fifth development, Uaru, was sanctioned in April 2023 and will utilize the Errea Wittu FPSO with an expected initial production capacity of approximately 250,000 gross bopd, with first production expected in 2026. Ten drill centers are planned with up to 21 production wells and 23 injection wells.

A sixth development, Whiptail, was submitted to the Government of Guyana for approval in the fourth quarter of 2023. Pending government approvals and project sanctioning, the project is expected to have an initial production capacity of approximately 250,000 gross bopd, with first production anticipated in 2027.

A gas to energy project is underway to construct a 130-mile pipeline network and associated infrastructure in order to transport approximately 50 million standard cubic feet of natural gas per day from the Liza Field to a 300 megawatt onshore power plant (Gas to Energy Project), which is expected to be constructed and operated by the Government of Guyana. ExxonMobil Guyana Ltd. expects to complete pipeline construction and field hook-up by the end of 2024.

The expiration of the exploration license for the Stabroek Block was extended one year from October 2026 to October 2027, and the end of the first renewal period of the exploration license, which requires the relinquishment of 20% of the acreage not held by discoveries, was extended one year from October 2023 to October 2024, both as a result of force majeure due to the COVID-19 pandemic.

In 2023, the operator drilled a total of three successful exploration and appraisal wells that encountered oil and two unsuccessful exploration wells for which the well costs were expensed. Subsequent to December 31, 2023, the operator completed one successful exploration well and one successful appraisal well. In 2024, the operator plans to utilize six drillships to continue to perform exploration, appraisal, and development activities.

Kaieteur Block: We relinquished our 20% participating interest, subject to government approval, in the Kaieteur Block which is adjacent to the Stabroek Block, in the third quarter of 2023.

Malaysia and JDA

Malaysia/Thailand Joint Development Area (JDA): Production comes from the Carigali Hess operated Block A-18 in the Malaysia/Thailand joint development area in the Gulf of Thailand (Hess 50%). In 2024, the operator plans to drill approximately five development wells.

Malaysia: Our production in Malaysia comes from our interests in Block PM302 (Hess 50%) and Block PM325 (Hess 50%) located in the North Malay Basin (NMB), offshore Peninsular Malaysia and Block PM301 (Hess 50%), which is adjacent to and is unitized with Block A‑18 of the JDA. In 2024, we plan to continue development activities at NMB, including drilling approximately five wells.

Other

Suriname: We hold a 33% non-operated participating interest in both Block 42 and Block 59, offshore Suriname. Exploration activities are planned at both blocks in 2024.

Canada: We held a 25% non-operated participating interest in two exploration licenses offshore Newfoundland, which expired in January 2024. In 2023, the operator, BP Canada, completed drilling operations on the Ephesus exploration well which did not encounter commercial quantities of hydrocarbons.

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 70 billion cubic feet of natural gas per year through 2025 and approximately 30 billion cubic feet per year in 2026 and 2027. At the North Malay Basin development project, offshore Peninsular Malaysia, we have annual minimum net sales commitments of approximately 55 billion cubic feet of natural gas per year through 2025. At the Liza Phase 1 and Phase 2 development projects at the Stabroek Block, offshore Guyana, we have annual minimum net sales commitments of approximately 2.6 billion cubic feet of natural gas per year following the commissioning period of the Gas to Energy Project. ExxonMobil Guyana Ltd. expects to complete pipeline construction and field hook-up by the end of 2024. The estimated total volume of natural gas subject to these sales commitments is approximately 375 billion cubic feet. We also have multiple minimum delivery commitments in the Bakken for natural gas and NGL with various end dates 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.

Selling Prices and Production Costs

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


	2023		2022		2021
Average Selling Prices (a)
Crude Oil – Per Barrel (Including Hedging)
United States
North Dakota	$	70.44	$	81.06	$	55.57
Offshore	72.06		81.38		60.09
Total United States	70.80		81.14		56.64
Guyana	80.72		89.86		68.57
Malaysia and JDA	75.51		89.77		71.00
Other (b)	—		93.67		66.39
Worldwide	75.97		85.76		60.08

Crude Oil – Per Barrel (Excluding Hedging)
United States
North Dakota	$	73.80	$	91.26	$	59.90
Offshore	75.39		91.51		64.77
Total United States	74.15		91.32		61.05
Guyana	82.20		96.52		71.07
Malaysia and JDA	75.51		89.77		71.00
Other (b)	—		101.92		69.25
Worldwide	78.29		94.15		63.90

Natural Gas Liquids – Per Barrel
United States
North Dakota	$	20.77	$	35.09	$	30.74
Offshore	20.87		35.24		26.40
Worldwide	20.77		35.09		30.40

Natural Gas – Per Mcf
United States
North Dakota	$	1.68	$	5.50	$	4.08
Offshore	2.16		6.21		3.25
Total United States	1.76		5.66		3.82
Malaysia and JDA	5.95		5.62		5.15
Other (b)	—		5.93		3.40
Worldwide	4.32		5.64		4.60

Average production (lifting) costs per barrel of oil equivalent produced (c)
United States
North Dakota (d)	$	27.16	$	29.02	$	25.87
Offshore	26.98		22.19		12.88
Total United States	27.61		28.16		23.27
Guyana (e)	9.60		11.23		17.93
Malaysia and JDA	7.33		6.12		4.72
Other (b)	—		2.78		6.34
Worldwide	18.96		18.97		17.91

(a)Selling prices in the United States and Guyana are adjusted for certain processing and distribution fees included in Marketing expenses.

(b)Other includes our interests in Libya (sold in November 2022) and Denmark (sold in August 2021).

(c)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.

(d)Includes Midstream tariff expense of $18.73 per boe in 2023 (2022: $21.21 per boe; 2021: $19.23 per boe).

(e)Includes pre-development costs from the operator for future phases of development and Hess internal costs totaling $1.87 per boe in 2023 (2022: $2.76 per boe; 2021: $5.76 per boe).

Gross and Net Undeveloped Acreage

At December 31, 2023, gross and net undeveloped acreage amounted to:


	Undeveloped Acreage (a)

	Gross	Net

	(In thousands)
United States	340	235
Guyana	9,804	2,608
Malaysia and JDA	197	98
Canada	1,304	326
Suriname	4,363	1,454
Total (b)	16,008	4,721

(a)Includes acreage held under production sharing contracts.

(b)At December 31, 2023, 63% of our net undeveloped acreage, primarily in Suriname, Guyana, and Canada 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, 2023 gross and net developed acreage and productive wells amounted to:


	Developed Acreage Applicable to Productive Wells		Productive Wells (a)
			Oil		Gas
	Gross	Net	Gross	Net	Gross	Net

	(In thousands)
United States	794	511	3,266	1,572	10	5
Guyana	164	49	31	9	—	—
Malaysia and JDA	481	241	—	—	134	65
Total	1,439	801	3,297	1,581	144	70

(a)Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 31 gross wells and 27 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
	2023	2022	2021	2023	2022	2021
Productive wells
United States	1	—	—	105	70	48
Guyana	1	3	3	5	2	3
Malaysia and JDA	—	1	—	8	6	2
Libya	—	—	—	—	—	1
	2	4	3	118	78	54
Dry holes
United States	—	—	—	—	—	—
Guyana (a)	1	—	—	—	—	—
Canada (b)	—	—	—	—	—	—
	1	—	—	—	—	—
Total	3	4	3	118	78	54

(a)Includes the Fish/Tarpon-1 and Kokwari-1 wells in 2023, the Banjo-1 well in 2022, and the Koebi-1 well in 2021 at the Stabroek Block.

(b)Includes the Ephesus well offshore Newfoundland in 2023.

Number of Wells in the Process of Being Drilled

At December 31, 2023, the number of wells in the process of drilling amounted to:


	Gross Wells	Net Wells
United States	57	18
Guyana (a)	22	7
Malaysia and JDA	4	2

Total	83	27

(a)Includes 12 gross (and 4 net) water injection and gas injection wells in process at December 31, 2023.

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 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. 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, Hess 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 owned 6% of the consolidated entity on an as-exchanged basis and Hess and GIP each owned 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.

In 2021, Hess Midstream completed two underwritten public equity offerings of an aggregate of approximately 15.5 million Hess Midstream Class A shares held by affiliates of Hess and GIP. The Class A shares of Hess Midstream were obtained by Hess and GIP through the exchange of 15.5 million of their Class B units of HESM Opco. In 2021, HESM Opco repurchased 31.25 million HESM Opco Class B units held by affiliates of Hess and GIP for $750 million in a single transaction. HESM Opco issued $750 million in aggregate principal amount of 4.250% fixed-rate senior unsecured notes due 2030 in a private offering to finance the repurchase.

In 2022, Hess Midstream completed a single underwritten public equity offering of approximately 10.2 million Hess Midstream Class A shares held by affiliates of Hess and GIP. The Class A shares of Hess Midstream were obtained by Hess and GIP through the exchange of approximately 10.2 million of their Class B units of HESM Opco. In 2022, HESM Opco repurchased approximately 13.6 million HESM Opco Class B units held by affiliates of Hess and GIP for $400 million in a single transaction. HESM Opco issued $400 million in aggregate principal amount of 5.500% fixed-rate senior unsecured notes due 2030 in a private offering to repay borrowings under its revolving credit facility used to finance the repurchase.

In 2023, Hess Midstream completed two underwritten public equity offerings of an aggregate of approximately 24.3 million Hess Midstream Class A shares held by affiliates of Hess and GIP. The Class A shares of Hess Midstream were obtained by Hess and GIP through the exchange of 24.3 million of their Class B units of HESM Opco. In 2023, HESM Opco repurchased an aggregate of approximately 13.6 million HESM Opco Class B units in multiple transactions from affiliates of Hess and GIP for total proceeds of $400 million. The unit repurchases were financed by borrowings under HESM Opco's revolving credit facility.

After giving effect to the above transactions, public shareholders of Class A shares of Hess Midstream own approximately 30%, GIP owns approximately 32%, and Hess owns approximately 38% of the consolidated entity on an as-exchanged basis at December 31, 2023.

At December 31, 2023, 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 1,410 miles of high and low pressure natural gas and NGL gathering pipelines with a current capacity of up to approximately 660 mmcfd. The system has an aggregate compression capacity of approximately 480 mmcfd including approximately 70 mmcfd of compression capacity added in 2023 by constructing one new greenfield compressor station and expanding an existing compressor station. Construction was also completed on an additional greenfield compressor station that, once put into operation in early 2024, will further increase compression capacity by approximately 30 mmcfd.

•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 and the Johnson’s Corner Header System. The crude oil gathering system consists of approximately 570 miles of crude oil gathering pipelines with a current capacity of up to approximately 290,000 bopd.

•Tioga Gas Plant: A natural gas processing and fractionation plant located in Tioga, North Dakota, with a current total processing capacity of approximately 400 mmcfd, an NGL fractionation capacity of approximately 60,000 boepd and y-grade NGL stabilization capacity of approximately 25,000 boepd.

•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 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, Dakota Access Pipeline (DAPL) and other 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 are operated 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 DAPL and other 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 300 miles of pipeline in gathering systems or by third-party trucking to water handling facilities for disposal.

•Other DAPL Connections: Various connections into DAPL, which are crude oil delivery points within the terminal system located in Williams and Mountrail Counties, North Dakota that receive crude oil by pipeline from the crude oil gathering system for delivery into DAPL. The facility has a delivery capacity of approximately 120,000 bopd of crude oil.

The Midstream segment earns substantially all of its revenues by charging fees for gathering, compressing and processing natural gas and fractionating NGLs; gathering, terminaling, loading and transporting crude oil and NGLs; storing and terminaling propane; and gathering and disposing produced water. Effective January 1, 2014, certain subsidiaries of Hess Midstream entered into (i) gas gathering, (ii) crude oil gathering, (iii) gas processing and fractionation, (iv) storage services and (v) terminaling and export services commercial agreements with certain subsidiaries of Hess, each generally with an initial ten-year term which could be extended for an additional ten-year term at the unilateral right of the Hess Midstream subsidiaries. The Hess Midstream subsidiaries exercised their right to extend the terms of each of these commercial agreements for the secondary term effective January 1, 2024 through December 31, 2033. Effective January 1, 2019, a subsidiary of Hess Midstream entered into water gathering and disposal services agreements with a subsidiary of Hess. These agreements also provide Hess Midstream the capacity to provide concurrent use of these services directly to third parties.

The commercial agreements contain minimum volume commitments which are based on nominations covering substantially all of the E&P segment’s existing and future owned or controlled production in the Bakken and projected third-party volumes owned or controlled by the E&P segment through dedicated third-party contracts. Minimum volume commitments are equal to 80% of the nominations and apply on a three-year rolling basis such that they are set for the three years following the most recent nomination. During the initial term of each commercial agreement, volume deficiencies are measured quarterly and any associated shortfall payments are not subject to future reduction or offset. During the secondary term of each commercial agreement, the applicable Hess

subsidiary will be entitled to receive a credit with respect to the amount of any shortfall fee paid. Such Hess subsidiary may apply the credit against the fees payable for any volumes delivered under the applicable agreement in excess of the nominated volumes up to four quarters after the credit is earned. No credits will be provided with respect to crude oil terminaling services under the terminaling and export services commercial agreement or water handling services under the water gathering and disposal services agreements.

Competition and Market Conditions

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

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 CGA, MSRC, MWCC, WWC and 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. 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, nine 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 Committee and Response Network Committee of MWCC, the Technical Operations Committee of CGA and the Emergency Preparedness and Response Committee of API. We also maintain regular voting membership in CGA, MSRC and 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 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 $450 million of coverage is provided through an industry mutual insurance group. Above this $450 million threshold, additional insurance is carried which ranges in value up to $800 million in total at December 31, 2023, 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 $830 million, which coverage under a standard JOA 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 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.

Government Regulations

The crude oil and natural gas industry is regulated at federal, state, local and foreign government levels. Regulations affecting elements of the energy sector are under continuous review for amendment or expansion over time, which may result in incremental costs of doing business and affect our profitability. See Regulatory, Legal and Environmental Risks in Item 1A. Risk Factors. Compliance with various existing environmental, health and safety regulations is not expected to have a material adverse effect on our financial condition or results of operations. However, 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 and may reduce demand for our products. We spent approximately $28 million in 2023 (2022: $23 million; 2021: $16 million) for environmental remediation. Additionally, we may be exposed to decommissioning liabilities, including for divested assets. See Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements. The level of other expenditures to comply with federal, state, local and foreign country 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, health and safety regulations affecting our business, see Environment, Health and Safety in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Human Capital Management

Corporate Culture and Overview

Our human capital strategy aims to attract, engage and retain our talent by investing in their professional development and providing them with challenging and rewarding opportunities for personal growth. Our workplace culture is guided by our values and reinforced by developing quality leadership, fostering DEI, emphasizing continuous learning, creating opportunities for engagement, driving innovation, and embracing Lean improvement processes. We utilize the Life at Hess framework to optimize the work experience for our multigenerational and demographically diverse workforce and unlock the discretionary effort that is required to perform at a high level on a sustained basis. The Life at Hess framework encompasses programs, policies and practices, and a listening system that draws on in-person dialogues, pulse polls and data analytics to help leaders understand employees’ experiences and perspectives to inform their decision making.

As of December 31, 2023, we had 1,756 employees globally, as detailed below.


	United States	Guyana	Malaysia and JDA	Total
Job Category
Executives and Senior Officers	29	—	1	30
First and Mid-Level Managers	373	—	67	440
Professionals	815	—	90	905
Other	377	—	4	381
Total	1,594	—	162	1,756

Life at Hess

We prioritize the safety of our workforce with programs and practices designed to help ensure that everyone, everywhere gets home safe every day. We continue to adapt our work policies and benefits to prioritize emotional, mental and physical health and well-being.

During 2023, we held several employee surveys throughout the year to understand employee sentiment and engagement and made the following improvements in response to employee feedback:

•formalized individual and team learning paths with new in-person and virtual learning and mentoring opportunities;

•enhanced resources to improve the effectiveness of hybrid working;

•enhanced our wellness program supporting physical, financial, social and emotional well-being of our employees; and

•established a new training and development program to help leaders navigate an increasingly dynamic, diverse, and complex work environment.

Diversity, Equity and Inclusion

In keeping with our values and purpose, we have a longstanding commitment to DEI and taking action to foster a sustainable culture of inclusion for everyone. DEI is a business imperative for improved performance and the innovation needed to accomplish our business goals now and in the future. Additionally, Hess is committed to providing a global workplace free from discrimination and harassment, where everyone can achieve their full potential. We provide equal employment opportunities for all employees and job candidates regardless of race, color, religion, gender, age, sexual orientation, gender identity, creed, national origin, genetic information, disability, veteran status or any other protected status.

Hess’ DEI Council provides executive leadership guidance to embed DEI into our culture and drive progress throughout the organization. Our expectations for a culture fostering mutual respect and trust are included in our Code of Business Conduct and Ethics and related policies. It is also reinforced regularly with employees at every level through regular communication and ongoing training. Additional information about our policies and practices, including training, employee engagement initiatives and workforce data, is included in our sustainability reports and annual U.S. Equal Employment Opportunity reporting, which is available on our website at www.hess.com.

During 2023, Hess either maintained or improved diversity across most levels of our workforce, as illustrated in the table below. We believe our strategic focus on DEI, including new training and diversity outreach programs and our inaugural Hess Inclusion Summit, contributed to this outcome. Our DEI leader helps to develop a tailored, long-term strategy that defines our objectives and strategies to advance DEI now and in the future. We have six employee resource groups that provide valuable employee insights to sustain a diverse, equitable and inclusive environment for everyone to thrive and perform at their best and partner with outside organizations to improve DEI in our communities. Each year, we share workforce activity and trends such as employee turnover, promotions, DEI and development metrics, along with qualitative information such as program development and progress, with our Board of Directors. Management also reviews these topics in greater detail with the Compensation and Management Development Committee throughout the year.


	Women (U.S. and International)						Minorities (a) (U.S. Based Employees)
	2023		2022		2021		2023		2022		2021
Job Category
Executives and Senior Officers	17	%	16	%	16	%	20	%	19	%	19	%
First and Mid-Level Managers	24	%	23	%	23	%	22	%	22	%	20	%
Professionals	33	%	33	%	34	%	32	%	31	%	30	%
Other	17	%	18	%	19	%	16	%	16	%	16	%
Total	27	%	27	%	27	%	26	%	25	%	24	%

(a)As defined by the U.S. Department of Labor.

Compensation and Benefits Programs

Our compensation and benefits programs are focused on attracting and retaining a highly skilled workforce in a rapidly changing industry. We benchmark these programs each year against other companies in our industry and conduct a review to help foster pay equity. The results are shared in our sustainability reports and on www.hess.com. We maintain an annual incentive plan that applies to all employees, including executive officers, with shared enterprise performance metrics for all participants. We also provide a comprehensive, nationally recognized wellness program that is designed to improve the physical, financial, social and emotional well-being of our employees.

Information about our Executive Officers

The following table presents information as of February 26, 2024 regarding executive officers of the Corporation:


Name	Age	Office Held* and Business Experience	Year Individual Became an Executive Officer



John B. Hess	69	Chief Executive Officer and Director Mr. Hess has been Chief Executive Officer of the Corporation since 1995 and employed by the Corporation since 1977. He has over 45 years of experience in the oil and gas industry.	1983
Gregory P. Hill	62	President and Chief Operating Officer 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.	2009
Timothy B. Goodell	66	Executive Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer Mr. Goodell has been General Counsel of the Corporation since 2009, Corporate Secretary since 2016, Chief Compliance Officer since 2017 and Executive Vice President since 2020. Prior to joining the Corporation in 2009, he was a partner at the law firm of White & Case, LLP where he spent 25 years.	2009
John P. Rielly	61	Executive Vice President and Chief Financial Officer Mr. Rielly has been Chief Financial Officer of the Corporation since 2004 and Executive Vice President since 2020. 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.	2002
Richard Lynch	66	Senior Vice President, Technology and Services 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.	2018
Gerbert Schoonman	58	Senior Vice President, Global Production 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.	2020
Andrew Slentz	62	Senior Vice President, Human Resources and Office Management 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 30 years in human resources experience at large international public companies.	2016
Barbara Lowery-Yilmaz	67	Senior Vice President and Chief Exploration Officer Ms. Lowery-Yilmaz has been the Senior Vice President, Exploration of the Corporation since 2014 and Chief Exploration Officer since 2020. 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.	2014

*All officers referred to herein hold office in accordance with our By-laws until the first meeting of directors in connection with the annual meeting of stockholders of the Corporation and until their successors shall have been duly chosen and qualified. Each of said officers was elected to the office opposite their name on May 17, 2023.

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.

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, including our sustainability report, is not part of or otherwise 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 by our Chief Executive Officer regarding our compliance with the NYSE’s corporate governance standards.

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.

Proposed Chevron Merger Risks

We will be subject to business uncertainties while the Merger is pending, which could adversely affect our businesses. Uncertainty about the effect of the Merger on employees and those that do business with us may have an adverse effect to the Corporation. These uncertainties may impair our ability to attract, retain and motivate key personnel until the Merger is completed and for a period of time thereafter, and could cause those that transact with us to seek to change their existing business relationships with us. Employee retention at the Corporation may be challenging during the pendency of the Merger, as employees may experience uncertainty about their roles. In addition, the Merger Agreement restricts us from entering into certain corporate transactions, entering into certain material contracts, making certain changes to our capital budget, incurring certain indebtedness and taking other specified actions without the consent of Chevron, and generally requires us to continue our operations in the ordinary course of business during the pendency of the Merger. These restrictions may prevent us from pursuing attractive business opportunities or adjusting our capital plan prior to the completion of the Merger.

We may become subject to lawsuits relating to the Merger, which could adversely affect our business, financial condition and operating results. We and/or our respective directors and officers may become subject to lawsuits relating to the Merger. Such litigation is very common in connection with acquisitions of public companies, regardless of the merits of the underlying acquisition. While we will evaluate and defend against any actions vigorously, the costs of the defense of such lawsuits and other effects of such litigation could have an adverse effect on our business, financial condition and operating results.

Completion of the Merger is subject to a number of conditions, and if these conditions are not satisfied or waived, the Merger will not be completed. Failure to complete, or significant delays in completing, the Merger could negatively affect the trading prices of our common stock and our future business and financial results. Completion of the Merger is subject to satisfaction or waiver of certain closing conditions, including (i) the receipt of the required approval from our stockholders, (ii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended applicable to the Merger, (iii) the absence of any order or law prohibiting consummation of the Merger, (iv) the effectiveness of the Registration Statement on Form S-4 to be filed by Chevron pursuant to which the shares of Chevron common stock to be issued in connection with the Merger will be registered with the U.S. Securities and Exchange Commission and (v) the authorization for listing on the New York Stock Exchange of the shares of Chevron common stock to be issued in connection with the Merger. The obligation of each party to consummate the Merger is also conditioned upon the other party having performed in all material respects its obligations under the Merger Agreement and the other party’s representations and warranties in the Merger Agreement being true and correct (subject to certain materiality qualifiers). Additionally, Hess and Chevron have been engaged in discussions with Exxon Mobil Corporation and China National Offshore Oil Corporation regarding a right of first refusal provision in the joint operating agreement for the Stabroek Block. If these discussions do not result in an acceptable resolution and arbitration (if pursued) does not result in a confirmation that such right of first refusal provision is inapplicable to the Merger, then there would be a failure of a closing condition under the Merger Agreement, in which case the Merger would not close. For additional information, please see the section entitled “The Merger-Stabroek JOA” in Chevron’s preliminary registration statement on Form S-4 to be filed on February 26, 2024. The obligation of Hess to consummate the merger is also subject to the receipt of a tax opinion from legal counsel that the Merger will qualify as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code of 1986, as amended. There can be no assurance that the conditions to the completion of the Merger will be satisfied or waived or that the Merger will be completed.

If the Merger is not completed, or if there are significant delays in completing the Merger, the trading prices of our common stock and our future business and financial results could be negatively affected, and we may be subject to several risks, including the following:

•the requirement that we pay Chevron a termination fee of approximately $1.715 billion under certain circumstances provided in the Merger Agreement;

•negative reactions from the financial markets, including declines in the prices of our common stock due to the fact that current prices may reflect a market assumption that the Merger will be completed;

•having to pay certain significant costs relating to the Merger; and

•the attention of our management will have been diverted to the Merger rather than our own operations and pursuit of other opportunities that could have been beneficial to us.

The Merger Agreement limits our ability to pursue alternatives to the Merger. The Merger Agreement contains provisions that may discourage a third party from submitting a competing proposal that might result in greater value to our stockholders than the Merger, or may result in a potential competing acquirer of the Corporation proposing to pay a lower per share price to acquire us than

it might otherwise have proposed to pay. These provisions include a general prohibition on us from soliciting or, subject to certain exceptions relating to the exercise of fiduciary duties by our board of directors, entering into discussions with any third party regarding any competing proposal or offer for a competing transaction.

Because the exchange ratio in the Merger Agreement is fixed and because the market price of Chevron common stock will fluctuate prior to the completion of the Merger, our stockholders cannot be sure of the market value of the Chevron common stock they will receive as consideration in the Merger. Under the terms of the Merger Agreement, if the Merger is completed, our stockholders will receive at the effective time of the Merger consideration consisting of 1.025 shares of Chevron common stock for each share of our common stock. The exchange ratio of the Merger consideration is fixed, and under the Merger Agreement there will be no adjustment to the Merger consideration for changes in the market price of Chevron common stock or our common stock prior to the completion of the Merger.

If the Merger is completed, there will be a time lapse between the date of signing of the Merger Agreement and the date on which our stockholders who are entitled to receive the Merger consideration actually receive the Merger consideration. The respective market values of Chevron common stock and our common stock have fluctuated and may continue to fluctuate during this period as a result of a variety of factors, including general market and economic conditions, changes in each company’s business, operations and prospects, commodity prices, regulatory considerations, and the market’s assessment of Chevron’s business and the Merger. Such factors are difficult to predict and in many cases may be beyond the control of Chevron and us. The actual value of the Merger consideration received by our stockholders at the completion of the Merger will depend on the market value of Chevron common stock at that time. This market value may differ, possibly materially, from the market value of Chevron common stock at the time the Merger Agreement was entered into or at any other time.

Shares of Chevron common stock received by our stockholders as a result of the Merger will have different rights from shares of our common stock. Upon completion of the Merger, our stockholders will no longer be stockholders of Hess, and our stockholders who receive the Merger consideration will become Chevron stockholders, and their rights as Chevron stockholders will be governed by the terms of Chevron’s charter and by-laws. There are differences between the current rights of our stockholders and the rights to which such stockholders will be entitled as Chevron stockholders.

Market and Third-Party Risks

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 weather, instability, changes in governments, armed conflict, economic sanctions and outbreaks of infectious diseases, such as COVID-19) 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, availability of and demand for alternative fuels or other forms of energy; the effect of energy conservation and environmental protection efforts; and overall economic conditions globally (including inflation, slower growth or recession, higher interest rates, supply chain constraints, and consequences associated with the ongoing invasion of Ukraine by Russia or the conflict between Israel and Hamas). 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 2023 were $77.60 per barrel for WTI (2022: $94.33; 2021: $68.08) and $82.18 per barrel for Brent (2022: $99.04; 2021: $70.95). 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.

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. For example, in June 2021, the U.S. Bankruptcy Court approved the bankruptcy plan for Fieldwood Energy LLC which includes transferring abandonment obligations of Fieldwood to us and other predecessors in title of certain of its assets, who are jointly and severally liable for the obligations. See Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements. As a result, actions of our contractual counterparties may adversely affect the value of our investments and result in increased costs or liabilities.

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, or may have established strategic relationships in areas we operate, or may be willing to incur a higher level of risk than we are willing to incur. 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.

Operational and Strategic Risks

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, changes in prevailing oil and gas prices, production sharing contracts, which may decrease reserves as crude oil and natural gas prices increase, and other factors.

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, derailments, fires, explosions, blowouts, oil releases, power outages, cratering, pipeline interruptions and ruptures, severe weather, such as hurricanes, floods, freezes and heat waves or droughts, geological events, shortages in availability of skilled labor, cyber-attacks or health measures related to outbreaks of infectious diseases, such as COVID-19. We maintain insurance coverage against many, but not all, potential losses and liabilities in amounts we deem prudent, including for property and casualty losses. Some forms of insurance may be unavailable in the future or be available only on terms that are deemed economically unacceptable. Moreover, there can be no assurance that such insurance will adequately protect us against liability from all potential consequences and damages. For example, we are self-insured against physical damage to property and liability related to windstorms. In 2023 and 2022, there was no significant hurricane-related downtime whereas in 2021, hurricane related downtime reduced net production by 4,000 boepd and hurricane related maintenance and repair costs were approximately $7 million. In addition, the frequency and severity of weather conditions and other meteorological phenomena, including storms, droughts, extreme temperatures, and changes in temperature and precipitation patterns that impact our business activities, may also be impacted by the effects of climate change. Energy needs could increase or decrease as a result of extreme weather conditions depending on the duration and magnitude of any such climate change. Increased energy use due to weather changes may require us to invest in order to serve increased demand or create operational challenges. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. To the extent the frequency of extreme weather events increases, this could adversely impact our business, results of operations and financial condition.

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, services or resources, availability of necessary personnel, construction delays, unfavorable weather conditions, equipment

failures, and outbreaks of infectious diseases, such as COVID-19. These delays could impact our future results of operations and cash flows.

An inability to secure personnel, drilling rigs, equipment, supplies and other required services or to retain key employees may result in material negative economic consequences. We are dependent on oilfield service companies for items including drilling rigs, equipment, supplies and skilled labor. 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. Concerns over global economic conditions, inflation, supply chain disruptions, labor shortages, and other factors, each of which are beyond our control, contribute to increased economic uncertainty for us and our suppliers. As a result, we may encounter difficulties in obtaining required services or 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. In addition, 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 also depends upon the continued service of key members of our senior management team, who play an important role in developing and implementing our strategy. An inability to recruit and retain adequate numbers of experienced technical and professional personnel in the necessary locations or the loss or departure of key members of senior management may prevent us from executing our strategy in full or in part, which could negatively impact our business.

Disruption, failure or cybersecurity attacks affecting or targeting information technology 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 rely on computer systems, hardware, software, technology infrastructure and online sites and networks for both internal and external operations that are critical to our business (collectively, Digital Systems). Some of our Digital Systems are managed and owned by us, but we rely on third parties for a range of Digital Systems and related products and services, including but not limited to cloud computing services. We use these Digital Systems to communicate, analyze and store proprietary, financial and operating data as well as data about employees, business partners and other third parties (collectively, Confidential Information). Our reliance on technology has increased due to our use of remote communications and hybrid work-from-home arrangements, which increase cybersecurity risks due to the challenges associated with managing remote computing assets and security vulnerabilities that are present in many non-corporate and home networks.

Technical system flaws, power loss and cybersecurity risks, including cyber or phishing-attacks, unauthorized access, malicious software, data privacy breaches by employees or others with authorized access, ransomware, and other cybersecurity issues, could compromise our Digital Systems or those of our business partners and result in disruptions to our business operations or the access, disclosure or loss of our Confidential Information and communications. 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, reputational harm, 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 Digital 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. Threat actors are becoming increasingly adept in using techniques and tools, including artificial intelligence, that circumvent security controls, evade detection and remove forensic evidence. As technologies evolve and these cybersecurity attacks become more sophisticated, we may incur significant costs to upgrade or enhance our security measures to protect against such attacks. We may also face difficulties in fully anticipating or implementing adequate preventive measures or mitigating potential harm.

Financial Risks

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. All 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, rising interest rates, 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. Environmental concerns and other factors have led to lower oil and gas representation in certain key equity market indices and may increase our costs to access the equity capital markets. Any inability to access capital markets could adversely impact our financial adaptability and our ability to execute our strategy.

We may engage in risk management transactions designed to mitigate commodity price volatility and other risks that 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.

Regulatory, Legal and Environmental Risks

Our oil and gas operations are subject to environmental risks and environmental, health and safety 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, health and safety 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 occur many years in the future, in most cases. These estimates may be impacted by future changes in regulations, solvency of subsequent owners and partners 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, sustainability and other ESG 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 GHG 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 GHGs from our operations, which may result in substantial capital expenditures and compliance, operating, maintenance and remediation costs. For example, the Inflation Reduction Act of 2022 (IRA) includes a methane emissions reduction program for petroleum and natural gas systems, which requires the EPA to impose a “waste emissions charge” on excess methane emissions from certain natural gas and oil sources that are required to report under EPA’s Greenhouse Gas Reporting Program beginning January 1, 2024 and also provides significant funding and incentives for research and development of competing low carbon energy production methods. California recently enacted three climate-related disclosure laws, the Climate Corporate Data Accountability Act, Climate Related Financial Risk Act and Voluntary Carbon Market Disclosures Act, which together will require certain entities doing business in California or taking certain actions in California to report and attain third-party assurance of greenhouse gas emissions information, reporting on climate-related financial risks and reporting regarding the use of voluntary carbon credits and/or carbon reduction claims. Legislation similar to California’s Climate Corporate Data Accountability Act is under consideration in other states. In addition to increased costs for compliance, such legislation, regulations and initiatives could also impact demand as our production is sold to third parties that produce petroleum fuels, which through normal end user consumption result in the emission of GHGs.

We are prioritizing sustainable energy practices to further reduce our carbon footprint while at the same time remaining a successful operating public company. However, various key stakeholders, including our stockholders, employees, suppliers, customers, local communities and others, may have differing approaches to climate change initiatives. If we do not successfully manage expectations across these varied stakeholder interests, it could erode our stakeholders’ trust and thereby affect our reputation. Shareholder activism has been recently increasing in our industry, and stockholders may attempt to effect changes to our business or governance, whether by shareholder proposals, public campaigns, proxy solicitations or otherwise. 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. We continue to focus on developing our ESG practices, and as voluntary and regulatory ESG disclosure standards and policies continue to evolve, we have expanded and expect to further expand our public disclosures in these areas. Such disclosures may reflect aspirational goals, targets, cost estimates and other expectations and assumptions, including over long timelines, which aspirational goals, targets, cost estimates, and other expectations and assumptions are necessarily uncertain and may not be realized. Failure to realize or timely achieve progress on such aspirational goals, targets, cost estimates, and other expectations or assumptions may adversely impact us.

Furthermore, 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 petroleum 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 GHG emissions reduction requirements could severely and adversely impact the oil and gas industry and therefore significantly reduce the value of our business. 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, beginning in 2017, certain states, municipalities and private associations in California, Delaware, Maryland, Rhode Island and South Carolina separately filed lawsuits against oil, gas and coal producers, including us, for alleged damages purportedly caused by climate change. Such actions could adversely impact our business by distracting management and other personnel from their primary responsibilities, require us to incur increased costs, and/or result in reputational harm.

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 may adversely affect our operations and those of our counterparties with whom we have contracted, which may affect our financial results. These actions could result in tax increases retroactively through tax claims or prospectively through changes to applicable statutory tax rates, modification of the tax base, or imposition of new tax types. For example, on August 16, 2022 the U.S. enacted the IRA, which includes a 15% book-income alternative minimum tax on corporations with average adjusted financial statement income over $1 billion for any 3-year period ending with 2022 or later and a 1% excise tax on the fair market value of stock that is repurchased by publicly traded U.S. corporations. The alternative minimum tax and the excise tax are effective in taxable years beginning after December 31, 2022. From time to time since enactment, the Department of Treasury and the Internal Revenue Service have issued interim guidance related to the alternative minimum tax and intend to issue proposed regulations addressing the alternative minimum tax in the future. We continue to evaluate the effect of the new law and any additional guidance on our future cash flows and financial results, including if we become a taxpayer subject to the alternative minimum tax, which would apply to any taxable years beginning on or after January 1, 2024. The impact of the excise tax provision will be dependent on the extent of share repurchases made in future periods. We continue to evaluate the corporate alternative minimum tax and its potential impact on our future U.S. tax expense, cash taxes, and effective tax rate, as well as any other impacts the IRA may have on our financial position and results of operations.

Additionally, governmental actions could include limitations on post-production deductions from royalty payments; limitations or prohibitions on the sales of new oil and gas leases or extensions on existing oil and gas leases; adverse court decisions with respect to the sale of new and existing oil and gas leases or claims related to working interest payments; 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; the imposition of tariffs; and anti-bribery or anti-corruption laws. In recent years, proposals for limitations on access to oil and gas exploration and development opportunities and related litigation have grown in certain areas and may include efforts to reduce access to public and private lands; restriction of exploration and production activities within government-owned and other lands; delaying or canceling permits for drilling or pipeline construction; restrictions or changes to existing pipeline easements; limiting or banning industry techniques such as hydraulic fracturing and/or adding restrictions on the use of water and associated disposal; imposition of set-backs on oil and gas sites; reduction of sulfur content in bunker fuel; delaying or denying air-quality or siting permits; advocating for increased regulations, punitive taxation, or citizen ballot initiatives or moratoriums on industry activity; and the use of social media channels to cause reputational harm. Costs associated with responding to these anti-development efforts or complying with any new legal or regulatory requirements could significantly and adversely affect our business, financial condition and results of operations.

Political instability globally and in areas where we operate can adversely affect our business. Political instability and civil unrest have affected and may continue to affect the oil and gas markets generally. Some international areas are politically less stable than other areas and may be subject to civil unrest, conflict, insurgency, corruption, security risks and labor unrest. Political instability in areas where we operate may expose 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 invasion of Ukraine by Russia in February 2022 has led to disruption, instability, and volatility in global markets and industries, including the oil and gas markets. The U.S. government and other foreign governments imposed severe economic sanctions and export controls against Russia, certain regions of Ukraine and particular entities and individuals, and may impose additional sanctions and controls. The recent war between Israel and Hamas, which began in October 2023, has the potential for further disruption of economic markets, particularly if the conflict expands to other parts of the Middle East. To date, we have not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; however, we will continue to monitor for events that could materially impact us or our industry. Furthermore, 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. 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.

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 stockholders. Moreover, these increased duties may lead to an increase in compliance costs.

Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

Cybersecurity Risk Management and Strategy

Cybersecurity is an integral part of our enterprise risk management. We have developed and implemented a cybersecurity risk management program intended to protect the confidentiality, integrity and availability of our Digital Systems. Our cybersecurity risk management program includes a cybersecurity incident response plan as well as property and casualty insurance that may cover damages caused as a result of a cybersecurity event.

We design and assess our program based on the NIST CSF. This does not imply that we meet any particular technical standards, specifications, or requirements, only that we use the NIST CSF as a guide to help us identify, assess and manage cybersecurity risks relevant to our business.

Our cybersecurity risk management program is integrated into our overall enterprise risk management program overseen by our Chief Risk Officer, and shares certain methodologies, reporting channels and governance processes that apply across the enterprise risk management program to other areas affecting our business risks, including financial, compliance, EHS, compensation and governance matters, among other topics.

Our cybersecurity risk management program includes:

•risk assessments designed to help identify material cybersecurity risks to critical systems integral to our exploration, development and production activities as well as the activities of our business partners and our broader enterprise information technology environment;

•a security team principally responsible for managing our cybersecurity risk assessment processes, our security controls and our response to cybersecurity incidents;

•the use of external service providers, where appropriate, to assess, test or otherwise assist with aspects of our security controls;

•ongoing cybersecurity awareness and compliance training that occurs quarterly and is mandatory for all our employees, incident response personnel and senior management;

•a cybersecurity incident response plan that includes procedures for responding to cybersecurity incidents; and

•a third-party risk management process for service providers, suppliers and vendors.

We have not identified risks from known cybersecurity threats during the year ended December 31, 2023, including as a result of any prior cybersecurity incidents, that have materially affected us or are reasonably likely to materially affect us, including our operations, business strategy, results of operations, or financial condition.

Additional information about cybersecurity risks we face is discussed in Item 1A. Risk Factors, under the heading “Disruption, failure or cybersecurity attacks affecting or targeting information technology and infrastructure used by the Corporation or our business partners may materially impact our business and operations” which should be read in conjunction with the information above.

Governance

Our Board of Directors (Board) appreciates the rapidly evolving nature of threats presented by cybersecurity incidents and is committed to the prevention, timely detection and mitigation of the effects of any such incidents on the Corporation. The Board considers cybersecurity risk as part of its risk oversight function and has delegated to the Audit Committee (Committee) primary responsibility for oversight of our risk management practices, including oversight of cybersecurity and other information technology risks.

The Committee oversees management’s implementation of our cybersecurity risk management program. The Committee receives presentations on cybersecurity topics from management at least twice a year, including the nature of threats, defense and detection capabilities; incident response plans; and employee training activities. In addition, management updates the Committee, as necessary, regarding any material cybersecurity incidents as well as other incidents with lesser impact potential. The Committee reports to the full Board regarding its activities, including those related to cybersecurity.

Our management team – including our Chief Risk Officer, our Head of Information Technology and our Chief Information Security Officer (CISO) – is responsible for assessing and managing our material risks from cybersecurity threats. The team is primarily responsible for our overall cybersecurity risk management program and supervises both our internal cybersecurity personnel and our retained external cybersecurity consultants. Our Chief Risk Officer has nearly 20 years of experience in this role at the Corporation and previously served as a consultant with Ernst & Young LLP’s Risk Management and Regulatory Practice, where he assisted financial services and energy trading clients in establishing their risk management infrastructure. Our Head of Information Technology and our CISO each have over 20 years of experience in information technology leadership in oil and gas. Furthermore, our CISO holds a Bachelor of Science in Cyber and Data Security from the University of Arizona and is a Certified Information Systems Security Professional.

Our management team is informed about and monitors the efforts to prevent, detect, mitigate and remediate cybersecurity risks and incidents through various means, which may include briefings from internal security personnel; threat intelligence and other information obtained from governmental, public or private sources, including external consultants engaged by us; and alerts and reports produced by security tools deployed in the information technology environment.

Item 3. Legal Proceedings

Information regarding legal proceedings is contained in Note 17, Guarantees, Contingencies and Commitments in the Notes to Consolidated Financial Statements and is incorporated herein by reference. Pursuant to Item 103(c)(3)(iii) of Regulation S-K under the Exchange Act, we are required to disclose certain information about environmental proceedings to which a governmental authority is a party if we reasonably believe such proceedings may result in monetary sanctions, exclusive of interest and costs, above a stated threshold. We have elected to apply a threshold of $1 million for purposes of determining whether disclosure of any such proceedings is required.

Item 4. Mine Safety Disclosures

None.

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 listed on the New York Stock Exchange (ticker symbol: HES). At January 31, 2024, there were 2,494 stockholders (based on the number of holders of record) who owned a total of 307,152,064 shares of common stock. In 2023, cash dividends on common stock totaled $1.75 per share per year ($0.4375 per quarter), $1.50 per share per year ($0.3750 per quarter) in 2022 and $1.00 per share per year ($0.2500 per quarter) in 2021.

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.

•2023 Proxy Peer Group as disclosed in our 2023 Proxy Statement, and including us.

Comparison of Five-Year Shareholder Returns

Years Ended December 31,


	2018	2019	2020	2021	2022	2023
Hess Corporation	$100.00	$167.72	$135.54	$192.62	$373.83	$384.72
S&P 500	$100.00	$131.47	$155.65	$200.29	$163.98	$207.04
Proxy Peer Group	$100.00	$100.02	$63.94	$117.20	$196.77	$193.47

Share Repurchase Activities

On March 1, 2023, our Board of Directors approved a new authorization for the repurchase of our common stock in an aggregate amount of up to $1 billion. This new authorization replaced our previous repurchase authorization which was fully utilized at the end of 2022. There were no shares of our common stock repurchased for the year ended December 31, 2023. The Merger Agreement provides that, during the periods from the date of the Merger Agreement until the closing of the Merger, we are subject to certain restrictions that, among other things, restrict our ability to repurchase, redeem or retire any capital stock of the Corporation.

Equity Compensation Plans

Following is information related to our equity compensation plans at December 31, 2023.


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	1,509,912	(a)	$	78.85	19,941,906	(b)
Equity compensation plans not approved by security holders	—		—		—

(a)This amount includes 1,509,912 shares of common stock issuable upon exercise of outstanding stock options. This amount excludes 1,020,653 shares of common stock issued as restricted stock pursuant to our equity compensation plans. This amount also excludes 511,781 PSUs. For the PSUs granted in 2021 and 2022, the number of shares of common stock to be issued will range from 0% to 200% based on our total shareholder return (TSR) relative to the TSR of a predetermined group of peer companies and the S&P 500 index over a three‑year performance period ending December 31 of the year prior to settlement of the grant. For the PSU’s granted in 2023, the number of shares of common stock to be issued is based on a comparison of the Corporation’s total shareholder return compound annual growth rate (TSR CAGR) to the TSR CAGR of the SPDR S&P Oil & Gas Exploration and Production ETF (XOP), with a modifier determined by comparing the Corporation’s TSR CAGR to the TSR CAGR of the S&P 500 index, over a three-year performance period ending December 31, 2025. Payout of these PSUs will range from 0% to 200% of the target awards based on the comparison of the Corporation’s TSR CAGR to the XOP’s TSR CAGR. The modifier can only adjust the payout percentage by plus or minus 10%, up to a maximum of 210% or a minimum of 0%.

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

See Note 13, Share‑based Compensation in the Notes to Consolidated Financial Statements for further discussion of our equity compensation plans.

Item 6. [Reserved]

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, and the information set forth in Part 1, Item 1A. Risk Factors.

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, 2022 compared with the year ended December 31, 2021, which can be found in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2022 Annual Report on Form 10-K, which was filed with the Securities and Exchange Commission on February 24, 2023, and such comparisons are incorporated herein by reference.

Index

Overview

Consolidated Results of Operations

Liquidity and Capital Resources

Critical Accounting Policies and Estimates

Overview

Hess Corporation is a global E&P company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA) and Malaysia. We conduct exploration activities primarily offshore Guyana, in the U.S. Gulf of Mexico, and offshore Suriname. At the Stabroek Block (Hess 30%), offshore Guyana, we and our partners have discovered a significant resource base and are executing a multi-phased development of the block. We currently have three FPSOs producing, and plan to have six FPSOs with an aggregate expected production capacity of more than 1.2 million gross bopd producing by the end of 2027. The discovered resources to date on the block are expected to underpin the potential for up to ten FPSOs.

On October 22, 2023, we entered into the Merger Agreement with Chevron and the Merger Subsidiary. The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, Merger Subsidiary will be merged with and into Hess, and Hess will be the surviving corporation in the Merger as a direct, wholly-owned subsidiary of Chevron. Under the terms of the Merger Agreement, if the Merger is completed, our stockholders will receive at the effective time of the Merger consideration consisting of 1.025 shares of Chevron common stock for each share of our common stock. The transaction is expected to close mid-2024, subject to shareholder and regulatory approvals and other closing conditions. See Part I, Item 1A. Risk Factors for a discussion of risks related to the Merger.

Climate Change, Energy Transition and Our Strategy

We believe climate risks can and should be addressed while at the same time meeting the growing demand for affordable and secure energy, which is essential to ensure a just and orderly energy transition that aligns with the United Nations Sustainable Development Goals. The IEA’s 2023 World Energy Outlook provides three scenarios of global energy demand in 2040 based on varying levels of global response to climate change. Under all of the IEA scenarios, oil and natural gas are expected to be needed for decades to come and we expect that significant investment will be required to meet the world’s projected growing energy needs, both in renewable energy sources and in oil and gas.

Our strategy is to grow our resource base, have a low cost of supply and sustain cash flow growth. Our strategy aligns with the energy transition needed to reach the energy-related Sustainable Development Goals of the United Nations. Our commitment to sustainability starts with our Board of Directors and senior management and is reinforced throughout our organization. Our Board of Directors, led by its Environmental, Health and Safety Committee, is actively engaged in overseeing Hess’ sustainability practices so that sustainability risks and opportunities are taken into account when making strategic decisions. Our Board’s Compensation and Management Development Committee has tied executive compensation to advancing our environmental, health and safety goals.

We have five year GHG reduction targets for 2025, which are to reduce operated Scope 1 and 2 GHG emissions intensity by approximately 50% and methane emissions intensity by approximately 50%, both from 2017 levels. In January 2022, we announced our plan to reduce routine flaring at Hess operated assets to zero by the end of 2025. In December 2022, we announced an agreement

with the Government of Guyana to purchase 37.5 million REDD+ carbon credits, including current and future issuances, for a minimum of $750 million from 2022 through 2032 to prevent deforestation and support sustainable development in Guyana. This agreement adds to the Corporation’s ongoing emissions reduction efforts and is an important part of our commitment to achieve net zero Scope 1 and 2 greenhouse gas emissions on a net equity basis by 2050.

Our business planning includes actions we expect to undertake to continue reducing our carbon footprint consistent with our targets. We also conduct annual scenario planning as a methodology to assess our portfolio’s resilience to differing scenarios of energy supply and demand over the longer term, and to inform our understanding of future risks and opportunities in relation to the potential evolution of energy demand, energy mix, the emergence of new technologies, and possible changes by policymakers with respect to greenhouse gas emissions and climate change.

Consolidated Results

Net income attributable to Hess Corporation was $1,382 million in 2023 compared with $2,096 million in 2022. Excluding items affecting comparability of earnings between periods summarized on page 34, adjusted net income was $1,552 million in 2023 compared with $2,176 million in 2022. Net production averaged 394,000 boepd in 2023 and 344,000 boepd in 2022. The average realized crude oil price, including the effect of hedging, was $75.97 per barrel in 2023 and $85.76 per barrel in 2022. Total proved reserves were 1,370 million boe and 1,256 million boe at December 31, 2023 and December 31, 2022, respectively.

Significant 2023 Activities

The following is an update of significant E&P activities during 2023:

E&P assets:

•In North Dakota, net production from the Bakken shale play averaged 182,000 boepd in 2023 (2022: 154,000 boepd). Net production was higher in 2023 reflecting increased drilling and completion activity and higher NGL and natural gas volumes received under percentage of proceeds contracts due to lower commodity prices. NGL and natural gas volumes received under percentage of proceeds contracts were 19,000 boepd in 2023, compared with 10,000 boepd in 2022, due to lower realized NGL and natural gas prices increasing volumes received as consideration for gas processing fees. We added a fourth operated rig in July 2022 and drilled 118 wells and brought 113 wells on production in 2023, bringing the total operated production wells to 1,757 at December 31, 2023. During 2024, we plan to operate four rigs.

•In the Gulf of Mexico, net production averaged 31,000 boepd in 2023 (2022: 31,000 boepd). In July 2023, the Pickerel-1 exploration well (Hess 100%) located in Mississippi Canyon Block 727 completed drilling operations and encountered approximately 90 feet of net pay in high quality, oil bearing, Miocene age reservoir. The well will be a tie-back to the Tubular Bells production facility with first oil expected in mid-2024. In the fourth quarter of 2023, we were the high bidder on 20 leases in the U.S. Department of Interior’s Lease Sale 261 for $88 million and we expect to be awarded these leases in the first quarter of 2024. We also spud the Hess operated Black Pearl development well (Hess 25%) in the fourth quarter of 2023. The well is planned as a tie-back to the Stampede production facility. In 2024, we plan to participate in two wells.

•At the Stabroek Block (Hess 30%), offshore Guyana, net production totaled 115,000 bopd in 2023 (2022: 78,000 bopd). The Liza Unity FPSO, which commenced production in February 2022, reached its initial production capacity of approximately 220,000 gross bopd in July 2022, and increased its production capacity to approximately 250,000 bopd in the third quarter of 2023. Further production optimization work is planned in 2024. The third development, Payara, began producing oil in November 2023 from the Prosperity FPSO and reached its initial production capacity of approximately 220,000 gross bopd in January 2024. In 2023, we sold 37 cargos of crude oil from Guyana compared with 26 cargos in 2022.

Pursuant to the contractual arrangements of the petroleum agreement, a portion of gross production from the block, separate from the joint venture partners’ (Co-Venturers) cost oil and profit oil entitlement, is used to satisfy the Co-Venturers’ income tax liability. This portion of gross production, referred to as tax barrels, is recognized as Co-Venturer production volumes and estimated proved reserves. Net production from Guyana in 2023 included 14,000 bopd of tax barrels (2022: 7,000 bopd; 2021: 0 bopd).

A gas to energy project is underway to construct a 130-mile pipeline network and associated infrastructure in order to transport approximately 50 million standard cubic feet of natural gas per day from the Liza Field to a 300 megawatt onshore power plant, which is expected to be constructed and operated by the Government of Guyana. ExxonMobil Guyana Ltd. expects to complete pipeline construction and field hook-up by the end of 2024.

At the Kaieteur Block, offshore Guyana, we relinquished our 20% participating interest, subject to government approval, and recognized exploration expense of $9 million in 2023.

•In the Gulf of Thailand, net production from Block A‑18 of the JDA averaged 36,000 boepd in 2023 (2022: 38,000 boepd), including contribution from unitized acreage in Malaysia, while net production from North Malay Basin averaged 30,000 boepd in 2023 (2022: 26,000 boepd). During 2023, we drilled seven production wells at the JDA and nine production wells at North Malay Basin, and we plan to continue development drilling in 2024.

•In Canada, offshore Newfoundland (Hess 25%), the operator completed drilling of the Ephesus exploration well in June 2023. The well did not encounter commercial quantities of hydrocarbons and well costs incurred of $34 million were recorded to exploration expense in 2023.

The following is an update of significant Midstream activities during 2023:

•Hess Midstream completed two underwritten public equity offerings of an aggregate of approximately 24.3 million Class A shares held by affiliates of Hess and GIP. As a result of these transactions, Hess received net proceeds of $167 million.

•HESM Opco, a consolidated subsidiary of Hess Midstream LP, repurchased an aggregate of approximately 13.6 million HESM Opco Class B units held by affiliates of Hess and GIP in multiple transactions for total proceeds of $400 million, financed by HESM Opco’s revolving credit facility, of which Hess received proceeds of $188 million.

Liquidity and Capital and Exploratory Expenditures

At December 31, 2023, cash and cash equivalents were $1,688 million (2022: $2,486 million) and consolidated debt was $8,613 million (2022: $8,281 million), which includes Hess Midstream debt that is nonrecourse to Hess Corporation of $3,211 million at December 31, 2023 (2022: $2,886 million).

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


	2023		2022		2021
E&P Capital and Exploratory Expenditures:
United States
North Dakota	$	1,138	$	807	$	522
Offshore and other	290		224		103
Total United States	1,428		1,031		625
Guyana	2,518		1,345		1,016
Malaysia and JDA	189		275		154
Other (a)	41		70		34
E&P Capital and Exploratory Expenditures	$	4,176	$	2,721	$	1,829


Exploration Expenses Charged to Income Included Above:
United States	$	106	$	107	$	90
International	37		25		41
Total Exploration Expenses Charged to Income included above	$	143	$	132	$	131


Midstream Capital Expenditures:
Midstream Capital Expenditures	$	246	$	232	$	183

(a)Other includes our interests in Libya (sold in November 2022) and Denmark (sold in August 2021), and certain non-producing countries.

Our E&P capital and exploratory expenditures are projected to be approximately $4.2 billion in 2024, compared with $4.2 billion in 2023. Capital investment for our Midstream operations is expected to be in the range of $250 million to $275 million in 2024, compared with $246 million in 2023.

Consolidated Results of Operations

Results by Segment:

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


	2023		2022		2021

	(In millions, except per share amounts)
Net Income Attributable to Hess Corporation:
Exploration and Production	$	1,601	$	2,396	$	770
Midstream	252		269		286
Corporate, Interest and Other	(471)		(569)		(497)
Total	$	1,382	$	2,096	$	559
Net Income Attributable to Hess Corporation Per Common Share:
Basic	$	4.52	$	6.80	$	1.82
Diluted	$	4.49	$	6.77	$	1.81

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, on an after-tax basis, items of income (expense) that are included in net income and affect comparability of earnings between periods. The items in the table below are explained on pages 39 through 41.


	2023		2022		2021

	(In millions)
Items Affecting Comparability of Earnings Between Periods, After Income Taxes:
Exploration and Production	$	(101)	$	22	$	(118)
Midstream	—		—		—
Corporate, Interest and Other	(69)		(102)		—
Total	$	(170)	$	(80)	$	(118)

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 57. The items in the table below are explained on pages 39 through 41.


	Before Income Taxes
	2023		2022		2021

	(In millions)
Gains on asset sales, net	$	—	$	98	$	29
Other, net	(17)		—		—


Exploration expenses, including dry holes and lease impairment	(52)		—		—
General and administrative expenses	(52)		(124)		—
Impairment and other	(82)		(54)		(147)
Total Items Affecting Comparability of Earnings Between Periods, Pre-Tax	$	(203)	$	(80)	$	(118)

Reconciliations of GAAP and Non-GAAP Measures:

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


	2023		2022		2021

	(In millions)
Adjusted Net Income Attributable to Hess Corporation:
Net income attributable to Hess Corporation	$	1,382	$	2,096	$	559
Less: Total items affecting comparability of earnings between periods, after-tax	(170)		(80)		(118)
Adjusted Net Income Attributable to Hess Corporation	$	1,552	$	2,176	$	677

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:


	2023		2022		2021

	(In millions)
Net cash provided by (used in) operating activities before changes in operating assets and liabilities:
Net cash provided by (used in) operating activities	$	3,942	$	3,944	$	2,890
Changes in operating assets and liabilities	552		1,177		101
Net cash provided by (used in) operating activities before changes in operating assets and liabilities	$	4,494	$	5,121	$	2,991

Adjusted net income attributable to Hess Corporation is a non-GAAP financial measure, which we define as reported net income attributable to Hess Corporation excluding items identified as affecting comparability of earnings between periods, which are summarized on pages 39 through 41. Management uses adjusted net income 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 GAAP net income and net cash provided by (used in) operating activities.

Comparison of Results

Exploration and Production

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


	2023		2022		2021

	(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues	$	10,500	$	11,324	$	7,473
Gains on asset sales, net	—		76		29
Other, net	50		102		64
Total revenues and non-operating income	10,550		11,502		7,566
Costs and Expenses
Marketing, including purchased oil and gas	2,809		3,394		2,119
Operating costs and expenses	1,479		1,186		965
Production and severance taxes	216		255		172
Midstream tariffs	1,245		1,193		1,094
Exploration expenses, including dry holes and lease impairment	317		208		162
General and administrative expenses	254		224		191
Depreciation, depletion and amortization	1,852		1,520		1,361
Impairment and other	82		54		147
Total costs and expenses	8,254		8,034		6,211
Results of Operations Before Income Taxes	2,296		3,468		1,355
Provision for income taxes	695		1,072		585
Net Income Attributable to Hess Corporation	$	1,601	$	2,396	$	770

Excluding the E&P items affecting comparability of earnings between periods in the table on page 39, 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, DD&A expense, exploration expenses and income taxes, as discussed below.

Selling Prices: Average worldwide realized crude oil selling prices, including hedging, were 11% lower in 2023 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 2023 by 41% and worldwide natural gas prices decreased in 2023 by 23%, compared with the prior year. In total, lower realized selling prices reduced after-tax results by approximately $1,560 million, compared with 2022. Our average selling prices were as follows:


	2023		2022		2021
Average Selling Prices (a)
Crude Oil – Per Barrel (Including Hedging)
United States
North Dakota	$	70.44	$	81.06	$	55.57
Offshore	72.06		81.38		60.09
Total United States	70.80		81.14		56.64
Guyana	80.72		89.86		68.57
Malaysia and JDA	75.51		89.77		71.00
Other (b)	—		93.67		66.39
Worldwide	75.97		85.76		60.08

Crude Oil – Per Barrel (Excluding Hedging)
United States
North Dakota	$	73.80	$	91.26	$	59.90
Offshore	75.39		91.51		64.77
Total United States	74.15		91.32		61.05
Guyana	82.20		96.52		71.07
Malaysia and JDA	75.51		89.77		71.00
Other (b)	—		101.92		69.25
Worldwide	78.29		94.15		63.90

Natural Gas Liquids – Per Barrel
United States
North Dakota	$	20.77	$	35.09	$	30.74
Offshore	20.87		35.24		26.40
Worldwide	20.77		35.09		30.40

Natural Gas – Per Mcf
United States
North Dakota	$	1.68	$	5.50	$	4.08
Offshore	2.16		6.21		3.25
Total United States	1.76		5.66		3.82
Malaysia and JDA	5.95		5.62		5.15
Other (b)	—		5.93		3.40
Worldwide	4.32		5.64		4.60

(a)Selling prices in the United States and Guyana are adjusted for certain processing and distribution fees included in Marketing expenses. Excluding these fees worldwide selling prices for 2023 would be $79.30 per barrel for crude oil (including hedging) (2022: $89.50; 2021: $64.25), $81.62 per barrel for crude oil (excluding hedging) (2022: $97.89; 2021: $68.07), $21.01 per barrel for NGL (2022: $35.44; 2021: $30.61) and $4.47 per mcf for natural gas (2022: $5.76; 2021: $4.71).

(b)Other includes our interests in Libya (sold in November 2022) and Denmark (sold in August 2021).

Crude oil hedging activities in 2023 were a net loss of $190 million before and after income taxes, and a net loss of $585 million before and after income taxes in 2022.

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


	2023	2022	2021

	(In thousands)
Crude Oil – Barrels
United States
North Dakota	83	75	80
Offshore	22	22	29
Total United States	105	97	109
Guyana	115	78	30