Hess (HES) 10-K 26 Feb 24 2023 FY Annual report Financial data

Cover

Cover - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Jan. 31, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Current Fiscal Year End Date	--12-31
Document Period End Date	Dec. 31, 2023
Document Transition Report	false
Entity File Number	1-1204
Entity Registrant Name	Hess Corporation
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	13-4921002
Entity Address, Address Line One	1185 AVENUE OF THE AMERICAS,
Entity Address, City or Town	NEW YORK,
Entity Address, State or Province	NY
Entity Address, Postal Zip Code	10036
City Area Code	212
Local Phone Number	997-8500
Title of 12(b) Security	Common Stock (par value $1.00)
Trading Symbol	HES
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Public Float			$ 37,598
Entity Common Stock, Shares Outstanding (in shares)		307,152,064
Documents Incorporated by Reference	Part III is incorporated by reference from the Proxy Statement for the 2024 annual meeting of stockholders.
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Entity Central Index Key	0000004447

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2023
Cover [Abstract]
Auditor Name	Ernst & Young LLP
Auditor Location	New York, New York
Auditor Firm ID	42

Consolidated Balance Sheet

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Current Assets:
Cash and cash equivalents	$ 1,688	$ 2,486
Accounts receivable:
From contracts with customers	1,180	1,041
Joint venture and other	150	121
Inventories	304	217
Other current assets	108	66
Total current assets	3,430	3,931
Property, plant and equipment:
Total — at cost	36,771	32,592
Less: Reserves for depreciation, depletion, amortization and lease impairment	19,339	17,494
Property, Plant and Equipment — Net	17,432	15,098
Operating lease right-of-use assets — net	720	570
Finance lease right-of-use assets — net	108	126
Post-retirement benefit assets	685	648
Goodwill	360	360
Deferred income taxes	320	133
Other assets	952	829
Total Assets	24,007	21,695
Current Liabilities:
Accounts payable	402	285
Accrued liabilities	2,102	1,840
Taxes payable	85	47
Current portion of long-term debt	311	3
Current portion of operating and finance lease obligations	370	221
Total current liabilities	3,270	2,396
Long-term debt	8,302	8,278
Long-term operating lease obligations	459	469
Long-term finance lease obligations	156	179
Deferred income taxes	608	418
Asset retirement obligations	1,186	1,034
Other liabilities and deferred credits	424	425
Total Liabilities	14,405	13,199
Hess Corporation stockholders’ equity:
Common stock, par value $1.00; Authorized 600,000,000 shares. Issued 307,158,272 shares (2022: 306,176,864)	307	306
Capital in excess of par value	6,495	6,206
Retained earnings	2,318	1,474
Accumulated other comprehensive income (loss)	(134)	(131)
Total Hess Corporation stockholders’ equity	8,986	7,855
Noncontrolling interests	616	641
Total equity	9,602	8,496
Total Liabilities and Equity	$ 24,007	$ 21,695

Consolidated Balance Sheet (Par

Consolidated Balance Sheet (Parenthetical) - $ / shares	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 1	$ 1
Common stock, shares authorized (in shares)	600,000,000	600,000,000
Common stock, shares issued (in shares)	307,158,272	306,176,864

Statement of Consolidated Incom

Statement of Consolidated Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues and Non-Operating Income
Sales and other operating revenues	$ 10,511	$ 11,324	$ 7,473
Gains on asset sales, net	2	101	29
Other, net	132	145	81
Total revenues and non-operating income	10,645	11,570	7,583
Costs and Expenses
Marketing, including purchased oil and gas	2,732	3,328	2,034
Operating costs and expenses	1,776	1,452	1,229
Production and severance taxes	216	255	172
Exploration expenses, including dry holes and lease impairment	317	208	162
General and administrative expenses	527	531	340
Interest expense	478	493	481
Depreciation, depletion and amortization	2,046	1,703	1,528
Impairment and other	82	54	147
Total costs and expenses	8,174	8,024	6,093
Income Before Income Taxes	2,471	3,546	1,490
Provision for income taxes	733	1,099	600
Net Income	1,738	2,447	890
Less: Net income attributable to noncontrolling interests	356	351	331
Net Income Attributable to Hess Corporation	$ 1,382	$ 2,096	$ 559
Net Income Attributable to Hess Corporation Per Common Share:
Basic (in dollars per share)	$ 4.52	$ 6.80	$ 1.82
Diluted (in dollars per share)	$ 4.49	$ 6.77	$ 1.81
Weighted Average Number of Common Shares Outstanding:
Shares outstanding – Basic (in shares)	305.9	308.1	307.4
Weighted Average Number of Common Shares Outstanding (Diluted) (in shares)	307.6	309.6	309.3
Common Stock Dividends Per Share (in dollars per share)	$ 1.75	$ 1.50	$ 1

Statement of Consolidated Compr

Statement of Consolidated Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Net Income	$ 1,738	$ 2,447	$ 890
Derivatives designated as cash flow hedges
Effect of hedge (gains) losses reclassified to income	190	585	243
Income taxes on effect of hedge (gains) losses reclassified to income	0	0	0
Net effect of hedge (gains) losses reclassified to income	190	585	243
Change in fair value of cash flow hedges	(190)	(517)	(315)
Income taxes on change in fair value of cash flow hedges	0	0	0
Net change in fair value of cash flow hedges	(190)	(517)	(315)
Change in derivatives designated as cash flow hedges, after taxes	0	68	(72)
Pension and other postretirement plans
(Increase) reduction in unrecognized actuarial losses	(22)	201	355
Income taxes on actuarial changes in plan liabilities	2	(5)	0
(Increase) reduction in unrecognized actuarial losses, net	(20)	196	355
Amortization of net actuarial losses	18	12	66
Income taxes on amortization of net actuarial losses	(1)	(1)	0
Net effect of amortization of net actuarial losses	17	11	66
Change in pension and other postretirement plans, after taxes	(3)	207	421
Other Comprehensive Income (Loss)	(3)	275	349
Comprehensive Income	1,735	2,722	1,239
Less: Comprehensive income attributable to noncontrolling interests	356	351	331
Comprehensive Income Attributable to Hess Corporation	$ 1,379	$ 2,371	$ 908

Statement of Consolidated Cash

Statement of Consolidated Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash Flows From Operating Activities
Net income	$ 1,738	$ 2,447	$ 890
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
(Gains) on asset sales, net	(2)	(101)	(29)
Depreciation, depletion and amortization	2,046	1,703	1,528
Impairment and other	82	54	147
Exploratory dry hole costs	147	56	11
Exploration lease impairment	27	20	20
Pension settlement loss	17	2	9
Stock compensation expense	87	83	77
Noncash (gains) losses on commodity derivatives, net	156	548	216
Provision (benefit) for deferred income taxes and other tax accruals	196	309	122
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable	(324)	(301)	(748)
(Increase) decrease in inventories	(87)	2	135
Increase (decrease) in accounts payable and accrued liabilities	253	50	241
Increase (decrease) in taxes payable	38	(465)	447
Changes in other operating assets and liabilities	(432)	(463)	(176)
Net cash provided by (used in) operating activities	3,942	3,944	2,890
Cash Flows From Investing Activities
Additions to property, plant and equipment – E&P	(3,884)	(2,487)	(1,584)
Additions to property, plant and equipment – Midstream	(224)	(238)	(163)
Proceeds from asset sales, net of cash sold	3	178	427
Other, net	(8)	(8)	(5)
Net cash provided by (used in) investing activities	(4,113)	(2,555)	(1,325)
Cash Flows From Financing Activities
Net borrowings (repayments) of debt with maturities of 90 days or less	322	(86)	(80)
Debt with maturities of greater than 90 days – Borrowings	0	420	750
Debt with maturities of greater than 90 days – Repayments	(3)	(510)	(510)
Cash dividends paid	(539)	(465)	(311)
Common stock acquired and retired	(20)	(630)	0
Proceeds from sale of Class A shares of Hess Midstream LP	167	146	178
Noncontrolling interests, net	(550)	(510)	(664)
Employee stock options exercised	10	52	77
Payments on finance lease obligations	(10)	(9)	(10)
Other, net	(4)	(24)	(21)
Net cash provided by (used in) financing activities	(627)	(1,616)	(591)
Net Increase (Decrease) in Cash and Cash Equivalents	(798)	(227)	974
Cash and Cash Equivalents at Beginning of Year	2,486	2,713	1,739
Cash and Cash Equivalents at End of Year	$ 1,688	$ 2,486	$ 2,713

Statement of Consolidated Equit

Statement of Consolidated Equity - USD ($) $ in Millions	Total	Common Stock	Capital in Excess of Par	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Total Hess Stockholders’ Equity	Noncontrolling Interests
Balance at Dec. 31, 2020	$ 6,335	$ 307	$ 5,684	$ 130	$ (755)	$ 5,366	$ 969
Net income	890			559		559	331
Other comprehensive income (loss)	349				349	349
Share-based compensation	156	3	153			156
Dividends on common stock	(310)			(310)		(310)
Sale of Class A shares of Hess Midstream LP	255		152			152	103
Repurchase of Class B units of Hess Midstream Operations LP	(362)		28			28	(390)
Noncontrolling interests, net	(287)						(287)
Balance at Dec. 31, 2021	7,026	310	6,017	379	(406)	6,300	726
Net income	2,447			2,096		2,096	351
Other comprehensive income (loss)	275				275	275
Share-based compensation	137	1	136			137
Dividends on common stock	(465)			(465)		(465)
Sale of Class A shares of Hess Midstream LP	218		130			130	88
Repurchase of Class B units of Hess Midstream Operations LP	(183)		32			32	(215)
Common stock acquired and retired	(650)	(5)	(109)	(536)		(650)
Noncontrolling interests, net	(309)						(309)
Balance at Dec. 31, 2022	8,496	306	6,206	1,474	(131)	7,855	641
Net income	1,738			1,382		1,382	356
Other comprehensive income (loss)	(3)				(3)	(3)
Share-based compensation	101	1	100			101
Dividends on common stock	(538)			(538)		(538)
Sale of Class A shares of Hess Midstream LP	333		158			158	175
Repurchase of Class B units of Hess Midstream Operations LP	(189)		31			31	(220)
Noncontrolling interests, net	(336)						(336)
Balance at Dec. 31, 2023	$ 9,602	$ 307	$ 6,495	$ 2,318	$ (134)	$ 8,986	$ 616

Nature of Operations, Basis of

Nature of Operations, Basis of Presentation and Summary of Accounting Policies	12 Months Ended
	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations, Basis of Presentation and Summary of Accounting Policies	1. Nature of Operations, Basis of Presentation and Summary of Accounting Policies Unless the context indicates otherwise, references to “Hess”, “the Corporation”, “Registrant”, “we”, “us” and “our” refer to the consolidated business operations of Hess Corporation and its affiliates. Nature of Business: Hess Corporation, incorporated in the State of Delaware in 1920, is a global 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. Our Midstream operating segment, which includes Hess Corporation’s approximate 38% consolidated ownership interest in Hess Midstream LP at December 31, 2023 (see Note 4, Hess Midstream LP ) 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. On October 22, 2023, we entered into an Agreement and Plan of Merger (the Merger Agreement) with Chevron Corporation (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. Basis of Presentation and Principles of Consolidation: The consolidated financial statements include the accounts of Hess Corporation and entities in which we own more than a 50% voting interest. We consolidate Hess Midstream LP, a variable interest entity, based on our conclusion that we have the power through Hess Corporation’s approximate 38% consolidated ownership interest in Hess Midstream LP to direct those activities that most significantly impact the economic performance of Hess Midstream LP , and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to Hess Midstream LP . Our undivided interests in unincorporated oil and gas E&P ventures are proportionately consolidated. Investments in affiliated companies, 20% to 50% owned and where we have the ability to influence the operating or financial decisions of the affiliate, are accounted for using the equity method. Estimates and Assumptions: In preparing financial statements in conformity with GAAP, management makes estimates and assumptions that affect the reported amounts of assets and liabilities in the Consolidated Balance Sheet and revenues and expenses in the Statement of Consolidated Income . Actual results could differ from those estimates. Estimates made by management include oil and gas reserves, asset and other valuations, depreciable lives, post-retirement liabilities, legal and environmental obligations, asset retirement obligations and income taxes. Revenue Recognition: Exploration and Production The E&P segment recognizes revenue from the sale of crude oil, NGL, and natural gas as performance obligations under contracts with customers are satisfied. Our responsibilities to deliver each unit of quantity of crude oil, NGL, and natural gas under these contracts represent separate, distinct performance obligations. These performance obligations are satisfied at the point in time control of each unit of quantity transfers to the customer. Generally, the control of each unit of quantity transfers to the customer upon the transfer of legal title at the point of physical delivery. Pricing is variable and is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials. For long-term international natural gas contracts with ship-or-pay provisions, our obligation to stand-ready to provide a minimum volume over each commitment period represents separate, distinct performance obligations. Penalties owed against future deliveries of natural gas due to delivery of volumes below minimum delivery commitments are recognized as reductions to revenue in the commitment period when the shortfall occurs. Long-term international natural gas contracts may also contain take-or-pay provisions whereby the customer is required to pay for volumes not taken that are below minimum volume commitments, but the customer has certain make-up rights to receive shortfall volumes in subsequent periods. Shortfall payments received from customers when volumes purchased are below the minimum volume commitment are deferred upon receipt as a contract liability. Revenue is recognized at the earlier of when we deliver the make-up volumes in subsequent periods or when it becomes remote that the customer will exercise their make-up rights. Certain crude oil, NGL, and natural gas volumes are purchased by Hess from third parties, including working interest partners and royalty owners in certain Hess-operated properties, before they are sold to customers. Where control over the crude oil, NGL, or natural gas transfers to Hess before the volumes are transferred to the customer, revenue and the associated cost of purchased volumes are presented on a gross basis in the Statement of Consolidated Income within Sales and other operating revenues and Marketing, including purchased oil and gas , respectively. Where control of crude oil, NGL, or natural gas is not transferred to Hess, revenue is presented net of the associated cost of purchased volumes within Sales and other operating revenues in the S tatement of Consolidated Income . Contract Duration and Pricing: Contracts with customers for the sale of U.S. crude oil, NGL, and natural gas primarily include those contracts that involve the short-term sale of volumes during a specified period, and those contracts that automatically renew on a periodic basis until either party cancels. We have certain long-term contracts with customers for the sale of U.S. natural gas and NGL that have remaining durations ranging from one Contracts with customers for the sale of international crude oil involve the short-term sale of volumes during a specified period. Pricing is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials, shortly after control of the volumes transfers to the customer. International contracts with customers for the sale of natural gas are in the form of natural gas sales agreements with government entities that have durations that are aligned with the durations of production sharing contracts or other contractual arrangements with host governments. Pricing for our natural gas sales agreements in North Malay Basin and Block A-18 of JDA are determined using contractual formulas that are based on the price of alternative fuels as obtained from price indices and other factors. Contract Balances: Our right to receive or collect payment from the customer is aligned with the timing of revenue recognition except in situations when we receive shortfall payments under contracts with take-or-pay provisions with customer make-up rights. Generally, we receive payments from customers on a monthly basis, shortly after the physical delivery of the crude oil, NGL, or natural gas. At December 31, 2023, there were no contract liabilities. At December 31, 2022, there were contract liabilities of $24 million resulting from a take-or-pay deficiency payment received in 2021 that was subject to a make-up period expiring in December 2023. During the year ended December 31, 2023, revenue of $24 million was recognized within Sales and other operating revenues that was included in the contract liability balance at December 31, 2022. At December 31, 2023 and 2022, there were no contract assets. Transaction Price Allocated to Remaining Performance Obligations: The transaction price allocated to our wholly unsatisfied performance obligations on uncompleted contracts is variable. Further, many of our contracts with customers have durations of less than twelve months. Accordingly, we have elected under the provisions of Accounting Standards Codification (ASC) 606, Revenues from Contracts with Customers, the exemption from disclosure of revenue recognizable in future periods as these performance obligations are satisfied. Sales-based Taxes: We exclude sales-based taxes that are collected from customers from the transaction price in our contracts with customers. Accordingly, revenue from contracts with customers is net of sales-based taxes that are collected from customers and remitted to taxing authorities. Revenue from Non-customers: In Guyana, the joint venture partners (Co-Venturers) to the Stabroek Block petroleum agreement are subject to the income tax laws of Guyana and remain primarily liable for income taxes due on the results of operations, resulting in recognition of income tax expense. Pursuant to the contractual arrangements of the petroleum agreement, a portion of gross production from the block, separate from the 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 included in our reported production volumes and is recognized as sales revenue from non-customers. Midstream 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 LP 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 ten 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 Midstream segment ’ s responsibility to provide each service for each year under each of the commercial agreements are considered separate, distinct performance obligations. Revenue is recognized over-time for each performance obligation as services are rendered using the output method, measured using the amount of volumes serviced during the period. The commercial agreements contain minimum volume commitments which fluctuate based on nominations covering substantially all of our E&P segment's existing and future owned or controlled production in the Bakken and projected third-party volumes owned or controlled by our 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. As the minimum volume commitments are subject to fluctuation, and these commercial agreements contain fee inflation escalators and fee recalculation mechanisms, substantially all of the transaction price is variable at inception of each of the commercial agreements. The Midstream segment has elected the practical expedient under the provisions of Accounting Standards Codification (ASC) 606 , Revenue from Contracts with Customers to recognize revenue in the amount it is entitled to invoice. If the volumes delivered are less than the applicable minimum volume commitments under the commercial agreements during any quarter, the applicable Hess subsidiary is obligated to pay a shortfall fee equal to the volume deficiency multiplied by the related gathering, processing and/or terminaling fee. The Midstream segment ’ s responsibility to stand-ready to service a minimum volume over each quarterly commitment period represents a separate, distinct performance obligation. During the initial term of each commercial agreement, volume deficiencies are measured quarterly and recognized as revenue in the same period, as 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, calculated in barrels or Mcf, as applicable, 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. Unused credits will be recognized as revenue when it becomes remote that such credits will be utilized. 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. All revenues, receivables, and contract balances arising from the commercial agreements between the Midstream segment and the Hess subsidiaries that are the counterparty to the commercial agreements are eliminated upon consolidation. Exploration and Development Costs: E&P activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized. The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of a project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors, firm plans for additional drilling and other factors. Depreciation, Depletion and Amortization: We record depletion expense for acquisition costs of proved properties using the units of production method over proved oil and gas reserves. Depreciation and depletion expense for oil and gas production facilities and wells is calculated using the units of production method over proved developed oil and gas reserves. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors. Depreciation of all other plant and equipment is determined on the straight-line method based on estimated useful lives. Capitalized Interest: Interest from external borrowings is capitalized on material projects using the weighted average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at first production from the field. Capitalized interest is depreciated in the same manner as the depreciation of the underlying assets. Impairment of Long‑lived Assets: We review long‑lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts of the long-lived assets are not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is measured based on the estimated fair value of the assets generally determined by discounting anticipated future net cash flows, an income valuation approach, or by a market‑based valuation approach, which are Level 3 fair value measurements. In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a projected amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairment will generally differ from those used in the standardized measure of discounted future net cash flows reported in Supplementary Oil and Gas Data , since the standardized measure requires the use of historical twelve-month average prices. Impairment of Goodwill: Goodwill is tested for impairment annually on October 1 st or when events or circumstances indicate it is more likely than not that the fair value of the reporting unit is less than its carrying value, including goodwill. If the fair value of the reporting unit exceeds its carrying value, goodwill is not impaired. If the carrying value of the reporting unit exceeds its fair value, an impairment loss would be recorded for the excess of the carrying value over fair value, limited by the amount of goodwill allocated to the reporting unit. At December 31, 2023, goodwill of $360 million relates to the Midstream operating segment. Cash and Cash Equivalents: Cash and cash equivalents primarily comprises cash on hand and on deposit, as well as highly liquid investments that are readily convertible into cash and have maturities of three months or less when acquired. Inventories: Produced and unsold crude oil and NGL are valued at the lower of cost or net realizable value. Cost is determined using the average cost of production plus any transport cost incurred in bringing the volumes to their present location. Materials and supplies are valued at cost. Obsolete or surplus materials identified during periodic reviews are valued at the lower of cost or estimated net realizable value. Leases: We determine if an arrangement is a lease at inception by evaluating whether the contract conveys the right to control an identified asset during the period of use. ROU assets represent our right to use an identified asset for the lease term and lease obligations represent our obligation to make payments as set forth in the lease arrangement. ROU assets and lease liabilities are recognized in the Consolidated Balance Sheet as operating leases or finance leases at the commencement date based on the present value of the minimum lease payments over the lease term. Where the implicit discount rate in a lease is not readily determinable, we use our incremental borrowing rate based on information available at the commencement date for determining the present value of the minimum lease payments. The lease term used in measurement of our lease obligations includes options to extend or terminate the lease when, in our judgment, it is reasonably certain that we will exercise that option. Variable lease payments that depend on an index or a rate are included in the measurement of lease obligations using the index or rate at the commencement date. Variable lease payments that vary because of changes in facts or circumstances after the commencement date of the lease are not included in the minimum lease payments used to measure lease obligations. We have agreements that include financial obligations for lease and nonlease components. For purposes of measuring lease obligations, we have elected not to separate nonlease components from lease components for the following classes of assets: drilling rigs, office space, offshore vessels, and aircraft. We apply a portfolio approach to account for operating lease ROU assets and liabilities for certain vehicles, railcars, field equipment and office equipment leases. Finance lease cost is recognized as amortization of the ROU asset and interest expense on the lease liability. Operating lease cost is generally recognized on a straight-line basis. Operating lease costs for drilling rigs used to drill development wells and successful exploration wells are capitalized. Operating lease cost for other ROU assets used in oil and gas producing activities are either capitalized or expensed based on the nature of operation for which the ROU asset is utilized. Leases with an initial term of 12 months or less are not recorded on the balance sheet as permitted under ASC 842, Leases . We recognize lease cost for short-term leases on a straight-line basis over the term of the lease. Some of our leases with initial terms of 12 months or less include one or more options to renew. The renewal option is at our sole discretion and is not included in the lease term for measurement of the lease obligation unless we are reasonably certain at the commencement date of the lease, to renew the lease. Income Taxes: Deferred income taxes are determined using the liability method. We have net operating loss carryforwards or credit carryforwards in multiple jurisdictions and have recognized deferred tax assets for those losses and credits. Additionally, we have deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If, when tested under the relevant accounting standards, it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is established to reduce the deferred tax assets to the amount that is expected to be realized. The accounting standards require the evaluation of all available positive and negative evidence giving weight based on the evidence’s relative objectivity. In evaluating potential sources of positive evidence, we consider the reversal of taxable temporary differences, taxable income in carryback and carryforward periods, the availability of tax planning strategies, the existence of appreciated assets, estimates of future taxable income, and other factors. In evaluating potential sources of negative evidence, we consider a cumulative loss in recent years, any history of operating losses or tax credit carryforwards expiring unused, losses expected in early future years, unsettled circumstances that, if unfavorably resolved, would adversely affect future operations and profit levels on a continuing basis in future years, and any carryback or carryforward period so brief that a significant deductible temporary difference expected to reverse in a single year would limit realization of tax benefits. We assign cumulative historical losses significant weight in the evaluation of realizability relative to more subjective evidence such as forecasts of future income. In addition, we recognize the financial statement effect of a tax position only when management believes that it is more likely than not, that based on the technical merits, the position will be sustained upon examination. We are not indefinitely reinvested with respect to the book in excess of tax basis in the investment in our foreign subsidiaries. Because of U.S. tax reform we expect that the future reversal of such temporary differences will occur free of material taxation. We classify interest and penalties associated with uncertain tax positions as income tax expense. We account for the U.S. tax effect of global intangible low-taxed income earned by foreign subsidiaries in the period that such income is earned. We utilize the aggregate approach for releasing disproportionate income tax effects from Accumulated other comprehensive income (loss) . Asset Retirement Obligations: We have legal obligations to remove and dismantle long‑lived assets and to restore land or the seabed at certain E&P locations. We initially recognize a liability for the fair value of legally required asset retirement obligations in the period in which the retirement obligations are incurred and capitalize the associated asset retirement costs as part of the carrying amount of the long‑lived assets. In subsequent periods, the liability is accreted over the useful life of the related asset, and the capitalized asset retirement costs are depreciated over proved developed oil and gas reserves using the units of production method or the useful life of the related asset. Fair value is determined by applying a credit adjusted risk-free rate to the undiscounted expected future abandonment expenditures. Changes in estimates prior to settlement result in adjustments to both the liability and related asset values, unless the field has ceased production, in which case changes are recognized in the Statement of Consolidated Income . We measure asset retirement obligations based on the requirements of existing laws and regulations in accordance with ASC 410-20, Asset Retirement Obligations . Laws and regulations associated with the scope and timing for the abandonment of oil and gas wells, facilities and equipment could change which could increase the cost of our abandonment obligations. In addition, we may be required to assume abandonment obligations for certain divested assets in the event the current or future owners of facilities previously owned by us are unable to perform, whether due to bankruptcy or otherwise. Retirement Plans: We recognize the funded status of defined benefit postretirement plans in the Consolidated Balance Sheet . The funded status is measured as the difference between the fair value of plan assets and the projected benefit obligation. We recognize the net changes in the funded status of these plans as a component of Other Comprehensive Income (Loss) in the year in which such changes occur. Actuarial gains and losses in excess of 10% of the greater of the benefit obligation or the market value of plan assets are amortized over the average remaining service period of active employees or the remaining average expected life if a plan’s participants are predominantly inactive. Derivatives: We utilize derivative instruments for financial risk management activities. In these activities, we may use futures, forwards, options and swaps, individually or in combination, to mitigate our exposure to fluctuations in prices of crude oil and natural gas, as well as changes in interest and foreign currency exchange rates. All derivative instruments are recorded at fair value in the Consolidated Balance Sheet . Our policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not designated as hedges are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges), or hedges of changes in fair value of recognized assets and liabilities or of unrecognized firm commitments (fair value hedges). Changes in fair value of derivatives that are designated as cash flow hedges are recorded as a component of Other Comprehensive Income (Loss) . Amounts included in Accumulated Other Comprehensive Income (Loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged item is recorded as an adjustment to its carrying amount and recognized currently in earnings. Fair Value Measurements: We use various valuation approaches in determining fair value for financial instruments, including the market and income approaches. Our fair value measurements also include non-performance risk and time value of money considerations. Counterparty credit is considered for financial assets, and our credit is considered for financial liabilities. We also record certain nonfinancial assets and liabilities at fair value when required by GAAP. These fair value measurements are recorded in connection with business combinations, qualifying nonmonetary exchanges, the initial recognition of asset retirement obligations and any impairment of long‑lived assets, equity method investments, goodwill or other indefinite-lived intangible assets, such as environmental credits. We determine fair value in accordance with the fair value measurements accounting standard which established a hierarchy for the inputs used to measure fair value based on the source of the inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3), including discounted cash flows and other unobservable data. Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market. Multiple inputs may be used to measure fair value; however, the level assigned to a fair value measurement is based on the lowest significant input level within this fair value hierarchy. Details on the methods and assumptions used to determine the fair values are as follows: Fair value measurements based on Level 1 inputs: Measurements that are most observable are based on quoted prices of identical instruments obtained from the principal markets in which they are traded. Closing prices are both readily available and representative of fair value. Market transactions occur with sufficient frequency and volume to assure liquidity. Fair value measurements based on Level 2 inputs: Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. Measurements based on Level 2 inputs include over-the-counter derivative instruments that are priced on an exchange-traded curve but have contractual terms that are not identical to exchange-traded contracts. Fair value measurements based on Level 3 inputs: Measurements that are least observable are estimated from related market data, determined from sources with little or no market activity for comparable contracts or are positions with longer durations. Fair values determined using discounted cash flows and other unobservable data are also classified as Level 3. Netting of Financial Instruments: We generally enter into master netting arrangements to mitigate legal and counterparty credit risk. Master netting arrangements are generally accepted overarching master contracts that govern all individual transactions with the same counterparty entity as a single legally enforceable agreement. The U.S. Bankruptcy Code provides for the enforcement of certain termination and netting rights under certain types of contracts upon the bankruptcy filing of a counterparty, commonly known as the “safe harbor” provisions. If a master netting arrangement provides for termination and netting upon the counterparty’s bankruptcy, these rights are generally enforceable with respect to “safe harbor” transactions. If these arrangements provide the right of offset and our intent and practice is to offset amounts in the case of such a termination, our policy is to record the fair value of derivative assets and liabilities on a net basis. In the normal course of business, we rely on legal and credit risk mitigation clauses providing for adequate credit assurance as well as close‑o

Inventories

Inventories	12 Months Ended
	Dec. 31, 2023
Inventory Disclosure [Abstract]
Inventories	2. Inventories Inventories at December 31 were as follows: 2023 2022 (In millions) Crude oil and natural gas liquids $ 72 $ 63 Materials and supplies 232 154 Total Inventories $ 304 $ 217

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	3. Property, Plant and Equipment Property, plant and equipment at December 31 were as follows: 2023 2022 (In millions) Exploration and Production Unproved properties $ 103 $ 149 Proved properties 2,660 2,660 Wells, equipment and related facilities 29,159 25,182 31,922 27,991 Midstream 4,819 4,571 Corporate and Other 30 30 Total — at cost 36,771 32,592 Less: Reserves for depreciation, depletion, amortization and lease impairment 19,339 17,494 Property, Plant and Equipment — Net $ 17,432 $ 15,098 Capitalized Exploratory Well Costs : The following table discloses the amount of capitalized exploratory well costs pending determination of proved reserves at December 31 and the changes therein during the respective years: 2023 2022 2021 (In millions) Balance at January 1 $ 886 $ 681 $ 459 Additions to capitalized exploratory well costs pending the determination of proved reserves 257 298 222 Reclassifications to wells, facilities and equipment based on the determination of proved reserves (133) (93) — Capitalized exploratory well costs charged to expense (58) — — Balance at December 31 $ 952 $ 886 $ 681 Number of Wells at December 31 43 43 35 During the three years ended December 31, 2023, additions to capitalized exploratory well costs primarily related to drilling at the Stabroek Block (Hess 30%), offshore Guyana. At December 31, 2023, 36 exploration and appraisal wells on the Stabroek Block, with a total cost of $841 million, were capitalized pending determination of proved reserves. Other additions to capitalized exploratory well costs in 2023 include the Pickerel-1 exploration well (Hess 100%) in the Gulf of Mexico on Mississippi Canyon Block 727. Other additions to capitalized exploratory wells costs in 2022 include the Huron-1 well (Hess 40%) in the Gulf of Mexico, and the Zanderij-1 well on Block 42 (Hess 33%), offshore Suriname. Reclassifications to wells, facilities and equipment based on the determination of proved reserves in 2023 resulted from the sanction of the Uaru Field development, the fifth sanctioned project on the Stabroek Block, and the Pickerel-1 exploration well in the Gulf of Mexico. In 2022, reclassifications to wells, facilities and equipment resulted from the sanction of the Yellowtail Field development, the fourth sanctioned project on the Stabroek Block. Capitalized exploratory well costs charged to expense in 2023 of $58 million primarily relate to the Huron-1 well in the Gulf of Mexico. In the fourth quarter of 2023, we, along with our partners, decided not to appraise the discovery given other available opportunities and the limited time remaining on the leases. The preceding table excludes well costs incurred and expensed during 2023 of $89 million (2022: $56 million; 2021: $11 million). Exploratory well costs capitalized for greater than one year following completion of drilling were $728 million at December 31, 2023, separated by year of completion as follows (in millions): 2022 $ 261 2021 162 2020 8 2019 139 2018 and prior 158 $ 728 Guyana: 87% of the capitalized well costs in excess of one year relate to successful exploration and appraisal wells where hydrocarbons were encountered on the Stabroek Block (Hess 30%). In October 2023, the operator submitted a plan for the Whiptail development project, the sixth development project on the Stabroek Block, to the Government of Guyana for approval. The operator also plans further appraisal drilling on the block and is conducting pre-development planning for additional phases of development. Suriname.: 6% of the capitalized well costs in excess of one year relates to the Zanderij-1 well on Block 42 (Hess 33%). Exploration and appraisal activities are ongoing. JDA: 5% of the capitalized well costs in excess of one year relates to the JDA (Hess 50%) in the Gulf of Thailand, where hydrocarbons were encountered in three successful exploration wells drilled in the western part of Block A-18. The operator has submitted a development plan concept to the regulator to facilitate ongoing commercial negotiations for an extension of the existing gas sales contract to include development of the western part of the block. Malaysia: 2% of the capitalized well costs in excess of one year relates to North Malay Basin (Hess 50%), offshore Peninsular Malaysia, where hydrocarbons were encountered in two successful exploration wells. Pre-development studies are ongoing.

Hess Midstream LP

Hess Midstream LP	12 Months Ended
	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Hess Midstream LP	4. Hess Midstream LP Hess Midstream LP, a variable interest entity, has an "Up-C" organizational structure. We have an approximate 38% consolidated ownership interest at December 31, 2023 in Hess Midstream LP on an as-exchanged basis, primarily through our ownership of Class B units in Hess Midstream Operations LP (HESM Opco), the operating subsidiary of Hess Midstream LP, which are exchangeable into Class A shares of Hess Midstream LP on a one-for-one basis. An affiliate of Global Infrastructure Partners (GIP) owns an approximate 32% consolidated interest in Hess Midstream LP at December 31, 2023, on an as-exchanged basis, primarily through its ownership of Class B units in HESM Opco, and the public owns an approximate 30% consolidated interest in Hess Midstream LP at December 31, 2023, through the ownership of Class A shares of Hess Midstream LP. We have concluded that we are the primary beneficiary of the variable interest entity since we have the power to direct those activities that most significantly impact the economic performance of Hess Midstream LP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to Hess Midstream LP. This conclusion was based on a qualitative analysis that considered Hess Midstream LP’s governance structure, the commercial agreements between Hess Midstream LP and us, and the voting rights established between the members. In 2021, Hess Midstream LP completed two underwritten public equity offerings of an aggregate of approximately 15.5 million Hess Midstream LP Class A shares held by affiliates of Hess and GIP. Hess received an aggregate of $178 million of net proceeds from these transactions. These transactions, in aggregate, resulted in an increase in Capital in excess of par and Noncontrolling interests of $152 million and $103 million, respectively. The aggregate increase to Noncontrolling interests of $103 million is comprised of $26 million resulting from the changes in ownership interests and $77 million from increases to deferred tax assets resulting from step-ups in the tax basis of Hess Midstream LP ’ s investment in 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. The transaction resulted in an increase in Capital in excess of par and a decrease in Noncontrolling interests of $28 million, and an increase in deferred tax assets and Noncontrolling interests of $15 million resulting from an adjustment in the carrying value of Hess Midstream LP ’ s investment in HESM Opco without a corresponding adjustment in the tax basis. The $375 million paid to GIP reduced Noncontrolling interests . In 2022, Hess Midstream LP completed a single underwritten public equity offering of approximately 10.2 million Hess Midstream LP Class A shares held by affiliates of Hess and GIP. Hess received net proceeds of $146 million from the transaction. The transaction resulted in an increase in Capital in excess of par and Noncontrolling interests of $130 million and $88 million, respectively. The increase to Noncontrolling interests of $88 million is comprised of $16 million resulting from the change in ownership interests and $72 million from an increase to deferred tax assets resulting from a step-up in the tax basis of Hess Midstream LP ’ s investment in 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. The transaction resulted in an increase in Capital in excess of par and a decrease in Noncontrolling interests of $32 million, and an increase in deferred tax assets and Noncontrolling interests of $17 million resulting from an adjustment in the carrying value of Hess Midstream LP ’ s investment in HESM Opco without a corresponding adjustment in the tax basis. The $200 million paid to GIP reduced Noncontrolling interests . In May 2023, Hess Midstream LP completed an underwritten public equity offering of approximately 12.8 million Hess Midstream LP Class A shares held by affiliates of Hess and GIP. Hess received $167 million of net proceeds from this transaction. This transaction resulted in an increase in Capital in excess of par and Noncontrolling interests of $158 million and $93 million, respectively. The increase to Noncontrolling interests of $93 million is comprised of $9 million resulting from the change in ownership interests and $84 million from an increase to deferred tax assets resulting from a step-up in the tax basis of Hess Midstream LP ’ s investment in HESM Opco. In August 2023, Hess Midstream LP completed an underwritten public equity offering of 11.5 million Class A shares held by an affiliate of GIP. Hess did not participate in this transaction and did not receive any proceeds. There was no change in Hess’ ownership interest in Hess Midstream LP on a consolidated basis and accordingly, there was no impact to the balance of Noncontrolling interests . However, the transaction did result in an increase to deferred tax assets of $82 million, with the offset recorded to Noncontrolling interests, due to a step-up in the tax basis of Hess Midstream LP ’ s investment in 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. The unit repurchases, in aggregate, resulted in an increase in Capital in excess of par and a decrease in Noncontrolling interests of $31 million, and an increase in deferred tax assets and Noncontrolling interests of $23 million resulting from adjustments in the carrying value of Hess Midstream LP ’ s investment in HESM Opco without corresponding adjustments in the tax basis. The aggregate proceeds paid to GIP of $212 million reduced Noncontrolling interests . Hess participated in all the HESM Opco Class B unit repurchase transactions in 2023 on a 50/50 basis with GIP with the exception of the HESM Opco Class B unit repurchase transaction in November 2023. Hess and GIP received $38 million and $62 million, respectively, of the total proceeds of $100 million. There was no change in Hess’ ownership interest in Hess Midstream LP on a consolidated basis as a result of this transaction and accordingly, there was no impact to the balance of Noncontrolling interests. However, the transaction did result in an increase to deferred tax assets of $7 million, with the offset recorded to Noncontrolling interests , as a result of an adjustment in the carrying value of Hess Midstream LP ’ s investment in HESM Opco without a corresponding adjustment in the tax basis. At December 31, 2023, Hess Midstream LP liabilities totaling $3,385 million (2022: $3,027 million) are on a nonrecourse basis to Hess Corporation, while Hess Midstream LP assets available to settle the obligations of Hess Midstream LP included cash and cash equivalents totaling $5 million (2022: $3 million), property, plant and equipment, net totaling $3,229 million (2022: $3,173 million) and the equity-method investment in Little Missouri 4 (LM4) of $90 million (2022: $94 million). LM4 is a 200 million standard cubic feet per day gas processing plant located south of the Missouri River in McKenzie County, North Dakota, that was constructed as part of a 50/50 joint venture between Hess Midstream LP and Targa Resources Corp. Hess Midstream LP has a natural gas processing agreement with LM4 under which it pays a processing fee and reimburses LM4 for its proportionate share of electricity costs. In 2023, processing fees were $24 million (2022: $21 million; 2021: $28 million) and are included in Operating costs and expenses in the Statement of Consolidated Income .

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2023
Payables and Accruals [Abstract]
Accrued Liabilities	5. Accrued Liabilities The following table provides detail of our accrued liabilities at December 31: 2023 2022 (In millions) Accrued capital expenditures $ 670 $ 499 Accrued operating and marketing expenditures 593 522 Accrued compensation and benefits 193 132 Accrued payments to royalty and working interest owners 178 201 Current portion of asset retirement obligations 160 207 Accrued interest on debt 144 143 Other accruals 164 136 Total Accrued Liabilities $ 2,102 $ 1,840

Leases

Leases	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Leases	6. Leases Operating and finance lease obligations at December 31 included in the Consolidated Balance Sheet were as follows: Operating Leases Finance Leases 2023 2022 2023 2022 (In millions) Right-of-use assets — net (a) $ 720 $ 570 $ 108 $ 126 Lease obligations: Current $ 347 $ 200 $ 23 $ 21 Long-term 459 469 156 179 Total lease obligations $ 806 $ 669 $ 179 $ 200 (a) At December 31, 2023, finance lease ROU assets had a cost of $212 million (2022: $212 million) and accumulated amortization of $104 million (2022: $86 million). Lease obligations represent 100% of the present value of future minimum lease payments in the lease arrangement. Where we have contracted directly with a lessor in our role as operator of an unincorporated oil and gas venture, we bill our partners their proportionate share for reimbursements as payments under lease agreements become due pursuant to the terms of our joint operating and other agreements. The nature of our leasing arrangements at December 31, 2023 was as follows: Operating leases : In the normal course of business, we primarily lease drilling rigs, equipment, logistical assets (offshore vessels, aircraft, and shorebases), and office space. Finance leases: In 2018, we entered into a sale and lease-back arrangement for a floating storage and offloading vessel (FSO) to handle produced condensate at North Malay Basin, offshore Peninsular Malaysia. At December 31, 2023, the remaining lease term for the FSO was 9.8 years. Maturities of lease obligations at December 31, 2023 were as follows: Operating Leases Finance (In millions) 2024 $ 377 $ 36 2025 197 36 2026 89 31 2027 48 22 2028 22 23 Remaining years 165 99 Total lease payments 898 247 Less: Imputed interest (92) (68) Total lease obligations $ 806 $ 179 The following information relates to the operating and finance leases at December 31: Operating Leases Finance Leases 2023 2022 2023 2022 Weighted average remaining lease term 5.0 years 6.8 years 9.8 years 10.8 years Range of remaining lease terms 0.1 - 12.5 years 0.3 - 13.5 years 9.8 years 10.8 years Weighted average discount rate 5.1% 4.5% 7.9% 7.9% The components of lease costs were as follows: 2023 2022 2021 (In millions) Operating lease cost (a) $ 241 $ 114 $ 88 Finance lease cost: Amortization of leased assets 18 18 24 Interest on lease obligations 15 18 18 Short-term lease cost (b) 294 311 137 Variable lease cost (c) 67 33 21 Sublease income (d) (19) (18) (17) Total lease cost $ 616 $ 476 $ 271 (a) Operating lease cost in 2023 included a drilling rig at North Malay Basin used for a 15 well development drilling program spanning 2023 and 2024, and offshore support vessels in the Gulf of Mexico. (b) Short-term lease cost is primarily attributable to equipment used in global exploration, development, production, and crude oil marketing activities. Future short-term lease costs will vary based on activity levels of our operated assets. In 2023 and 2022, short-term lease cost included drilling rigs and offshore support vessels used primarily for exploration and abandonment activities in the Gulf of Mexico and workover rigs for maintenance activities in the Bakken. (c) Variable lease costs for drilling rigs result from differences in the minimum rate and the actual usage of the ROU asset during the lease period. Variable lease costs for logistical assets result from differences in stated monthly rates and total charges reflecting the actual usage of the ROU asset during the lease period. Variable lease costs for our office leases represent common area maintenance charges which have not been separated from lease components. (d) We sublease certain of our office space to third parties under our head lease. The above lease costs represent 100% of the lease payments due for the period, including where we as operator have contracted directly with suppliers. As the payments under lease agreements where we are operator become due, we bill our partners their proportionate share for reimbursement pursuant to the terms of our joint operating agreements. Reimbursements are not reflected in the table above. Certain lease costs above associated with exploration and development activities are included in capital expenditures. Supplemental cash flow information related to leases were as follows: Operating Leases Finance Leases 2023 2022 2021 2023 2022 2021 (In millions) Cash paid for amounts included in the measurement of lease obligations: Operating cash flows (a) $ 254 $ 126 $ 87 $ 15 $ 18 $ 18 Financing cash flows (a) — — — 21 19 18 Noncash transactions: Leased assets recognized for new lease obligations incurred (b) 267 294 12 — — — Changes in leased assets and lease obligations due to lease modifications (c) 97 16 29 — — — (a) Amounts represent gross lease payments before any recovery from partners. (b) In 2023, primarily related to leases for a drilling rig and offshore support vessels in the Gulf of Mexico. In 2022, primarily related to leases for drilling rigs in the Bakken and at North Malay Basin. (c)
Leases	6. Leases Operating and finance lease obligations at December 31 included in the Consolidated Balance Sheet were as follows: Operating Leases Finance Leases 2023 2022 2023 2022 (In millions) Right-of-use assets — net (a) $ 720 $ 570 $ 108 $ 126 Lease obligations: Current $ 347 $ 200 $ 23 $ 21 Long-term 459 469 156 179 Total lease obligations $ 806 $ 669 $ 179 $ 200 (a) At December 31, 2023, finance lease ROU assets had a cost of $212 million (2022: $212 million) and accumulated amortization of $104 million (2022: $86 million). Lease obligations represent 100% of the present value of future minimum lease payments in the lease arrangement. Where we have contracted directly with a lessor in our role as operator of an unincorporated oil and gas venture, we bill our partners their proportionate share for reimbursements as payments under lease agreements become due pursuant to the terms of our joint operating and other agreements. The nature of our leasing arrangements at December 31, 2023 was as follows: Operating leases : In the normal course of business, we primarily lease drilling rigs, equipment, logistical assets (offshore vessels, aircraft, and shorebases), and office space. Finance leases: In 2018, we entered into a sale and lease-back arrangement for a floating storage and offloading vessel (FSO) to handle produced condensate at North Malay Basin, offshore Peninsular Malaysia. At December 31, 2023, the remaining lease term for the FSO was 9.8 years. Maturities of lease obligations at December 31, 2023 were as follows: Operating Leases Finance (In millions) 2024 $ 377 $ 36 2025 197 36 2026 89 31 2027 48 22 2028 22 23 Remaining years 165 99 Total lease payments 898 247 Less: Imputed interest (92) (68) Total lease obligations $ 806 $ 179 The following information relates to the operating and finance leases at December 31: Operating Leases Finance Leases 2023 2022 2023 2022 Weighted average remaining lease term 5.0 years 6.8 years 9.8 years 10.8 years Range of remaining lease terms 0.1 - 12.5 years 0.3 - 13.5 years 9.8 years 10.8 years Weighted average discount rate 5.1% 4.5% 7.9% 7.9% The components of lease costs were as follows: 2023 2022 2021 (In millions) Operating lease cost (a) $ 241 $ 114 $ 88 Finance lease cost: Amortization of leased assets 18 18 24 Interest on lease obligations 15 18 18 Short-term lease cost (b) 294 311 137 Variable lease cost (c) 67 33 21 Sublease income (d) (19) (18) (17) Total lease cost $ 616 $ 476 $ 271 (a) Operating lease cost in 2023 included a drilling rig at North Malay Basin used for a 15 well development drilling program spanning 2023 and 2024, and offshore support vessels in the Gulf of Mexico. (b) Short-term lease cost is primarily attributable to equipment used in global exploration, development, production, and crude oil marketing activities. Future short-term lease costs will vary based on activity levels of our operated assets. In 2023 and 2022, short-term lease cost included drilling rigs and offshore support vessels used primarily for exploration and abandonment activities in the Gulf of Mexico and workover rigs for maintenance activities in the Bakken. (c) Variable lease costs for drilling rigs result from differences in the minimum rate and the actual usage of the ROU asset during the lease period. Variable lease costs for logistical assets result from differences in stated monthly rates and total charges reflecting the actual usage of the ROU asset during the lease period. Variable lease costs for our office leases represent common area maintenance charges which have not been separated from lease components. (d) We sublease certain of our office space to third parties under our head lease. The above lease costs represent 100% of the lease payments due for the period, including where we as operator have contracted directly with suppliers. As the payments under lease agreements where we are operator become due, we bill our partners their proportionate share for reimbursement pursuant to the terms of our joint operating agreements. Reimbursements are not reflected in the table above. Certain lease costs above associated with exploration and development activities are included in capital expenditures. Supplemental cash flow information related to leases were as follows: Operating Leases Finance Leases 2023 2022 2021 2023 2022 2021 (In millions) Cash paid for amounts included in the measurement of lease obligations: Operating cash flows (a) $ 254 $ 126 $ 87 $ 15 $ 18 $ 18 Financing cash flows (a) — — — 21 19 18 Noncash transactions: Leased assets recognized for new lease obligations incurred (b) 267 294 12 — — — Changes in leased assets and lease obligations due to lease modifications (c) 97 16 29 — — — (a) Amounts represent gross lease payments before any recovery from partners. (b) In 2023, primarily related to leases for a drilling rig and offshore support vessels in the Gulf of Mexico. In 2022, primarily related to leases for drilling rigs in the Bakken and at North Malay Basin. (c)

Debt

Debt	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Debt	7. Debt Total debt at December 31 consisted of the following: 2023 2022 (In millions) Debt – Hess Corporation: Senior unsecured fixed-rate public notes: 3.500% due 2024 $ 300 $ 300 4.300% due 2027 997 996 7.875% due 2029 465 464 7.300% due 2031 629 629 7.125% due 2033 537 537 6.000% due 2040 743 742 5.600% due 2041 1,238 1,237 5.800% due 2047 495 494 Total senior unsecured fixed-rate public notes 5,404 5,399 Fair value adjustments – interest rate hedging (2) (4) Total Debt – Hess Corporation $ 5,402 $ 5,395 Debt – Midstream (Hess Midstream Operations LP): Senior unsecured fixed-rate public notes: 5.625% due 2026 $ 795 $ 793 5.125% due 2028 545 544 4.250% due 2030 742 740 5.500% due 2030 395 395 Total senior unsecured fixed-rate public notes 2,477 2,472 Term Loan A facility 394 396 Revolving credit facility 340 18 Total Debt – Midstream $ 3,211 $ 2,886 Total Debt: Current portion of long-term debt $ 311 $ 3 Long-term debt 8,302 8,278 Total Debt $ 8,613 $ 8,281 At December 31, 2023, the maturity profile of total debt was as follows: Total Hess Midstream (In millions) 2024 $ 311 $ 298 $ 13 2025 22 — 22 2026 832 — 832 2027 1,670 1,000 670 2028 550 — 550 Thereafter 5,290 4,140 1,150 Total Borrowings 8,675 5,438 3,237 Less: Deferred financing costs and discounts (62) (36) (26) Total Debt (excluding interest) $ 8,613 $ 5,402 $ 3,211 In 2023, $48 million of interest was capitalized (2022: $10 million; 2021: $0 million). Debt – Hess Corporation: Senior unsecured fixed-rate public notes: At December 31, 2023, Hess Corporation’s fixed-rate senior unsecured notes had a gross principal amount of $5,438 million (2022: $5,438 million) and a weighted average interest rate of 5.9% (2022: 5.9%). The indentures for our fixed-rate senior unsecured notes limit the ratio of secured debt to Consolidated Net Tangible Assets (as that term is defined in the indentures) to 15%. As of December 31, 2023, Hess Corporation was in compliance with this financial covenant. Credit facility: The revolving credit facility can be used for borrowings and letters of credit. Borrowings on the facility will generally bear interest at 1.400% above SOFR, though the interest rate is subject to adjustment based on the credit rating of the Corporation ’ s senior, unsecured, non-credit enhanced long-term debt. The revolving credit facility is subject to customary representations, warranties, customary events of default and covenants, including a financial covenant limiting the ratio of Total Consolidated Debt to Total Capitalization of the Corporation and its consolidated subsidiaries to 65%, and a financial covenant limiting the ratio of secured debt to Consolidated Net Tangible Assets of the Corporation and its consolidated subsidiaries to 15% (as these capitalized terms are defined in the credit agreement for the revolving credit facility). As of December 31, 2023, Hess Corporation was in compliance with these financial covenants. At December 31, 2023, Hess Corporation had no outstanding borrowings or letters of credit under its revolving credit facility. Other outstanding letters of credit at December 31 were as follows: 2023 2022 (In millions) Committed lines (a) $ 2 $ — Uncommitted lines (a) 86 83 Total $ 88 $ 83 (a) At December 31, 2023, committed and uncommitted lines have expiration dates through 2024. The most restrictive of the financial covenants relating to our fixed-rate senior unsecured notes and our revolving credit facility would allow us to borrow up to an additional $2,515 million of secured debt at December 31, 2023. Debt – Midstream (Hess Midstream Operations LP): Senior unsecured fixed-rate public notes: At December 31, 2023, HESM Opco’s fixed-rate senior unsecured notes had a gross principal amount of $2,500 million (2022: $2,500 million) and a weighted average interest rate of 5.1% (2022: 5.1%). HESM Opco ’ s senior unsecured notes are guaranteed by certain of HESM Opco’s direct and indirect wholly owned material domestic subsidiaries. These senior unsecured notes are non-recourse to Hess Corporation. In April 2022, HESM Opco issued $400 million in aggregate principal amount of 5.500% fixed-rate senior unsecured notes due in 2030 in a private offering to repay borrowings under its revolving credit facility used to finance the repurchase of approximately 13.6 million HESM Opco Class B units held by Hess and GIP. In August 2021, HESM Opco issued $750 million in aggregate principal amount of 4.250% fixed-rate senior unsecured notes due in 2030 in a private offering to finance the repurchase of 31.25 million HESM Opco Class B units held by Hess and GIP. Credit facilities: At December 31, 2023, HESM Opco had $1.4 billion of senior secured syndicated credit facilities, consisting of a $1.0 billion revolving credit facility and a $400 million term loan facility. Borrowings under the term loan facility will generally bear interest at SOFR plus an applicable margin ranging from 1.650% to 2.550%, while the applicable margin for the syndicated revolving credit facility ranges from 1.375% to 2.050%. Pricing levels for the facility fee and interest-rate margins are based on HESM Opco’s ratio of total debt to EBITDA (as defined in the credit facilities). If HESM Opco obtains an investment grade credit rating, the pricing levels will be based on HESM Opco’s credit ratings in effect from time to time. The credit facilities contain covenants that require HESM Opco to maintain a ratio of total debt to EBITDA (as defined in the credit facilities) for the prior four fiscal quarters of not greater than 5.00 to 1.00 as of the last day of each fiscal quarter (5.50 to 1.00 during the specified period following certain acquisitions) and, prior to HESM Opco obtaining an investment grade credit rating, a ratio of secured debt to EBITDA for the prior four fiscal quarters of not greater than 4.00 to 1.00 as of the last day of each fiscal quarter. HESM Opco was in compliance with these financial covenants at December 31, 2023. The credit facilities are secured by first-priority perfected liens on substantially all of the assets of HESM Opco and its direct and indirect wholly owned material domestic subsidiaries, including equity interests directly owned by such entities, subject to certain customary exclusions. At December 31, 2023, borrowings of $340 million were drawn under HESM Opco’s revolving credit facility, and borrowings of $397 million, excluding deferred issuance costs, were drawn under HESM Opco’s term loan facility. Borrowings under these credit facilities are non-recourse to Hess Corporation.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	8. Asset Retirement Obligations The following table describes the changes in our asset retirement obligations for the years ended December 31: 2023 2022 (In millions) Balance at January 1 $ 1,241 $ 1,190 Liabilities incurred 135 126 Liabilities settled or disposed of (a) (240) (213) Accretion expense 61 48 Revisions of estimated liabilities 148 92 Foreign currency remeasurement 1 (2) Balance at December 31 $ 1,346 $ 1,241 Total Asset Retirement Obligations at December 31: Current portion of asset retirement obligations $ 160 $ 207 Long-term asset retirement obligations 1,186 1,034 Total at December 31 $ 1,346 $ 1,241 (a) Payments to settle asset retirement obligations are presented in Changes in other operating assets and liabilities on the Statement of Consolidated Cash Flows. The liabilities incurred in 2023 primarily relate to operations in Guyana while liabilities incurred in 2022 primarily relate to operations in Guyana and Malaysia. Liabilities settled or disposed of in 2023 and 2022 primarily result from abandonment activity completed in the Gulf of Mexico and the Bakken. Revisions of estimated liabilities in 2023 include $82 million that resulted from revisions to estimated costs to abandon certain wells, pipelines and production facilities in the West Delta Field in the Gulf of Mexico. See Note 12, Impairment and Other . Other revisions of estimated liabilities in 2023 primarily reflect changes in service and equipment rates. Revisions of estimated liabilities in 2022 primarily reflect changes in service and equipment rates. Sinking fund deposits that are legally restricted for purposes of settling asset retirement obligations, which are reported in non-current Other assets in the Consolidated Balance Sheet , were $294 million at December 31, 2023 (2022: $261 million).

Retirement Plans

Retirement Plans	12 Months Ended
	Dec. 31, 2023
Retirement Benefits [Abstract]
Retirement Plans	9. Retirement Plans We have funded noncontributory defined benefit pension plans for a significant portion of our employees. In addition, we have an unfunded supplemental pension plan covering certain employees, which provides incremental payments that would have been payable from our principal pension plans, were it not for limitations imposed by income tax regulations. The plans provide defined benefits based on years of service and final average salary to our U.S. employees hired prior to January 1, 2017 and to our employees in the United Kingdom (U.K.). The U.S. employees hired on or after January 1, 2017 participate under a cash accumulation formula and receive credits to a notional account based on a percentage of pensionable wages. Interest accrues on the balance in the notional account at a rate determined in accordance with plan provisions. Additionally, we maintain an unfunded post-retirement medical plan that provides health benefits to certain U.S. qualified retirees from ages 55 through 65. The measurement date for all retirement plans is December 31. The following table summarizes the benefit obligations, the fair value of plan assets, and the funded status of our pension and postretirement medical plans: Funded Unfunded Postretirement 2023 2022 2023 2022 2023 2022 (In millions) Change in Benefit Obligation Balance at January 1, $ 1,802 $ 2,948 $ 212 $ 248 $ 52 $ 59 Service cost 26 33 9 11 3 3 Interest cost 88 66 9 3 2 1 Actuarial (gain) loss (a) 44 (818) 7 (38) 1 (7) Plan settlements (143) (266) — — — — Benefit payments (77) (90) (15) (12) (5) (4) Foreign currency exchange rate changes 20 (71) — — — — Balance at December 31, (b) $ 1,760 $ 1,802 $ 222 $ 212 $ 53 $ 52 Change in Fair Value of Plan Assets Balance at January 1, $ 2,450 $ 3,357 $ — $ — $ — $ — Actual return on plan assets 186 (469) — — — — Employer contributions 1 1 15 12 5 4 Plan settlements (143) (266) — — — — Benefit payments (77) (90) (15) (12) (5) (4) Foreign currency exchange rate changes 28 (83) — — — — Balance at December 31, $ 2,445 $ 2,450 $ — $ — $ — $ — Funded Status (Plan assets greater (less) than benefit obligations) at December 31, $ 685 $ 648 $ (222) $ (212) $ (53) $ (52) Unrecognized Net Actuarial (Gains) Losses (c) $ 332 $ 337 $ 30 $ 23 $ (25) $ (27) (a) In 2023, changes in discount rates resulted in actuarial losses of $56 million, updates to census data resulted in actuarial losses of $18 million, and the alignment of the projected benefit obligation to the amount of plan settlement payments resulted in actuarial gains of $20 million. Changes in all other assumptions resulted in net actuarial gains of $2 million in 2023. In 2022, changes in discount rates resulted in actuarial gains of $874 million and changes in mortality assumptions resulted in actuarial losses of $8 million. Changes in all other assumptions, including inflation and demographic assumptions, resulted in net actuarial losses of $3 million in 2022. (b) At December 31, 2023, the accumulated benefit obligation for the funded and unfunded defined benefit pension plans was $1,684 million and $181 million, respectively (2022: $1,743 million and $180 million, respectively). (c) At December 31, 2023, the unrecognized net actuarial losses related to the U.K. pension plan was $179 million (2022: $175 million). Amounts recognized in the Consolidated Balance Sheet at December 31 consisted of the following: Funded Unfunded Postretirement 2023 2022 2023 2022 2023 2022 (In millions) Noncurrent assets $ 685 $ 648 $ — $ — $ — $ — Current liabilities — — (23) (24) (5) (6) Noncurrent liabilities — — (199) (188) (48) (46) Post-retirement benefit assets / (liabilities) $ 685 $ 648 $ (222) $ (212) $ (53) $ (52) Accumulated other comprehensive (income) loss, pre-tax (a) $ 332 $ 337 $ 30 $ 23 $ (25) $ (27) (a) The after‑tax deficit reflected in Accumulated other comprehensive income (loss) was $134 million at December 31, 2023 (2022: $131 million deficit). The net periodic benefit cost for funded and unfunded pension plans, and the postretirement medical plan, is as follows: Pension Plans Postretirement Medical Plan 2023 2022 2021 2023 2022 2021 (In millions) Service cost $ 35 $ 44 $ 51 $ 3 $ 3 $ 3 Interest cost 97 69 55 2 1 1 Expected return on plan assets (156) (196) (197) — — — Amortization of unrecognized net actuarial losses (gains) 3 11 58 (2) (1) (1) Settlement loss 17 2 9 — — — Net Periodic Benefit Cost / (Income) (a) $ (4) $ (70) $ (24) $ 3 $ 3 $ 3 (a) Net non-service cost, which is included in Other, net in the Statement of Consolidated Income, was income of $39 million in 2023 (2022: $114 million of income; 2021: $75 million of income). In 2023, the Hess Corporation Employees ’ Pension Plan paid lump sums to certain participants totaling $143 million which resulted in a noncash settlement loss of $17 million to recognize unamortized actuarial losses. In 2022, the Hess Corporation Employees ’ Pension Plan purchased a single premium annuity contract at a cost of $166 million using assets of the plan to settle and transfer certain of its obligations to a third party. This partial settlement resulted in a noncash settlement loss of $13 million to recognize unamortized actuarial losses. In 2022, the HOVENSA Legacy Employees ’ Pension Plan paid lump sums to certain participants totaling $20 million, and purchased a single premium annuity contract at a cost of $80 million, to settle the plan ’ s projected benefit obligation in connection with terminating the plan. The settlement transactions resulted in a noncash settlement gain of $11 million to recognize unamortized actuarial gains. The assets remaining after settlement of the plan ’ s projected benefit obligation of $15 million were transferred to the Hess Corporation Employees ’ Pension Plan in December 2022. In 2024, we forecast service cost for our pension and post-retirement medical plans to be approximately $40 million and net non-service cost of approximately $65 million of income, which is comprised of interest cost The board of trustees for our U.K. pension plan is evaluating various alternatives to settle all or a portion of the plan’s projected benefit obligation. A decision to proceed will occur only after the board of trustees receives and evaluates proposals and determines that the transaction is in the best interest of plan participants. Should a settlement be completed, a material noncash settlement loss may be recorded reflecting any difference between the settlement value and projected benefit obligation, and the acceleration of the recognition of unrecognized actuarial losses. Assumptions : The weighted average actuarial assumptions used to determine benefit obligations at December 31 and net periodic benefit cost for the three years ended December 31 for our funded and unfunded pension plans were as follows: 2023 2022 2021 Benefit Obligations: Discount rate 4.8% 5.0% 2.5% Rate of compensation increase 3.9% 4.0% 3.8% Net Periodic Benefit Cost: Discount rate Service cost 5.0% 3.3% 2.6% Interest cost 4.9% 3.0% 1.7% Expected rate of return on plan assets 6.5% 6.5% 6.6% Rate of compensation increase 4.0% 3.8% 3.8% The actuarial assumptions used to determine benefit obligations at December 31 for the post-retirement medical plan were as follows: 2023 2022 2021 Discount rate 4.7% 4.9% 2.4% Initial health care trend rate 6.0% 6.3% 5.5% Ultimate trend rate 4.0% 4.0% 4.0% Year in which ultimate trend rate is reached 2046 2046 2046 The assumptions used to determine net periodic benefit cost for each year were established at the end of each previous year. In 2022 and 2021, there was an interim remeasurement of the funded status of certain plans due to plan settlements which resulted in net periodic benefit cost being recalculated for the remainder of the year using assumptions as of the interim remeasurement dates. The assumptions disclosed in the preceding table used to determine net periodic benefit cost for 2022 and 2021 are a weighted average of the assumptions as of the end of the previous year and the interim remeasurement dates. Due to the timing of plan settlements in 2023, an interim remeasurement of the funded status was unnecessary in 2023. The assumptions used to determine benefit obligations were established at each year end. Discount rates are developed based on a portfolio of high‑quality, fixed income debt instruments with maturities that approximate the expected payment of plan obligations. The overall expected rate of return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of assets to that asset category. The future expected rate of return assumptions for individual asset categories are largely based on inputs from various investment experts regarding their future return expectations for particular asset categories. The expected rate of return on plan assets is applied to the fair value of plan assets to determine the expected return on plan assets component of net periodic benefit cost for the year. Our investment strategy is to maximize long‑term returns at an acceptable level of risk through broad diversification of plan assets in a variety of asset classes. Asset classes and target allocations are determined by our investment committee and include domestic and foreign equities, fixed income, and other investments, including hedge funds, real estate and private equity. Investment managers are prohibited from investing in securities issued by us unless indirectly held as part of an index strategy. The majority of plan assets are highly liquid, providing ample liquidity for benefit payment requirements. The current target allocations are 30% equity securities, 50% fixed income securities (including cash and short‑term investment funds) and 20% to all other types of investments. Asset allocations are rebalanced on a periodic basis throughout the year to bring assets to within an acceptable range of target levels. Fair value: The following tables provide the fair value of the financial assets of the funded pension plans at December 31, 2023 and 2022 in accordance with the fair value measurement hierarchy described in Note 1, Nature of Operations, Basis of Presentation and Summary of Accounting Policies . Level 1 Level 2 Level 3 Net Asset Total (In millions) December 31, 2023 Cash and Short-Term Investment Funds $ 27 $ — $ — $ — $ 27 Equities: U.S. equities (domestic) 309 — — — 309 International equities (non-U.S.) 52 — — 158 210 Global equities (domestic and non-U.S.) — 6 — 55 61 Fixed Income: Treasury and government related (a) — 581 — — 581 Mortgage-backed securities (b) — 98 — 12 110 Corporate — 547 — 3 550 Other: Hedge funds — — — — — Private equity funds — — — 414 414 Real estate funds — — — 183 183 Total investments $ 388 $ 1,232 $ — $ 825 $ 2,445 December 31, 2022 Cash and Short-Term Investment Funds $ 51 $ — $ — $ — $ 51 Equities: U.S. equities (domestic) 409 — — 11 420 International equities (non-U.S.) 62 11 — 306 379 Global equities (domestic and non-U.S.) — 5 — 90 95 Fixed Income: Treasury and government related (a) — 364 — — 364 Mortgage-backed securities (b) — 142 — 18 160 Corporate — 304 — 8 312 Other: Hedge funds — — — 75 75 Private equity funds — — — 374 374 Real estate funds 9 — — 211 220 Total investments $ 531 $ 826 $ — $ 1,093 $ 2,450 (a) Includes securities issued and guaranteed by U.S. and non‑U.S. governments, and securities issued by governmental agencies and municipalities. (b) Comprised of U.S. residential and commercial mortgage-backed securities. (c) Includes certain investments that have been valued using the net asset value (NAV) practical expedient, and therefore have not been categorized in the fair value hierarchy. The inclusion of such amounts in the above table is intended to aid reconciliation of investments categorized in the fair value hierarchy to total pension plan assets. The following describes the financial assets of the funded pension plans: Cash and short‑term investment funds – Consists of cash on hand and short-term investment funds that provide for daily investments and redemptions which are classified as Level 1. Equities – Consists of individually held U.S. and international equity securities. This investment category also includes funds that consist primarily of U.S. and international equity securities. Equity securities, which are individually held and are traded actively on exchanges, are classified as Level 1. Certain funds, consisting primarily of equity securities, are classified as Level 2 if the NAV is determined and published daily, and is the basis for current transactions. Commingled funds, consisting primarily of equity securities held in unitized trusts, are valued using the NAV per fund share. Fixed income investments – Consists of individually held securities issued by the U.S. government, non-U.S. governments, governmental agencies, municipalities and corporations, and agency and non-agency mortgage-backed securities. This investment category also includes funds that consist primarily of fixed income securities. Individual fixed income securities are generally valued on the basis of evaluated prices from independent pricing services. Such prices are monitored by the trustee, which also serves as the independent third-party custodial firm responsible for safekeeping assets of the particular plan, and are classified as Level 2. Exchange-traded funds consisting of fixed income securities are classified as Level 1. Certain funds, consisting primarily of fixed income securities, are classified as Level 2 if the NAV is determined and published daily, and is the basis for current transactions. Commingled funds, consisting primarily of fixed income securities, are valued using the NAV per fund share. Other investments – Consists of exchange‑traded real estate investment trust securities, which are classified as Level 1. Commingled funds and limited partnership investments in hedge funds, private equity and real estate funds are valued at the NAV per fund share. Contributions and estimated future benefit payments : In 2024, we expect to contribute approximately $25 million to our funded pension plans. Estimated future benefit payments by the funded and unfunded pension plans, and the post-retirement medical plan, which reflect expected future service, are as follows (in millions): 2024 $ 112 2025 117 2026 167 2027 117 2028 123 Years 2029 to 2033 611 We also have defined contribution plans for certain eligible employees. Employees may contribute a portion of their compensation to these plans and we match a portion of the employee contributions. We recorded expense of $24 million in 2023 for contributions to these plans (2022: $22 million; 2021: $18 million).

Revenue

Revenue	12 Months Ended
	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Revenue	10. Revenue Revenue from contracts with customers on a disaggregated basis was as follows (in millions): Exploration and Production Midstream Eliminations Total United States Guyana Malaysia and JDA Other (a) E&P Total 2023 Sales of net production volumes: Crude oil revenue $ 3,058 $ 3,486 $ 144 $ — $ 6,688 $ — $ — $ 6,688 Natural gas liquids revenue 529 — — — 529 — — 529 Natural gas revenue 182 — 800 — 982 — — 982 Sales of purchased oil and gas 2,390 70 — — 2,460 — — 2,460 Third-party services — — — — — 8 — 8 Intercompany revenue — — — — — 1,338 (1,338) — Total sales (b) 6,159 3,556 944 — 10,659 1,346 (1,338) 10,667 Other operating revenues (c) (78) (62) (19) — (159) 3 — (156) Total sales and other operating revenues $ 6,081 $ 3,494 $ 925 $ — $ 10,500 $ 1,349 $ (1,338) $ 10,511 2022 Sales of net production volumes: Crude oil revenue $ 3,407 $ 2,771 $ 134 $ 509 $ 6,821 $ — $ — $ 6,821 Natural gas liquids revenue 703 — — — 703 — — 703 Natural gas revenue 438 — 739 21 1,198 — — 1,198 Sales of purchased oil and gas 2,978 53 — 112 3,143 — — 3,143 Intercompany revenue — — — — — 1,273 (1,273) — Total sales (b) 7,526 2,824 873 642 11,865 1,273 (1,273) 11,865 Other operating revenues (c) (312) (188) — (41) (541) — — (541) Total sales and other operating revenues $ 7,214 $ 2,636 $ 873 $ 601 $ 11,324 $ 1,273 $ (1,273) $ 11,324 2021 Sales of net production volumes: Crude oil revenue $ 2,958 $ 765 $ 83 $ 519 $ 4,325 $ — $ — $ 4,325 Natural gas liquids revenue 594 — — — 594 — — 594 Natural gas revenue 350 — 655 10 1,015 — — 1,015 Sales of purchased oil and gas 1,638 16 — 95 1,749 — — 1,749 Intercompany revenue — — — — — 1,204 (1,204) — Total sales (b) 5,540 781 738 624 7,683 1,204 (1,204) 7,683 Other operating revenues (c) (162) (27) — (21) (210) — — (210) Total sales and other operating revenues $ 5,378 $ 754 $ 738 $ 603 $ 7,473 $ 1,204 $ (1,204) $ 7,473 (a) Other includes our interest in the Waha Concession in Libya, which was sold in November 2022, and our interests in Denmark, which were sold in August 2021. (b) Guyana crude oil revenue includes $433 million of revenue from non-customers in 2023 (2022: $230 million). There was no sales revenue from non-customers in 2021. (c) Other operating revenues are not a component of revenues from contracts with customers. Included within other operating revenues are gains (losses) on commodity derivatives

Dispositions

Dispositions	12 Months Ended
	Dec. 31, 2023
Disposal Group, Not Discontinued Operation, Disposal Disclosures [Abstract]
Dispositions	11. Dispositions 2022: We completed the sale of our 8% interest in the Waha Concession in Libya for net cash consideration of $150 million and recognized a pre-tax gain of $76 million ($76 million after income taxes). We also completed the sale of real property related to our former downstream business for cash consideration of $24 million and recognized a pre-tax gain of $22 million ($22 million after income taxes). 2021: We completed the sale of our interests in Denmark for net cash consideration of approximately $130 million, after normal closing adjustments, and recognized a pre-tax gain of $29 million ($29 million after income taxes). In addition, we completed the sale of our Little Knife and Murphy Creek nonstrategic acreage interests in the Bakken for net cash consideration of $297 million, after normal closing adjustments. The sale included approximately 78,700 net acres, which are located in the southernmost portion of the Corporation ’ s Bakken position. The acreage constituted part of a larger amortization base and the sale was treated as a normal retirement. Accordingly, no gain or loss was recognized upon sale.

Impairment and Other

Impairment and Other	12 Months Ended
	Dec. 31, 2023
Asset Impairment Charges [Abstract]
Impairment and Other	12. Impairment and Other 2023 : We recorded a pre-tax charge of $82 million ($82 million after income taxes) that resulted from revisions to estimated costs to abandon certain wells, pipelines and production facilities in the West Delta Field in the Gulf of Mexico. These abandonment obligations were assigned to us as a former owner after they were discharged from Fieldwood Energy LLC (Fieldwood) as part of its approved bankruptcy plan in 2021. See Note 8, Asset Retirement Obligations . 2022 : We recorded a pre-tax charge of $28 million ($28 million after income taxes) that resulted from updates to our estimated abandonment liabilities for non-producing properties in the Gulf of Mexico and $26 million ($26 million after income taxes) to fully impair the net book value of our interests in the Penn State Field in the Gulf of Mexico due to a mechanical issue on the field ’ s remaining production well. 2021: In June 2021, the U.S. Bankruptcy Court approved the bankruptcy plan of Fieldwood, which included the abandonment of certain assets, including seven offshore Gulf of Mexico leases and related facilities in the West Delta Field that were formerly owned by us and sold to a Fieldwood predecessor in 2004, and the discharge of Fieldwood’s obligation to decommission these facilities. As a result, we recognized a pre-tax charge of $147 million ($147 million after income taxes) in connection with the estimated abandonment obligations in the West Delta Field.

Share-based Compensation

Share-based Compensation	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Share-based Compensation	13. Share-based Compensation We have established and maintain LTIP for the granting of restricted common shares, PSUs and stock options to our employees. At December 31, 2023, the total number of authorized common stock under the LTIP was 63.5 million shares, of which we have 19.9 million shares available for issuance. Share‑based compensation expense consisted of the following: 2023 2022 2021 (In millions) Restricted stock $ 55 $ 52 $ 49 Performance share units 21 20 18 Stock options 11 11 10 Share-based compensation expense before income taxes $ 87 $ 83 $ 77 Income tax benefit on share-based compensation expense $ — $ — $ — Based on share‑based compensation awards outstanding at December 31, 2023, unearned compensation expense, before income taxes, of $89 million is expected to be recognized over a weighted average period of 1.8 years. Our share-based compensation plans can be summarized as follows: Restricted stock: Restricted stock generally vests equally on an annual basis over a three-year term and is valued based on the prevailing market price of our common stock on the date of grant. The following is a summary of restricted stock award activity in 2023: Shares of Restricted Common Stock Weighted - Average Price on Date of Grant (In thousands, except per share amounts) Outstanding at January 1, 2023 1,312 $ 80.61 Granted 470 141.76 Vested (a) (735) 73.24 Forfeited (26) 104.14 Outstanding at December 31, 2023 1,021 $ 113.47 (a) In 2023, restricted stock with a vesting date fair value of $104 million were vested (2022: $86 million; 2021: $72 million). Performance share units: PSUs generally vest three years from the date of grant and are valued using a Monte Carlo simulation on the date of grant. For the PSU's granted in 2021 and 2022, the number of shares of common stock to be issued under a PSU agreement is based on a comparison of the Corporation’s total shareholder return (TSR) 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. Payouts of the performance share awards will range from 0% to 200% of the target awards based on the Corporation’s TSR ranking within the peer group. Dividend equivalents for the performance period will accrue on performance shares but will only be paid out on earned shares after the performance period. For the PSU's granted in 2023, the number of shares of common stock to be issued under a PSU agreement 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 the performance share awards 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%. Dividend equivalents for the performance period will accrue on performance shares but will only be paid out on earned shares after the performance period. The following is a summary of PSU activity in 2023: Performance Share Units Weighted - Average Fair Value on Date of Grant (In thousands, except per share amounts) Outstanding at January 1, 2023 686 $ 81.25 Granted 130 178.80 Vested (a) (303) 57.93 Forfeited (1) 104.54 Outstanding at December 31, 2023 512 $ 119.77 (a) In 2023, PSU’s with a vesting date fair value of $55 million were vested (2022: $37 million; 2021: $30 million). The following weighted average assumptions were utilized to estimate the fair value of PSU awards: 2023 2022 2021 Risk free interest rate 4.61 % 1.59 % 0.29 % Stock price volatility 0.478 0.584 0.579 Contractual term in years 3.0 3.0 3.0 Grant date price of Hess common stock $ 141.95 $ 101.17 $ 75.04 Stock options: Stock options vest over three years from the date of grant, have a 10‑year term, and the exercise price equals the market price of our common stock on the date of grant. The following is a summary of stock options activity in 2023: Number of options Weighted Average Exercise Price per Share Weighted Average Remaining Contractual Term Outstanding at January 1, 2023 1,481 $ 69.31 6.6 years Granted 189 141.71 Exercised (157) 64.34 Forfeited (3) 90.73 Outstanding at December 31, 2023 1,510 $ 78.85 6.1 years At December 31, 2023, there were 1.5 million outstanding stock options (1.0 million exercisable) with a weighted average exercise price of $78.85 per share ($64.07 per share for exercisable options), a weighted average remaining contractual life of 6.1 years (5.1 years for exercisable options) and an aggregate intrinsic value of $105 million ($88 million for exercisable options). The intrinsic value of stock options exercised in 2023 was $13 million (2022: $44 million, 2021: $45 million). The following weighted average assumptions were utilized to estimate the fair value of stock options: 2023 2022 2021 Risk free interest rate 4.20 % 1.66 % 0.95 % Stock price volatility 0.469 0.457 0.470 Dividend yield 1.24 % 1.48 % 1.33 % Expected life in years 6.0 6.0 6.0 Weighted average fair value per option granted $ 63.45 $ 39.51 $ 29.66 In estimating the fair value of PSUs and stock options, the risk-free interest rate is based on the expected term of the award and is obtained from published sources. The stock price volatility is determined from the historical stock prices of the Corporation using the expected term.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Income Taxes	14. Income Taxes The provision (benefit) for income taxes consisted of: 2023 2022 2021 (In millions) United States Federal Current $ — $ — $ — Deferred taxes and other accruals 31 22 12 State 7 5 3 38 27 15 Foreign Current (a) 537 789 478 Deferred taxes and other accruals 158 283 107 695 1,072 585 Provision (Benefit) For Income Taxes $ 733 $ 1,099 $ 600 (a) Primarily comprised of Guyana in 2023, Guyana and Libya in 2022, and Libya in 2021. Income (loss) before income taxes consisted of the following: 2023 2022 2021 (In millions) United States (a) $ (191) $ 569 $ 143 Foreign 2,662 2,977 1,347 Income (Loss) Before Income Taxes $ 2,471 $ 3,546 $ 1,490 (a) Includes substantially all of our interest expense, corporate expense, the results of commodity hedging activities, and amounts attributable to noncontrolling interests. The difference between our effective income tax rate and the U.S. statutory rate is reconciled below: 2023 2022 2021 U.S. statutory rate 21.0 % 21.0 % 21.0 % Effect of foreign operations (a) 7.5 16.5 28.0 State income taxes, net of federal income tax 0.2 0.1 0.2 Valuation allowance on current year operations 4.5 (4.8) (5.3) Release of valuation allowance (1.3) — — Noncontrolling interests in Midstream (2.0) (1.6) (4.0) Equity and executive compensation (0.2) (0.2) 0.4 Total 29.7 % 31.0 % 40.3 % (a) The variance in effective income tax rates attributable to the effect of foreign operations is primarily driven by Guyana in 2023 and Libya in 2022 and 2021. The components of deferred tax liabilities and deferred tax assets at December 31, were as follows: 2023 2022 (In millions) Deferred Tax Liabilities Property, plant and equipment and investments $ (2,117) $ (1,742) Other (108) (99) Total Deferred Tax Liabilities (2,225) (1,841) Deferred Tax Assets Net operating loss carryforwards 4,406 4,226 Tax credit carryforwards 109 98 Property, plant and equipment and investments 413 233 Accrued compensation, deferred credits and other liabilities 109 85 Asset retirement obligations 296 279 Other 256 293 Total Deferred Tax Assets 5,589 5,214 Valuation allowances (a) (3,652) (3,658) Total deferred tax assets, net of valuation allowances 1,937 1,556 Net Deferred Tax Assets (Liabilities) $ (288) $ (285) (a) In 2023, the valuation allowance decreased by $6 million (2022: decrease of $180 million; 2021: decrease of $1,553 million). In the Consolidated Balance Sheet , deferred tax assets and liabilities are netted by taxing jurisdiction and are recorded at December 31, as follows: 2023 2022 (In millions) Deferred income taxes (long-term asset) $ 320 $ 133 Deferred income taxes (long-term liability) (608) (418) Net Deferred Tax Assets (Liabilities) $ (288) $ (285) At December 31, 2023, we have a gross deferred tax asset related to net operating loss carryforwards of $4,406 million before application of valuation allowances. The deferred tax asset is comprised of $127 million attributable to foreign net operating losses which will begin to expire in 2025, $3,778 million attributable to U.S. federal operating losses which will begin to expire in 2034, and $501 million attributable to losses in various U.S. states which will begin to expire in 2024. The deferred tax asset attributable to foreign net operating losses, net of valuation allowances, is $23 million. A full valuation allowance is established against the deferred tax asset attributable to U.S. federal and state net operating losses, except for $38 million of U.S. federal and $8 million of U.S. state deferred tax assets attributable to Midstream activities for which separate U.S. federal and state tax returns are filed. At December 31, 2023, we have U.S. state tax credit carryforwards of $27 million, which will begin to expire in 2034, $81 million of other business credit carryforwards, which will begin to expire in 2036, and foreign tax credit carryforwards of $1 million, which will begin to expire in 2024. A full valuation allowance is established against the deferred tax asset attributable to these credits. At December 31, 2023, the Consolidated Balance Sheet reflects a $3,652 million (2022: $3,658 million) valuation allowance against the net deferred tax assets for multiple jurisdictions based on application of the relevant accounting standards. Hess continues to maintain a full valuation allowance against its deferred tax assets in the U.S. (non-Midstream) and certain other jurisdictions. The reduction in valuation allowance year over year is primarily due to a partial release of the valuation allowance in Malaysia, partially offset with an increase in deferred tax asset balances in other jurisdictions. Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. In December 2023, the valuation allowance established against a portion of the net deferred tax assets in Malaysia, related to the Marginal Field tax ring-fence was released in the amount of $33 million as a result of the emergence from a cumulative loss position and positive evidence from forecasted pre-tax income from operations. The remaining valuation allowance in Malaysia is associated with net deferred tax assets of other tax ring-fences which lack sufficient positive evidence to support realizability. While we emerged from a recent cumulative loss position in the U.S. (non-Midstream) in 2023, the cumulative income position is near breakeven. Until we see a more significant and sustained pattern of objectively verifiable income, we do not assign significant weight to subjective long-term projections of future income and thus maintain a full valuation allowance against our U.S. (non-Midstream) federal and state deferred tax assets. If anticipated future earnings are exceeded, sufficient positive evidence may become available to support the release of valuation allowance in the future. This would result in the recognition of certain deferred tax assets on the balance sheet and a decrease to income tax expense for the period in which the release is recognized. Below is a reconciliation of the gross beginning and ending amounts of unrecognized tax benefits: 2023 2022 2021 (In millions) Balance at January 1 $ 120 $ 133 $ 166 Additions based on tax positions taken in the current year — 17 12 Additions based on tax positions of prior years — — 3 Reductions based on tax positions of prior years (9) (30) (48) Balance at December 31 $ 111 $ 120 $ 133 There is no balance at December 31, 2023 for unrecognized tax benefits that, if recognized would impact our effective income tax rate. Over the next 12 months, we have no unrecognized benefit that is reasonably possible to decrease due to settlements with taxing authorities or other resolutions, as well as lapses in statutes of limitation. At December 31, 2023, we have no accrued interest and penalties related to unrecognized tax benefits (2022: $0 million). We file income tax returns in the U.S. and various foreign jurisdictions. We are no longer subject to examinations by income tax authorities in most jurisdictions for years prior to 2009.

Outstanding and Weighted Averag

Outstanding and Weighted Average Common Shares	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Outstanding and Weighted Average Common Shares	15. Outstanding and Weighted Average Common Shares Net income and weighted average number of common shares used in the basic and diluted earnings per share computations were as follows: 2023 2022 2021 (In millions except per share amounts) Net Income Attributable to Hess Corporation: Net income $ 1,738 $ 2,447 $ 890 Less: Net income attributable to noncontrolling interests 356 351 331 Net income attributable to Hess Corporation $ 1,382 $ 2,096 $ 559 Weighted Average Number of Common Shares Outstanding: Basic 305.9 308.1 307.4 Effect of dilutive securities Restricted common stock 0.5 0.7 0.7 Stock options 0.7 0.6 0.4 Performance share units 0.5 0.2 0.8 Diluted 307.6 309.6 309.3 Net Income Attributable to Hess Corporation per Common Share: Basic $ 4.52 $ 6.80 $ 1.82 Diluted $ 4.49 $ 6.77 $ 1.81 Antidilutive shares excluded from the computation of diluted shares: Restricted common stock — — — Stock options 0.2 0.2 0.7 Performance share units — — — The following table provides the changes in our outstanding common shares: 2023 2022 2021 (In millions) Balance at January 1 306.2 309.7 307.0 Activity related to restricted stock awards, net 0.4 0.5 0.7 Stock options exercised 0.2 0.9 1.5 PSUs vested 0.4 0.5 0.5 Shares repurchased — (5.4) — Balance at December 31 307.2 306.2 309.7 Common Stock Repurchase Plan : 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 during 2023 or 2021. During 2022, we repurchased approximately 5.4 million shares of our common stock for $650 million ($20 million was paid subsequent to December 31, 2022). Shares of common stock repurchased are retired upon settlement of the trade. Common Stock Dividends : Cash dividends declared on common stock totaled $1.75 per share in 2023 (2022: $1.50 per share; 2021: $1.00 per share).

Supplementary Cash Flow Informa

Supplementary Cash Flow Information	12 Months Ended
	Dec. 31, 2023
Supplemental Cash Flow Elements [Abstract]
Supplementary Cash Flow Information	16. Supplementary Cash Flow Information The following information supplements the Statement of Consolidated Cash Flows : 2023 2022 2021 (In millions) Cash Flows From Operating Activities Interest paid $ (470) $ (486) $ (459) Net income taxes (paid) refunded (71) (1,036) (16) Cash Flows From Investing Activities Additions to property, plant and equipment – E&P: Capital expenditures incurred – E&P $ (4,033) $ (2,589) $ (1,698) Increase (decrease) in related liabilities 149 102 114 Additions to property, plant and equipment – E&P $ (3,884) $ (2,487) $ (1,584) Additions to property, plant and equipment – Midstream: Capital expenditures incurred – Midstream $ (246) $ (232) $ (183) Increase (decrease) in related liabilities 22 (6) 20 Additions to property, plant and equipment – Midstream $ (224) $ (238) $ (163)

Guarantees, Contingencies and C

Guarantees, Contingencies and Commitments	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Guarantees, Contingencies and Commitments	17. Guarantees, Contingencies and Commitments Guarantees and Contingencies We are subject to loss contingencies with respect to various claims, lawsuits and other proceedings. A liability is recognized in our consolidated financial statements when it is probable that a loss has been incurred and the amount can be reasonably estimated. If the risk of loss is probable, but the amount cannot be reasonably estimated or the risk of loss is only reasonably possible, a liability is not accrued; however, we disclose the nature of those contingencies. We cannot predict with certainty if, how or when existing claims, lawsuits and proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages. We, along with many companies that have been or continue to be engaged in refining and marketing of gasoline, have been a party to lawsuits and claims related to the use of MTBE in gasoline. A series of similar lawsuits, many involving water utilities or governmental entities, were filed in jurisdictions across the United States against producers of MTBE and petroleum refiners who produced gasoline containing MTBE, including us. The principal allegation in all cases was that gasoline containing MTBE was a defective product and that these producers and refiners are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE. The majority of the cases asserted against us have been settled. There are two remaining active cases, filed by Pennsylvania and Maryland. In June 2014, the Commonwealth of Pennsylvania filed a lawsuit alleging that we and all major oil companies with operations in Pennsylvania, have damaged the groundwater by introducing thereto gasoline with MTBE. The Pennsylvania suit has been forwarded to the existing MTBE multidistrict litigation pending in the Southern District of New York. In December 2017, the State of Maryland filed a lawsuit alleging that we and other major oil companies damaged the groundwater in Maryland by introducing thereto gasoline with MTBE. The suit, filed in Maryland state court, was served on us in January 2018 and has been removed to federal court by the defendants. In March 2014, we received an Administrative Order from the EPA requiring us and 26 other parties to undertake the Remedial Design for the remedy selected by the EPA for the Gowanus Canal Superfund Site in Brooklyn, New York. Our alleged liability derives from our former ownership and operation of a fuel oil terminal and connected shipbuilding and repair facility adjacent to the Canal. The remedy selected by the EPA includes dredging of surface sediments and the placement of a cap over the deeper sediments throughout the Canal and in-situ stabilization of certain contaminated sediments that will remain in place below the cap. The EPA’s original estimate was that this remedy would cost $506 million; however, the ultimate costs that will be incurred in connection with the design and implementation of the remedy remain uncertain. We have complied with the EPA’s March 2014 Administrative Order and contributed funding for the Remedial Design based on an allocation of costs among the parties determined by a third-party expert. In January 2020, we received an additional Administrative Order from the EPA requiring us and several other parties to begin Remedial Action along the uppermost portion of the Canal. We intend to comply with this Administrative Order. The remediation work began in the fourth quarter of 2020. Based on currently known facts and circumstances, we do not believe that this matter will result in a significant liability to us, and the costs will continue to be allocated amongst the parties, as they were for the Remedial Design. From time to time, we are involved in other judicial and administrative proceedings relating to environmental matters. We periodically receive notices from the EPA that we are a “potential responsible party” under the Superfund legislation with respect to various waste disposal sites. Under this legislation, all potentially responsible parties may be jointly and severally liable. For any site for which we have received such a notice, the EPA’s claims or assertions of liability against us relating to these sites have not been fully developed, or the EPA’s claims have been settled or a settlement is under consideration, in all cases for amounts that are not material. Beginning in 2017, certain states, municipalities and private associations in California, Delaware, Maryland, Rhode Island and South Carolina separately filed lawsuits against oil, gas and coal producers, including us, for alleged damages purportedly caused by climate change. These proceedings include claims for monetary damages and injunctive relief. Beginning in 2013, various parishes in Louisiana filed suit against approximately 100 oil and gas companies, including us, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. The ultimate impact of such climate and other aforementioned environmental proceedings, and of any related proceedings by private parties, on our business or accounts cannot be predicted at this time due to the large number of other potentially responsible parties and the speculative nature of clean-up cost estimates. Hess Corporation and its subsidiary HONX, Inc. have been named as defendants in various personal injury claims alleging exposure to asbestos and/or other alleged toxic substances while working at a former refinery (owned and operated by subsidiaries or related entities) located in St. Croix, U.S. Virgin Islands. On April 28, 2022, HONX, Inc. initiated a Chapter 11 § 524G process in the United States Bankruptcy Court for the Southern District of Texas, Houston Division, to resolve these asbestos-related claims. In February 2023, Hess, HONX, Inc., the Unsecured Creditors’ Committee, and counsel representing claimants, reached a mediated resolution of the matter, contingent upon ongoing negotiations with the Future Claimants Representative (FCR), final approvals of all parties and confirmation by the Bankruptcy Court. As of December 31, 2023, following agreement with the FCR, we increased our reserve to a total of $153 million for the amounts expected to be funded to the § 524G trust established for the settlement of all current and future claims. The Bankruptcy Court and U.S. Federal District Court confirmed the HONX Bankruptcy Plan on February 16, 2024. We are also involved in six claims in federal and state courts in North Dakota related to post-production deductions from royalty and working interest payments. The plaintiffs in these cases assert that we take unauthorized or excessive post-production deductions from royalty or working interest payments for various oil and gas processing and transportation related costs and expenses. These plaintiffs seek reimbursement for allegedly underpaid revenue. It is our position that these costs and expenses are actual, reasonable, necessary, and authorized by the respective leases and North Dakota law. We believe that based on the facts and circumstances of these claims and because we have viable defenses, loss is not probable and the ultimate impact of these claims on our business or accounts cannot be estimated at this time due to the early stages of the proceedings and the speculative and indeterminate damages. We may also be exposed to future decommissioning liabilities for divested assets in the event the current or future owners of facilities previously owned by us are determined to be unable to perform such actions, whether due to bankruptcy or otherwise. We cannot predict with certainty if, how or when such proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages. Numerous issues may need to be resolved, including through potentially lengthy discovery and determination of important factual matters before a loss or range of loss can be reasonably estimated for any proceeding. Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of lawsuits, claims and proceedings, including the matters disclosed above, is not expected to have a material adverse effect on our financial condition, results of operations or cash flows. However, we could incur judgments, enter into settlements, or revise our opinion regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations in the period in which the amounts are accrued and our cash flows in the period in which the amounts are paid. Unconditional Purchase Obligations and Commitments The following table shows aggregate information for certain unconditional purchase obligations and commitments at December 31, 2023, which are not included elsewhere within these Consolidated Financial Statements : Payments Due by Period Total 2024 2025 2026 2027 2028 Thereafter (In millions) Capital expenditures $ 7,472 $ 2,371 $ 2,106 $ 1,757 $ 774 $ 371 $ 93 Operating expenses 762 238 107 55 50 63 249 Transportation and related contracts 2,243 298 260 286 277 261 861

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Segment Information	18. Segment Information We currently have two operating segments, E&P and Midstream. The E&P operating segment explores for, develops, produces, purchases and sells crude oil, NGL and natural gas. Production operations over the three years ended December 31, 2023 were in Guyana, the U.S., Malaysia and the JDA, Libya (sold in November 2022) and Denmark (sold in August 2021). The Midstream operating segment 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 of North Dakota. All unallocated costs are reflected under Corporate, Interest and Other. The following table presents operating segment financial data (in millions): Exploration and Production Midstream Corporate, Interest and Other Eliminations Total 2023 Sales and other operating revenues $ 10,500 $ 11 $ — $ — $ 10,511 Intersegment revenues — 1,338 — (1,338) — Total sales and other operating revenues $ 10,500 $ 1,349 $ — $ (1,338) $ 10,511 Net income (loss) attributable to Hess Corporation $ 1,601 $ 252 $ (471) $ — $ 1,382 Interest expense — 179 299 — 478 Depreciation, depletion and amortization 1,852 193 1 — 2,046 Impairment and other 82 — — — 82 Provision for income taxes 695 38 — — 733 Investment in affiliates 76 90 — — 166 Identifiable assets 17,931 3,984 2,092 — 24,007 Capital expenditures 4,033 246 — — 4,279 2022 Sales and other operating revenues $ 11,324 $ — $ — $ — $ 11,324 Intersegment revenues — 1,273 — (1,273) — Total sales and other operating revenues $ 11,324 $ 1,273 $ — $ (1,273) $ 11,324 Net income (loss) attributable to Hess Corporation $ 2,396 $ 269 $ (569) $ — $ 2,096 Interest expense — 150 343 — 493 Depreciation, depletion and amortization 1,520 181 2 — 1,703 Impairment and other 54 — — — 54 Provision for income taxes 1,072 27 — — 1,099 Investment in affiliates 88 94 1 — 183 Identifiable assets 15,022 3,775 2,898 — 21,695 Capital expenditures 2,589 232 — — 2,821 2021 Sales and other operating revenues $ 7,473 $ — $ — $ — $ 7,473 Intersegment revenues — 1,204 — (1,204) — Total sales and other operating revenues $ 7,473 $ 1,204 $ — $ (1,204) $ 7,473 Net income (loss) attributable to Hess Corporation $ 770 $ 286 $ (497) $ — $ 559 Interest expense — 105 376 — 481 Depreciation, depletion and amortization 1,361 166 1 — 1,528 Impairment and other 147 — — — 147 Provision for income taxes 585 15 — — 600 Capital expenditures 1,698 183 — — 1,881 Corporate, Interest and Other had interest income of $82 million in 2023 (2022: $32 million, 2021: $1 million) which is included in Other, net in the Statement of Consolidated Income. The following table presents financial information by major geographic area: United States Guyana Malaysia and JDA Other (a) Corporate, Interest and other Total (In millions) 2023 Sales and Other Operating Revenues $ 6,092 $ 3,494 $ 925 $ — $ — $ 10,511 Property, Plant and Equipment (Net) (b) 10,554 5,957 872 42 7 17,432 2022 Sales and Other Operating Revenues $ 7,214 $ 2,636 $ 873 $ 601 $ — $ 11,324 Property, Plant and Equipment (Net) (b) 9,937 4,042 1,065 46 8 15,098 2021 Sales and Other Operating Revenues $ 5,378 $ 754 $ 738 $ 603 $ — $ 7,473 (a) Other includes our interests in Libya (sold in November 2022), Denmark (sold in August 2021), Suriname and Canada. (b) Property, plant and equipment in the United States in 2023 includes $7,325 million (2022: $6,764 million) attributable to the E&P segment and $3,229 million (2022: $3,173 million) attributable to the Midstream segment.

Financial Risk Management Activ

Financial Risk Management Activities	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Financial Risk Management Activities	Financial Risk Management Activities In the normal course of our business, we are exposed to commodity risks related to changes in the prices of crude oil and natural gas, as well as changes in interest rates and foreign currency values. In the disclosures that follow, corporate financial risk management activities refer to the mitigation of these risks through hedging activities. We maintain a control environment for all of our financial risk management activities under the direction of our Chief Risk Officer. Our Treasury department is responsible for administering foreign exchange rate and interest rate hedging programs using similar controls and processes, where applicable. Hedging strategies are reviewed annually by the Audit Committee of the Board of Directors. Corporate Financial Risk Management Activities: Financial risk management activities include transactions designed to reduce risk in the selling prices of crude oil or natural gas we produce or reduce our exposure to foreign currency or interest rate movements. Generally, futures, swaps or option strategies may be used to fix the forward selling price, or establish a floor price or a range banded with a floor and ceiling price, for a portion of our crude oil or natural gas production. Forward contracts or swaps may also be used to purchase certain currencies in which we conduct business with the intent of reducing exposure to foreign currency fluctuations. At December 31, 2023, these forward contracts relate to the British Pound and Malaysian Ringgit. Interest rate swaps may be used to convert interest payments on certain long-term debt from fixed to floating rates. The notional amounts of outstanding financial risk management derivative contracts were as follows: December 31, 2023 December 31, 2022 (In millions) Foreign exchange forwards and swaps $ 226 $ 177 Interest rate swaps $ 100 $ 100 The table below reflects the gross and net fair values of risk management derivative instruments: Assets Liabilities (In millions) December 31, 2023 Derivative Contracts Designated as Hedging Instruments: Interest rate swaps $ — $ (2) Total derivative contracts designated as hedging instruments — (2) Derivative Contracts Not Designated as Hedging Instruments: Foreign exchange forwards and swaps — (6) Total derivative contracts not designated as hedging instruments — (6) Gross fair value of derivative contracts — (8) Gross amount offset in the Consolidated Balance Sheet — — Net Amounts Presented in the Consolidated Balance Sheet $ — $ (8) December 31, 2022 Derivative Contracts Designated as Hedging Instruments: Interest rate swaps — (4) Total derivative contracts designated as hedging instruments — (4) Derivative Contracts Not Designated as Hedging Instruments: Foreign exchange forwards and swaps — (2) Total derivative contracts not designated as hedging instruments — (2) Gross fair value of derivative contracts — (6) Gross amount offset in the Consolidated Balance Sheet — — Net Amounts Presented in the Consolidated Balance Sheet $ — $ (6) At December 31, 2023 and 2022, the fair value of our interest rate swaps is presented within Accrued liabilities and Other liabilities and deferred credits , respectively, in our Consolidated Balance Sheet . The fair value of our foreign exchange forwards and swaps is presented within Accrued liabilities in our Consolidated Balance Sheet . All fair values in the table above are based on Level 2 inputs. Crude oil price hedging contracts decreased Sales and other operating revenues by $190 million in 2023 (2022: decrease of $585 million; 2021: decrease of $243 million). The change in fair value of interest rate swaps was an increase of $2 million in 2023 (2022: $6 million decrease; 2021: $3 million decrease) with a corresponding adjustment in the carrying value of the hedged fixed‑rate debt. We recognized net foreign exchange gains of $4 million in 2023 (2022: $16 million losses; 2021: $3 million losses). Offsetting these net foreign exchange gains were net losses from our foreign exchange derivative contracts, that are not designated as hedges, of $2 million in 2023 (2022: $14 million gains; 2021: $1 million gains). Foreign exchange gains and losses, and the gains and losses on our foreign exchange derivative contracts, are recorded in Other, net in the Statement of Consolidated Income . Credit Risk: We are exposed to credit risks that may at times be concentrated with certain counterparties, groups of counterparties or customers. Accounts receivable are generated from a diverse domestic and international customer base. At December 31, 2023, our accounts receivable were concentrated with the following counterparty industry segments: Integrated companies 40%, Independent E&P companies 37%, Refining and marketing companies 12%, Storage and transportation companies 4%, National oil companies 1%, and Others 6%. We reduce risk related to certain counterparties, where applicable, by using master netting arrangements and requiring collateral, generally cash or letters of credit. At December 31, 2023, we had outstanding letters of credit totaling $88 million (2022: $83 million). Fair Value Measurement: At December 31, 2023, our total long-term debt, which was substantially comprised of fixed rate debt instruments, had a carrying value of $8,613 million and a fair value of $9,006 million, based on Level 2 inputs in the fair value measurement hierarchy. We also have short-term financial instruments, primarily cash equivalents, accounts receivable and accounts payable, for which the carrying value approximated fair value at December 31, 2023 and December 31, 2022.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2023
Subsequent Events [Abstract]
Subsequent Event	20. Subsequent Event In February 2024, Hess Midstream LP completed an underwritten public equity offering of 11.5 million Hess Midstream LP Class A shares held by an affiliate of GIP. Hess did not receive any proceeds from this transaction. After giving effect to this transaction, public shareholders of Class A shares of Hess Midstream LP own approximately 35%, GIP owns approximately 27%, and Hess owns approximately 38% of the consolidated entity on an as-exchanged basis.

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net income (loss) attributable to Hess Corporation	$ 1,382	$ 2,096	$ 559

Insider Trading Arrangements

Insider Trading Arrangements	12 Months Ended
	Dec. 31, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Nature of Operations, Basis o_2

Nature of Operations, Basis of Presentation and Summary of Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation and Principles of Consolidation	Basis of Presentation and Principles of Consolidation: The consolidated financial statements include the accounts of Hess Corporation and entities in which we own more than a 50% voting interest. We consolidate Hess Midstream LP, a variable interest entity, based on our conclusion that we have the power through Hess Corporation’s approximate 38% consolidated ownership interest in Hess Midstream LP to direct those activities that most significantly impact the economic performance of Hess Midstream LP , and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to Hess Midstream LP . Our undivided interests in unincorporated oil and gas E&P ventures are proportionately consolidated. Investments in affiliated companies, 20% to 50% owned and where we have the ability to influence the operating or financial decisions of the affiliate, are accounted for using the equity method.
Estimates and Assumptions	Estimates and Assumptions: In preparing financial statements in conformity with GAAP, management makes estimates and assumptions that affect the reported amounts of assets and liabilities in the Consolidated Balance Sheet and revenues and expenses in the Statement of Consolidated Income . Actual results could differ from those estimates. Estimates made by management include oil and gas reserves, asset and other valuations, depreciable lives, post-retirement liabilities, legal and environmental obligations, asset retirement obligations and income taxes.
Revenue Recognition	Revenue Recognition: Exploration and Production The E&P segment recognizes revenue from the sale of crude oil, NGL, and natural gas as performance obligations under contracts with customers are satisfied. Our responsibilities to deliver each unit of quantity of crude oil, NGL, and natural gas under these contracts represent separate, distinct performance obligations. These performance obligations are satisfied at the point in time control of each unit of quantity transfers to the customer. Generally, the control of each unit of quantity transfers to the customer upon the transfer of legal title at the point of physical delivery. Pricing is variable and is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials. For long-term international natural gas contracts with ship-or-pay provisions, our obligation to stand-ready to provide a minimum volume over each commitment period represents separate, distinct performance obligations. Penalties owed against future deliveries of natural gas due to delivery of volumes below minimum delivery commitments are recognized as reductions to revenue in the commitment period when the shortfall occurs. Long-term international natural gas contracts may also contain take-or-pay provisions whereby the customer is required to pay for volumes not taken that are below minimum volume commitments, but the customer has certain make-up rights to receive shortfall volumes in subsequent periods. Shortfall payments received from customers when volumes purchased are below the minimum volume commitment are deferred upon receipt as a contract liability. Revenue is recognized at the earlier of when we deliver the make-up volumes in subsequent periods or when it becomes remote that the customer will exercise their make-up rights. Certain crude oil, NGL, and natural gas volumes are purchased by Hess from third parties, including working interest partners and royalty owners in certain Hess-operated properties, before they are sold to customers. Where control over the crude oil, NGL, or natural gas transfers to Hess before the volumes are transferred to the customer, revenue and the associated cost of purchased volumes are presented on a gross basis in the Statement of Consolidated Income within Sales and other operating revenues and Marketing, including purchased oil and gas , respectively. Where control of crude oil, NGL, or natural gas is not transferred to Hess, revenue is presented net of the associated cost of purchased volumes within Sales and other operating revenues in the S tatement of Consolidated Income . Contract Duration and Pricing: Contracts with customers for the sale of U.S. crude oil, NGL, and natural gas primarily include those contracts that involve the short-term sale of volumes during a specified period, and those contracts that automatically renew on a periodic basis until either party cancels. We have certain long-term contracts with customers for the sale of U.S. natural gas and NGL that have remaining durations ranging from one Contracts with customers for the sale of international crude oil involve the short-term sale of volumes during a specified period. Pricing is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials, shortly after control of the volumes transfers to the customer. International contracts with customers for the sale of natural gas are in the form of natural gas sales agreements with government entities that have durations that are aligned with the durations of production sharing contracts or other contractual arrangements with host governments. Pricing for our natural gas sales agreements in North Malay Basin and Block A-18 of JDA are determined using contractual formulas that are based on the price of alternative fuels as obtained from price indices and other factors. Contract Balances: Our right to receive or collect payment from the customer is aligned with the timing of revenue recognition except in situations when we receive shortfall payments under contracts with take-or-pay provisions with customer make-up rights. Generally, we receive payments from customers on a monthly basis, shortly after the physical delivery of the crude oil, NGL, or natural gas. At December 31, 2023, there were no contract liabilities. At December 31, 2022, there were contract liabilities of $24 million resulting from a take-or-pay deficiency payment received in 2021 that was subject to a make-up period expiring in December 2023. During the year ended December 31, 2023, revenue of $24 million was recognized within Sales and other operating revenues that was included in the contract liability balance at December 31, 2022. At December 31, 2023 and 2022, there were no contract assets. Transaction Price Allocated to Remaining Performance Obligations: The transaction price allocated to our wholly unsatisfied performance obligations on uncompleted contracts is variable. Further, many of our contracts with customers have durations of less than twelve months. Accordingly, we have elected under the provisions of Accounting Standards Codification (ASC) 606, Revenues from Contracts with Customers, the exemption from disclosure of revenue recognizable in future periods as these performance obligations are satisfied. Sales-based Taxes: We exclude sales-based taxes that are collected from customers from the transaction price in our contracts with customers. Accordingly, revenue from contracts with customers is net of sales-based taxes that are collected from customers and remitted to taxing authorities. Revenue from Non-customers: In Guyana, the joint venture partners (Co-Venturers) to the Stabroek Block petroleum agreement are subject to the income tax laws of Guyana and remain primarily liable for income taxes due on the results of operations, resulting in recognition of income tax expense. Pursuant to the contractual arrangements of the petroleum agreement, a portion of gross production from the block, separate from the 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 included in our reported production volumes and is recognized as sales revenue from non-customers. Midstream 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 LP 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 ten 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 Midstream segment ’ s responsibility to provide each service for each year under each of the commercial agreements are considered separate, distinct performance obligations. Revenue is recognized over-time for each performance obligation as services are rendered using the output method, measured using the amount of volumes serviced during the period. The commercial agreements contain minimum volume commitments which fluctuate based on nominations covering substantially all of our E&P segment's existing and future owned or controlled production in the Bakken and projected third-party volumes owned or controlled by our 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. As the minimum volume commitments are subject to fluctuation, and these commercial agreements contain fee inflation escalators and fee recalculation mechanisms, substantially all of the transaction price is variable at inception of each of the commercial agreements. The Midstream segment has elected the practical expedient under the provisions of Accounting Standards Codification (ASC) 606 , Revenue from Contracts with Customers to recognize revenue in the amount it is entitled to invoice. If the volumes delivered are less than the applicable minimum volume commitments under the commercial agreements during any quarter, the applicable Hess subsidiary is obligated to pay a shortfall fee equal to the volume deficiency multiplied by the related gathering, processing and/or terminaling fee. The Midstream segment ’ s responsibility to stand-ready to service a minimum volume over each quarterly commitment period represents a separate, distinct performance obligation. During the initial term of each commercial agreement, volume deficiencies are measured quarterly and recognized as revenue in the same period, as 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, calculated in barrels or Mcf, as applicable, 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. Unused credits will be recognized as revenue when it becomes remote that such credits will be utilized. 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. All revenues, receivables, and contract balances arising from the commercial agreements between the Midstream segment and the Hess subsidiaries that are the counterparty to the commercial agreements are eliminated upon consolidation.
Exploration and Development Costs	Exploration and Development Costs: E&P activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized. The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of a project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors, firm plans for additional drilling and other factors.
Depreciation, Depletion and Amortization	Depreciation, Depletion and Amortization: We record depletion expense for acquisition costs of proved properties using the units of production method over proved oil and gas reserves. Depreciation and depletion expense for oil and gas production facilities and wells is calculated using the units of production method over proved developed oil and gas reserves. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors. Depreciation of all other plant and equipment is determined on the straight-line method based on estimated useful lives.
Capitalized Interest	Capitalized Interest: Interest from external borrowings is capitalized on material projects using the weighted average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at first production from the field. Capitalized interest is depreciated in the same manner as the depreciation of the underlying assets.
Impairment of Long-lived Assets	Impairment of Long‑lived Assets: We review long‑lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts of the long-lived assets are not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is measured based on the estimated fair value of the assets generally determined by discounting anticipated future net cash flows, an income valuation approach, or by a market‑based valuation approach, which are Level 3 fair value measurements. In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a projected amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairment will generally differ from those used in the standardized measure of discounted future net cash flows reported in Supplementary Oil and Gas Data , since the standardized measure requires the use of historical twelve-month average prices.
Impairment of Goodwill	Impairment of Goodwill: Goodwill is tested for impairment annually on October 1 st or when events or circumstances indicate it is more likely than not that the fair value of the reporting unit is less than its carrying value, including goodwill. If the fair value of the reporting unit exceeds its carrying value, goodwill is not impaired. If the carrying value of the reporting unit exceeds its fair value, an impairment loss would be recorded for the excess of the carrying value over fair value, limited by the amount of goodwill allocated to the reporting unit. At December 31, 2023, goodwill of $360 million relates to the Midstream operating segment.
Cash and Cash Equivalents	Cash and Cash Equivalents: Cash and cash equivalents primarily comprises cash on hand and on deposit, as well as highly liquid investments that are readily convertible into cash and have maturities of three months or less when acquired.
Inventories	Inventories: Produced and unsold crude oil and NGL are valued at the lower of cost or net realizable value. Cost is determined using the average cost of production plus any transport cost incurred in bringing the volumes to their present location. Materials and supplies are valued at cost. Obsolete or surplus materials identified during periodic reviews are valued at the lower of cost or estimated net realizable value.
Leases	Leases: We determine if an arrangement is a lease at inception by evaluating whether the contract conveys the right to control an identified asset during the period of use. ROU assets represent our right to use an identified asset for the lease term and lease obligations represent our obligation to make payments as set forth in the lease arrangement. ROU assets and lease liabilities are recognized in the Consolidated Balance Sheet as operating leases or finance leases at the commencement date based on the present value of the minimum lease payments over the lease term. Where the implicit discount rate in a lease is not readily determinable, we use our incremental borrowing rate based on information available at the commencement date for determining the present value of the minimum lease payments. The lease term used in measurement of our lease obligations includes options to extend or terminate the lease when, in our judgment, it is reasonably certain that we will exercise that option. Variable lease payments that depend on an index or a rate are included in the measurement of lease obligations using the index or rate at the commencement date. Variable lease payments that vary because of changes in facts or circumstances after the commencement date of the lease are not included in the minimum lease payments used to measure lease obligations. We have agreements that include financial obligations for lease and nonlease components. For purposes of measuring lease obligations, we have elected not to separate nonlease components from lease components for the following classes of assets: drilling rigs, office space, offshore vessels, and aircraft. We apply a portfolio approach to account for operating lease ROU assets and liabilities for certain vehicles, railcars, field equipment and office equipment leases. Finance lease cost is recognized as amortization of the ROU asset and interest expense on the lease liability. Operating lease cost is generally recognized on a straight-line basis. Operating lease costs for drilling rigs used to drill development wells and successful exploration wells are capitalized. Operating lease cost for other ROU assets used in oil and gas producing activities are either capitalized or expensed based on the nature of operation for which the ROU asset is utilized. Leases with an initial term of 12 months or less are not recorded on the balance sheet as permitted under ASC 842, Leases . We recognize lease cost for short-term leases on a straight-line basis over the term of the lease. Some of our leases with initial terms of 12 months or less include one or more options to renew. The renewal option is at our sole discretion and is not included in the lease term for measurement of the lease obligation unless we are reasonably certain at the commencement date of the lease, to renew the lease.
Income Taxes	Income Taxes: Deferred income taxes are determined using the liability method. We have net operating loss carryforwards or credit carryforwards in multiple jurisdictions and have recognized deferred tax assets for those losses and credits. Additionally, we have deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If, when tested under the relevant accounting standards, it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is established to reduce the deferred tax assets to the amount that is expected to be realized. The accounting standards require the evaluation of all available positive and negative evidence giving weight based on the evidence’s relative objectivity. In evaluating potential sources of positive evidence, we consider the reversal of taxable temporary differences, taxable income in carryback and carryforward periods, the availability of tax planning strategies, the existence of appreciated assets, estimates of future taxable income, and other factors. In evaluating potential sources of negative evidence, we consider a cumulative loss in recent years, any history of operating losses or tax credit carryforwards expiring unused, losses expected in early future years, unsettled circumstances that, if unfavorably resolved, would adversely affect future operations and profit levels on a continuing basis in future years, and any carryback or carryforward period so brief that a significant deductible temporary difference expected to reverse in a single year would limit realization of tax benefits. We assign cumulative historical losses significant weight in the evaluation of realizability relative to more subjective evidence such as forecasts of future income. In addition, we recognize the financial statement effect of a tax position only when management believes that it is more likely than not, that based on the technical merits, the position will be sustained upon examination. We are not indefinitely reinvested with respect to the book in excess of tax basis in the investment in our foreign subsidiaries. Because of U.S. tax reform we expect that the future reversal of such temporary differences will occur free of material taxation. We classify interest and penalties associated with uncertain tax positions as income tax expense. We account for the U.S. tax effect of global intangible low-taxed income earned by foreign subsidiaries in the period that such income is earned. We utilize the aggregate approach for releasing disproportionate income tax effects from Accumulated other comprehensive income (loss) .
Asset Retirement Obligations	Asset Retirement Obligations: We have legal obligations to remove and dismantle long‑lived assets and to restore land or the seabed at certain E&P locations. We initially recognize a liability for the fair value of legally required asset retirement obligations in the period in which the retirement obligations are incurred and capitalize the associated asset retirement costs as part of the carrying amount of the long‑lived assets. In subsequent periods, the liability is accreted over the useful life of the related asset, and the capitalized asset retirement costs are depreciated over proved developed oil and gas reserves using the units of production method or the useful life of the related asset. Fair value is determined by applying a credit adjusted risk-free rate to the undiscounted expected future abandonment expenditures. Changes in estimates prior to settlement result in adjustments to both the liability and related asset values, unless the field has ceased production, in which case changes are recognized in the Statement of Consolidated Income . We measure asset retirement obligations based on the requirements of existing laws and regulations in accordance with ASC 410-20, Asset Retirement Obligations . Laws and regulations associated with the scope and timing for the abandonment of oil and gas wells, facilities and equipment could change which could increase the cost of our abandonment obligations. In addition, we may be required to assume abandonment obligations for certain divested assets in the event the current or future owners of facilities previously owned by us are unable to perform, whether due to bankruptcy or otherwise.
Retirement Plans	Retirement Plans: We recognize the funded status of defined benefit postretirement plans in the Consolidated Balance Sheet . The funded status is measured as the difference between the fair value of plan assets and the projected benefit obligation. We recognize the net changes in the funded status of these plans as a component of Other Comprehensive Income (Loss) in the year in which such changes occur. Actuarial gains and losses in excess of 10% of the greater of the benefit obligation or the market value of plan assets are amortized over the average remaining service period of active employees or the remaining average expected life if a plan’s participants are predominantly inactive.
Derivatives	Derivatives: We utilize derivative instruments for financial risk management activities. In these activities, we may use futures, forwards, options and swaps, individually or in combination, to mitigate our exposure to fluctuations in prices of crude oil and natural gas, as well as changes in interest and foreign currency exchange rates. All derivative instruments are recorded at fair value in the Consolidated Balance Sheet . Our policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not designated as hedges are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges), or hedges of changes in fair value of recognized assets and liabilities or of unrecognized firm commitments (fair value hedges). Changes in fair value of derivatives that are designated as cash flow hedges are recorded as a component of Other Comprehensive Income (Loss) . Amounts included in Accumulated Other Comprehensive Income (Loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged item is recorded as an adjustment to its carrying amount and recognized currently in earnings.
Fair Value Measurements	Fair Value Measurements: We use various valuation approaches in determining fair value for financial instruments, including the market and income approaches. Our fair value measurements also include non-performance risk and time value of money considerations. Counterparty credit is considered for financial assets, and our credit is considered for financial liabilities. We also record certain nonfinancial assets and liabilities at fair value when required by GAAP. These fair value measurements are recorded in connection with business combinations, qualifying nonmonetary exchanges, the initial recognition of asset retirement obligations and any impairment of long‑lived assets, equity method investments, goodwill or other indefinite-lived intangible assets, such as environmental credits. We determine fair value in accordance with the fair value measurements accounting standard which established a hierarchy for the inputs used to measure fair value based on the source of the inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3), including discounted cash flows and other unobservable data. Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market. Multiple inputs may be used to measure fair value; however, the level assigned to a fair value measurement is based on the lowest significant input level within this fair value hierarchy. Details on the methods and assumptions used to determine the fair values are as follows: Fair value measurements based on Level 1 inputs: Measurements that are most observable are based on quoted prices of identical instruments obtained from the principal markets in which they are traded. Closing prices are both readily available and representative of fair value. Market transactions occur with sufficient frequency and volume to assure liquidity. Fair value measurements based on Level 2 inputs: Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. Measurements based on Level 2 inputs include over-the-counter derivative instruments that are priced on an exchange-traded curve but have contractual terms that are not identical to exchange-traded contracts. Fair value measurements based on Level 3 inputs: Measurements that are least observable are estimated from related market data, determined from sources with little or no market activity for comparable contracts or are positions with longer durations. Fair values determined using discounted cash flows and other unobservable data are also classified as Level 3.
Netting of Financial Instruments	Netting of Financial Instruments: We generally enter into master netting arrangements to mitigate legal and counterparty credit risk. Master netting arrangements are generally accepted overarching master contracts that govern all individual transactions with the same counterparty entity as a single legally enforceable agreement. The U.S. Bankruptcy Code provides for the enforcement of certain termination and netting rights under certain types of contracts upon the bankruptcy filing of a counterparty, commonly known as the “safe harbor” provisions. If a master netting arrangement provides for termination and netting upon the counterparty’s bankruptcy, these rights are generally enforceable with respect to “safe harbor” transactions. If these arrangements provide the right of offset and our intent and practice is to offset amounts in the case of such a termination, our policy is to record the fair value of derivative assets and liabilities on a net basis. In the normal course of business, we rely on legal and credit risk mitigation clauses providing for adequate credit assurance as well as close‑out netting, including two‑party netting and single counterparty multilateral netting. As applied to us, “two‑party netting” is the right to net amounts owing under safe harbor transactions between a single defaulting counterparty entity and a single Hess entity, and “single counterparty multilateral netting” is the right to net amounts owing under safe harbor transactions among a single defaulting counterparty entity and multiple Hess entities. We are reasonably assured that these netting rights would be upheld in a bankruptcy proceeding in the U.S. in which the defaulting counterparty is a debtor under the U.S. Bankruptcy Code.
Share-based Compensation	Share-based Compensation: We account for share-based compensation based on the fair value of the award on the date of grant. The fair value of all share‑based compensation is recognized over the requisite service period for the entire award, whether the award was granted with ratable or cliff vesting terms, net of actual forfeitures. We estimate fair value at the date of grant using a Black‑Scholes valuation model for employee stock options and a Monte Carlo simulation model for performance share units (PSUs). Fair value of restricted stock is based on the market value of the underlying shares at the date of grant.
Foreign Currency Translation	Foreign Currency Remeasurement: The U.S. Dollar is the functional currency (primary currency in which business is conducted) for our foreign operations. Adjustments resulting from remeasuring monetary assets and liabilities that are denominated in a currency other than the functional currency are recorded in Other, net in the Statement of Consolidated Income .
Maintenance and Repairs	Maintenance and Repairs: Maintenance and repairs are expensed as incurred. Capital improvements are recorded as additions in Property, plant and equipment .
Environmental Expenditures	Environmental Expenditures:
Environmental Credits	Environmental Credits: Carbon credits and renewable energy certificates are purchased to fulfill voluntary emissions reduction targets and are classified as indefinite-lived intangible assets. They are expensed when retired to offset emissions and are tested for impairment annually on October 1 st, or when events or circumstances indicate it is more likely than not that fair value is less than carrying value. If the carrying value exceeds fair value, an impairment loss would be recorded for the excess of the carrying value over fair value. In response to feedback from constituents and the staff ’ s related research and analysis, the Financial Accounting Standards Board (FASB) added a project to its technical agenda on May 25, 2022 to address the accounting for environmental credits due to a lack of existing guidance for accounting for environmental credits. Our environmental credits fall within the scope of this project. Included among the tentative decisions made by the FASB on January 31, 2024, is a prohibition against capitalizing the cost of environmental credits that will not be sold or used to settle environmental credit obligations. In 2023, we purchased $75 million REDD+ carbon credits (2022: $75 million, 2021: $0 million) under a long-term agreement with the Government of Guyana that was executed in December 2022 in order to support ongoing carbon emissions reduction efforts by the Corporation. The carbon credits acquired by us are registered on the ART Registry, an over-the-counter registry, and can be sold to third parties or retired to offset emissions. These amounts would have been expensed in the period of purchase, instead of capitalized as indefinite-lived intangible assets, if the prohibition per the tentative decision above were applied. At December 31, 2023, the carrying value of our carbon credits of $150 million (2022: $75 million) is included in non-current Other assets in the Consolidated Balance Sheet . All renewable energy certificates were retired and expensed in the period of purchase.
New Accounting Pronouncements	New Accounting Pronouncements: In November 2023, the FASB issued Accounting Standards Update (ASU) No. 2023-07, Improvements to Reportable Segments Disclosures . The ASU improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The ASU does not change how an entity identifies its operating segments. The ASU is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. We are currently assessing the impact of adopting the ASU on our consolidated financial statements. In December 2023, the FASB issued ASU No. 2023-09, Improvements to Income Tax Disclosures

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2023
Inventory Disclosure [Abstract]
Schedule of Inventories	Inventories at December 31 were as follows: 2023 2022 (In millions) Crude oil and natural gas liquids $ 72 $ 63 Materials and supplies 232 154 Total Inventories $ 304 $ 217

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Components of Property, Plant and Equipment	Property, plant and equipment at December 31 were as follows: 2023 2022 (In millions) Exploration and Production Unproved properties $ 103 $ 149 Proved properties 2,660 2,660 Wells, equipment and related facilities 29,159 25,182 31,922 27,991 Midstream 4,819 4,571 Corporate and Other 30 30 Total — at cost 36,771 32,592 Less: Reserves for depreciation, depletion, amortization and lease impairment 19,339 17,494 Property, Plant and Equipment — Net $ 17,432 $ 15,098
Net Changes in Capitalized Exploratory Well Costs	Capitalized Exploratory Well Costs : The following table discloses the amount of capitalized exploratory well costs pending determination of proved reserves at December 31 and the changes therein during the respective years: 2023 2022 2021 (In millions) Balance at January 1 $ 886 $ 681 $ 459 Additions to capitalized exploratory well costs pending the determination of proved reserves 257 298 222 Reclassifications to wells, facilities and equipment based on the determination of proved reserves (133) (93) — Capitalized exploratory well costs charged to expense (58) — — Balance at December 31 $ 952 $ 886 $ 681 Number of Wells at December 31 43 43 35
Exploratory Drilling Costs Capitalized	Exploratory well costs capitalized for greater than one year following completion of drilling were $728 million at December 31, 2023, separated by year of completion as follows (in millions): 2022 $ 261 2021 162 2020 8 2019 139 2018 and prior 158 $ 728

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2023
Payables and Accruals [Abstract]
Schedule of Accrued Liabilities	The following table provides detail of our accrued liabilities at December 31: 2023 2022 (In millions) Accrued capital expenditures $ 670 $ 499 Accrued operating and marketing expenditures 593 522 Accrued compensation and benefits 193 132 Accrued payments to royalty and working interest owners 178 201 Current portion of asset retirement obligations 160 207 Accrued interest on debt 144 143 Other accruals 164 136 Total Accrued Liabilities $ 2,102 $ 1,840

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Balance Sheet Information Related to Operating & Finance Leases	Operating and finance lease obligations at December 31 included in the Consolidated Balance Sheet were as follows: Operating Leases Finance Leases 2023 2022 2023 2022 (In millions) Right-of-use assets — net (a) $ 720 $ 570 $ 108 $ 126 Lease obligations: Current $ 347 $ 200 $ 23 $ 21 Long-term 459 469 156 179 Total lease obligations $ 806 $ 669 $ 179 $ 200 (a) At December 31, 2023, finance lease ROU assets had a cost of $212 million (2022: $212 million) and accumulated amortization of $104 million (2022: $86 million).
Maturity Profile of Lease Obligations	Maturities of lease obligations at December 31, 2023 were as follows: Operating Leases Finance (In millions) 2024 $ 377 $ 36 2025 197 36 2026 89 31 2027 48 22 2028 22 23 Remaining years 165 99 Total lease payments 898 247 Less: Imputed interest (92) (68) Total lease obligations $ 806 $ 179
Term & Rate Information Related to Operating & Finance Leases	The following information relates to the operating and finance leases at December 31: Operating Leases Finance Leases 2023 2022 2023 2022 Weighted average remaining lease term 5.0 years 6.8 years 9.8 years 10.8 years Range of remaining lease terms 0.1 - 12.5 years 0.3 - 13.5 years 9.8 years 10.8 years Weighted average discount rate 5.1% 4.5% 7.9% 7.9%
Components of Lease Costs	The components of lease costs were as follows: 2023 2022 2021 (In millions) Operating lease cost (a) $ 241 $ 114 $ 88 Finance lease cost: Amortization of leased assets 18 18 24 Interest on lease obligations 15 18 18 Short-term lease cost (b) 294 311 137 Variable lease cost (c) 67 33 21 Sublease income (d) (19) (18) (17) Total lease cost $ 616 $ 476 $ 271 (a) Operating lease cost in 2023 included a drilling rig at North Malay Basin used for a 15 well development drilling program spanning 2023 and 2024, and offshore support vessels in the Gulf of Mexico. (b) Short-term lease cost is primarily attributable to equipment used in global exploration, development, production, and crude oil marketing activities. Future short-term lease costs will vary based on activity levels of our operated assets. In 2023 and 2022, short-term lease cost included drilling rigs and offshore support vessels used primarily for exploration and abandonment activities in the Gulf of Mexico and workover rigs for maintenance activities in the Bakken. (c) Variable lease costs for drilling rigs result from differences in the minimum rate and the actual usage of the ROU asset during the lease period. Variable lease costs for logistical assets result from differences in stated monthly rates and total charges reflecting the actual usage of the ROU asset during the lease period. Variable lease costs for our office leases represent common area maintenance charges which have not been separated from lease components. (d) We sublease certain of our office space to third parties under our head lease.
Supplemental Cash Flow Information Related to Leases	Supplemental cash flow information related to leases were as follows: Operating Leases Finance Leases 2023 2022 2021 2023 2022 2021 (In millions) Cash paid for amounts included in the measurement of lease obligations: Operating cash flows (a) $ 254 $ 126 $ 87 $ 15 $ 18 $ 18 Financing cash flows (a) — — — 21 19 18 Noncash transactions: Leased assets recognized for new lease obligations incurred (b) 267 294 12 — — — Changes in leased assets and lease obligations due to lease modifications (c) 97 16 29 — — — (a) Amounts represent gross lease payments before any recovery from partners. (b) In 2023, primarily related to leases for a drilling rig and offshore support vessels in the Gulf of Mexico. In 2022, primarily related to leases for drilling rigs in the Bakken and at North Malay Basin. (c)

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Components of Debt	Total debt at December 31 consisted of the following: 2023 2022 (In millions) Debt – Hess Corporation: Senior unsecured fixed-rate public notes: 3.500% due 2024 $ 300 $ 300 4.300% due 2027 997 996 7.875% due 2029 465 464 7.300% due 2031 629 629 7.125% due 2033 537 537 6.000% due 2040 743 742 5.600% due 2041 1,238 1,237 5.800% due 2047 495 494 Total senior unsecured fixed-rate public notes 5,404 5,399 Fair value adjustments – interest rate hedging (2) (4) Total Debt – Hess Corporation $ 5,402 $ 5,395 Debt – Midstream (Hess Midstream Operations LP): Senior unsecured fixed-rate public notes: 5.625% due 2026 $ 795 $ 793 5.125% due 2028 545 544 4.250% due 2030 742 740 5.500% due 2030 395 395 Total senior unsecured fixed-rate public notes 2,477 2,472 Term Loan A facility 394 396 Revolving credit facility 340 18 Total Debt – Midstream $ 3,211 $ 2,886 Total Debt: Current portion of long-term debt $ 311 $ 3 Long-term debt 8,302 8,278 Total Debt $ 8,613 $ 8,281
Maturity Profile of Debt	At December 31, 2023, the maturity profile of total debt was as follows: Total Hess Midstream (In millions) 2024 $ 311 $ 298 $ 13 2025 22 — 22 2026 832 — 832 2027 1,670 1,000 670 2028 550 — 550 Thereafter 5,290 4,140 1,150 Total Borrowings 8,675 5,438 3,237 Less: Deferred financing costs and discounts (62) (36) (26) Total Debt (excluding interest) $ 8,613 $ 5,402 $ 3,211
Other Outstanding Letters of Credit	Other outstanding letters of credit at December 31 were as follows: 2023 2022 (In millions) Committed lines (a) $ 2 $ — Uncommitted lines (a) 86 83 Total $ 88 $ 83 (a) At December 31, 2023, committed and uncommitted lines have expiration dates through 2024.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Changes to Asset Retirement Obligations	The following table describes the changes in our asset retirement obligations for the years ended December 31: 2023 2022 (In millions) Balance at January 1 $ 1,241 $ 1,190 Liabilities incurred 135 126 Liabilities settled or disposed of (a) (240) (213) Accretion expense 61 48 Revisions of estimated liabilities 148 92 Foreign currency remeasurement 1 (2) Balance at December 31 $ 1,346 $ 1,241 Total Asset Retirement Obligations at December 31: Current portion of asset retirement obligations $ 160 $ 207 Long-term asset retirement obligations 1,186 1,034 Total at December 31 $ 1,346 $ 1,241

Retirement Plans (Tables)

Retirement Plans (Tables)	12 Months Ended
	Dec. 31, 2023
Retirement Benefits [Abstract]
Change in Benefit Obligation, Fair Value of Plan Assets & Funded Status of Pension Plans & Postretirement Medical Plan	The following table summarizes the benefit obligations, the fair value of plan assets, and the funded status of our pension and postretirement medical plans: Funded Unfunded Postretirement 2023 2022 2023 2022 2023 2022 (In millions) Change in Benefit Obligation Balance at January 1, $ 1,802 $ 2,948 $ 212 $ 248 $ 52 $ 59 Service cost 26 33 9 11 3 3 Interest cost 88 66 9 3 2 1 Actuarial (gain) loss (a) 44 (818) 7 (38) 1 (7) Plan settlements (143) (266) — — — — Benefit payments (77) (90) (15) (12) (5) (4) Foreign currency exchange rate changes 20 (71) — — — — Balance at December 31, (b) $ 1,760 $ 1,802 $ 222 $ 212 $ 53 $ 52 Change in Fair Value of Plan Assets Balance at January 1, $ 2,450 $ 3,357 $ — $ — $ — $ — Actual return on plan assets 186 (469) — — — — Employer contributions 1 1 15 12 5 4 Plan settlements (143) (266) — — — — Benefit payments (77) (90) (15) (12) (5) (4) Foreign currency exchange rate changes 28 (83) — — — — Balance at December 31, $ 2,445 $ 2,450 $ — $ — $ — $ — Funded Status (Plan assets greater (less) than benefit obligations) at December 31, $ 685 $ 648 $ (222) $ (212) $ (53) $ (52) Unrecognized Net Actuarial (Gains) Losses (c) $ 332 $ 337 $ 30 $ 23 $ (25) $ (27) (a) In 2023, changes in discount rates resulted in actuarial losses of $56 million, updates to census data resulted in actuarial losses of $18 million, and the alignment of the projected benefit obligation to the amount of plan settlement payments resulted in actuarial gains of $20 million. Changes in all other assumptions resulted in net actuarial gains of $2 million in 2023. In 2022, changes in discount rates resulted in actuarial gains of $874 million and changes in mortality assumptions resulted in actuarial losses of $8 million. Changes in all other assumptions, including inflation and demographic assumptions, resulted in net actuarial losses of $3 million in 2022. (b) At December 31, 2023, the accumulated benefit obligation for the funded and unfunded defined benefit pension plans was $1,684 million and $181 million, respectively (2022: $1,743 million and $180 million, respectively). (c) At December 31, 2023, the unrecognized net actuarial losses related to the U.K. pension plan was $179 million (2022: $175 million).
Amounts Recognized in Balance Sheet for Pension Plans & Postretirement Medical Plan	Amounts recognized in the Consolidated Balance Sheet at December 31 consisted of the following: Funded Unfunded Postretirement 2023 2022 2023 2022 2023 2022 (In millions) Noncurrent assets $ 685 $ 648 $ — $ — $ — $ — Current liabilities — — (23) (24) (5) (6) Noncurrent liabilities — — (199) (188) (48) (46) Post-retirement benefit assets / (liabilities) $ 685 $ 648 $ (222) $ (212) $ (53) $ (52) Accumulated other comprehensive (income) loss, pre-tax (a) $ 332 $ 337 $ 30 $ 23 $ (25) $ (27) (a) The after‑tax deficit reflected in Accumulated other comprehensive income (loss) was $134 million at December 31, 2023 (2022: $131 million deficit).
Components of Net Periodic Benefit Cost for Pension Plans & Postretirement Medical Plan	The net periodic benefit cost for funded and unfunded pension plans, and the postretirement medical plan, is as follows: Pension Plans Postretirement Medical Plan 2023 2022 2021 2023 2022 2021 (In millions) Service cost $ 35 $ 44 $ 51 $ 3 $ 3 $ 3 Interest cost 97 69 55 2 1 1 Expected return on plan assets (156) (196) (197) — — — Amortization of unrecognized net actuarial losses (gains) 3 11 58 (2) (1) (1) Settlement loss 17 2 9 — — — Net Periodic Benefit Cost / (Income) (a) $ (4) $ (70) $ (24) $ 3 $ 3 $ 3 (a) Net non-service cost, which is included in Other, net in the Statement of Consolidated Income, was income of $39 million in 2023 (2022: $114 million of income; 2021: $75 million of income).
Actuarial Assumptions Used for Pension Plans & Postretirement Medical Plan	The weighted average actuarial assumptions used to determine benefit obligations at December 31 and net periodic benefit cost for the three years ended December 31 for our funded and unfunded pension plans were as follows: 2023 2022 2021 Benefit Obligations: Discount rate 4.8% 5.0% 2.5% Rate of compensation increase 3.9% 4.0% 3.8% Net Periodic Benefit Cost: Discount rate Service cost 5.0% 3.3% 2.6% Interest cost 4.9% 3.0% 1.7% Expected rate of return on plan assets 6.5% 6.5% 6.6% Rate of compensation increase 4.0% 3.8% 3.8% The actuarial assumptions used to determine benefit obligations at December 31 for the post-retirement medical plan were as follows: 2023 2022 2021 Discount rate 4.7% 4.9% 2.4% Initial health care trend rate 6.0% 6.3% 5.5% Ultimate trend rate 4.0% 4.0% 4.0% Year in which ultimate trend rate is reached 2046 2046 2046
Fair Value of Financial Assets of Funded Pension Plans	The following tables provide the fair value of the financial assets of the funded pension plans at December 31, 2023 and 2022 in accordance with the fair value measurement hierarchy described in Note 1, Nature of Operations, Basis of Presentation and Summary of Accounting Policies . Level 1 Level 2 Level 3 Net Asset Total (In millions) December 31, 2023 Cash and Short-Term Investment Funds $ 27 $ — $ — $ — $ 27 Equities: U.S. equities (domestic) 309 — — — 309 International equities (non-U.S.) 52 — — 158 210 Global equities (domestic and non-U.S.) — 6 — 55 61 Fixed Income: Treasury and government related (a) — 581 — — 581 Mortgage-backed securities (b) — 98 — 12 110 Corporate — 547 — 3 550 Other: Hedge funds — — — — — Private equity funds — — — 414 414 Real estate funds — — — 183 183 Total investments $ 388 $ 1,232 $ — $ 825 $ 2,445 December 31, 2022 Cash and Short-Term Investment Funds $ 51 $ — $ — $ — $ 51 Equities: U.S. equities (domestic) 409 — — 11 420 International equities (non-U.S.) 62 11 — 306 379 Global equities (domestic and non-U.S.) — 5 — 90 95 Fixed Income: Treasury and government related (a) — 364 — — 364 Mortgage-backed securities (b) — 142 — 18 160 Corporate — 304 — 8 312 Other: Hedge funds — — — 75 75 Private equity funds — — — 374 374 Real estate funds 9 — — 211 220 Total investments $ 531 $ 826 $ — $ 1,093 $ 2,450 (a) Includes securities issued and guaranteed by U.S. and non‑U.S. governments, and securities issued by governmental agencies and municipalities. (b) Comprised of U.S. residential and commercial mortgage-backed securities. (c)
Estimated Future Benefit Payments for Pension Plans & Postretirement Medical Plan	Estimated future benefit payments by the funded and unfunded pension plans, and the post-retirement medical plan, which reflect expected future service, are as follows (in millions): 2024 $ 112 2025 117 2026 167 2027 117 2028 123 Years 2029 to 2033 611

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Summary of Revenue from Contracts with Customers on a Disaggregated Basis	Revenue from contracts with customers on a disaggregated basis was as follows (in millions): Exploration and Production Midstream Eliminations Total United States Guyana Malaysia and JDA Other (a) E&P Total 2023 Sales of net production volumes: Crude oil revenue $ 3,058 $ 3,486 $ 144 $ — $ 6,688 $ — $ — $ 6,688 Natural gas liquids revenue 529 — — — 529 — — 529 Natural gas revenue 182 — 800 — 982 — — 982 Sales of purchased oil and gas 2,390 70 — — 2,460 — — 2,460 Third-party services — — — — — 8 — 8 Intercompany revenue — — — — — 1,338 (1,338) — Total sales (b) 6,159 3,556 944 — 10,659 1,346 (1,338) 10,667 Other operating revenues (c) (78) (62) (19) — (159) 3 — (156) Total sales and other operating revenues $ 6,081 $ 3,494 $ 925 $ — $ 10,500 $ 1,349 $ (1,338) $ 10,511 2022 Sales of net production volumes: Crude oil revenue $ 3,407 $ 2,771 $ 134 $ 509 $ 6,821 $ — $ — $ 6,821 Natural gas liquids revenue 703 — — — 703 — — 703 Natural gas revenue 438 — 739 21 1,198 — — 1,198 Sales of purchased oil and gas 2,978 53 — 112 3,143 — — 3,143 Intercompany revenue — — — — — 1,273 (1,273) — Total sales (b) 7,526 2,824 873 642 11,865 1,273 (1,273) 11,865 Other operating revenues (c) (312) (188) — (41) (541) — — (541) Total sales and other operating revenues $ 7,214 $ 2,636 $ 873 $ 601 $ 11,324 $ 1,273 $ (1,273) $ 11,324 2021 Sales of net production volumes: Crude oil revenue $ 2,958 $ 765 $ 83 $ 519 $ 4,325 $ — $ — $ 4,325 Natural gas liquids revenue 594 — — — 594 — — 594 Natural gas revenue 350 — 655 10 1,015 — — 1,015 Sales of purchased oil and gas 1,638 16 — 95 1,749 — — 1,749 Intercompany revenue — — — — — 1,204 (1,204) — Total sales (b) 5,540 781 738 624 7,683 1,204 (1,204) 7,683 Other operating revenues (c) (162) (27) — (21) (210) — — (210) Total sales and other operating revenues $ 5,378 $ 754 $ 738 $ 603 $ 7,473 $ 1,204 $ (1,204) $ 7,473 (a) Other includes our interest in the Waha Concession in Libya, which was sold in November 2022, and our interests in Denmark, which were sold in August 2021. (b) Guyana crude oil revenue includes $433 million of revenue from non-customers in 2023 (2022: $230 million). There was no sales revenue from non-customers in 2021. (c) Other operating revenues are not a component of revenues from contracts with customers. Included within other operating revenues are gains (losses) on commodity derivatives

Share-based Compensation (Table

Share-based Compensation (Tables)	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Share-based Compensation Cost by Award Type	Share‑based compensation expense consisted of the following: 2023 2022 2021 (In millions) Restricted stock $ 55 $ 52 $ 49 Performance share units 21 20 18 Stock options 11 11 10 Share-based compensation expense before income taxes $ 87 $ 83 $ 77 Income tax benefit on share-based compensation expense $ — $ — $ —
Summary of Restricted Stock Award Activity	The following is a summary of restricted stock award activity in 2023: Shares of Restricted Common Stock Weighted - Average Price on Date of Grant (In thousands, except per share amounts) Outstanding at January 1, 2023 1,312 $ 80.61 Granted 470 141.76 Vested (a) (735) 73.24 Forfeited (26) 104.14 Outstanding at December 31, 2023 1,021 $ 113.47 (a) In 2023, restricted stock with a vesting date fair value of $104 million were vested (2022: $86 million; 2021: $72 million).
Summary of Performance Share Units Activity	The following is a summary of PSU activity in 2023: Performance Share Units Weighted - Average Fair Value on Date of Grant (In thousands, except per share amounts) Outstanding at January 1, 2023 686 $ 81.25 Granted 130 178.80 Vested (a) (303) 57.93 Forfeited (1) 104.54 Outstanding at December 31, 2023 512 $ 119.77 (a) In 2023, PSU’s with a vesting date fair value of $55 million were vested (2022: $37 million; 2021: $30 million).
Assumptions to Estimate Fair Value of Performance Share Units	The following weighted average assumptions were utilized to estimate the fair value of PSU awards: 2023 2022 2021 Risk free interest rate 4.61 % 1.59 % 0.29 % Stock price volatility 0.478 0.584 0.579 Contractual term in years 3.0 3.0 3.0 Grant date price of Hess common stock $ 141.95 $ 101.17 $ 75.04
Summary of Stock Options Activity	The following is a summary of stock options activity in 2023: Number of options Weighted Average Exercise Price per Share Weighted Average Remaining Contractual Term Outstanding at January 1, 2023 1,481 $ 69.31 6.6 years Granted 189 141.71 Exercised (157) 64.34 Forfeited (3) 90.73 Outstanding at December 31, 2023 1,510 $ 78.85 6.1 years
Assumptions to Estimate Fair Value of Stock Options	The following weighted average assumptions were utilized to estimate the fair value of stock options: 2023 2022 2021 Risk free interest rate 4.20 % 1.66 % 0.95 % Stock price volatility 0.469 0.457 0.470 Dividend yield 1.24 % 1.48 % 1.33 % Expected life in years 6.0 6.0 6.0 Weighted average fair value per option granted $ 63.45 $ 39.51 $ 29.66

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Components of Income Tax Provision (Benefit)	The provision (benefit) for income taxes consisted of: 2023 2022 2021 (In millions) United States Federal Current $ — $ — $ — Deferred taxes and other accruals 31 22 12 State 7 5 3 38 27 15 Foreign Current (a) 537 789 478 Deferred taxes and other accruals 158 283 107 695 1,072 585 Provision (Benefit) For Income Taxes $ 733 $ 1,099 $ 600 (a) Primarily comprised of Guyana in 2023, Guyana and Libya in 2022, and Libya in 2021.
Components of Income (Loss) Before Income Taxes	Income (loss) before income taxes consisted of the following: 2023 2022 2021 (In millions) United States (a) $ (191) $ 569 $ 143 Foreign 2,662 2,977 1,347 Income (Loss) Before Income Taxes $ 2,471 $ 3,546 $ 1,490 (a) Includes substantially all of our interest expense, corporate expense, the results of commodity hedging activities, and amounts attributable to noncontrolling interests.
Reconciliation of Effective Income Tax Rate	The difference between our effective income tax rate and the U.S. statutory rate is reconciled below: 2023 2022 2021 U.S. statutory rate 21.0 % 21.0 % 21.0 % Effect of foreign operations (a) 7.5 16.5 28.0 State income taxes, net of federal income tax 0.2 0.1 0.2 Valuation allowance on current year operations 4.5 (4.8) (5.3) Release of valuation allowance (1.3) — — Noncontrolling interests in Midstream (2.0) (1.6) (4.0) Equity and executive compensation (0.2) (0.2) 0.4 Total 29.7 % 31.0 % 40.3 % (a) The variance in effective income tax rates attributable to the effect of foreign operations is primarily driven by Guyana in 2023 and Libya in 2022 and 2021.
Components of Deferred Tax Assets & Liabilities	The components of deferred tax liabilities and deferred tax assets at December 31, were as follows: 2023 2022 (In millions) Deferred Tax Liabilities Property, plant and equipment and investments $ (2,117) $ (1,742) Other (108) (99) Total Deferred Tax Liabilities (2,225) (1,841) Deferred Tax Assets Net operating loss carryforwards 4,406 4,226 Tax credit carryforwards 109 98 Property, plant and equipment and investments 413 233 Accrued compensation, deferred credits and other liabilities 109 85 Asset retirement obligations 296 279 Other 256 293 Total Deferred Tax Assets 5,589 5,214 Valuation allowances (a) (3,652) (3,658) Total deferred tax assets, net of valuation allowances 1,937 1,556 Net Deferred Tax Assets (Liabilities) $ (288) $ (285) (a) In 2023, the valuation allowance decreased by $6 million (2022: decrease of $180 million; 2021: decrease of $1,553 million). In the Consolidated Balance Sheet , deferred tax assets and liabilities are netted by taxing jurisdiction and are recorded at December 31, as follows: 2023 2022 (In millions) Deferred income taxes (long-term asset) $ 320 $ 133 Deferred income taxes (long-term liability) (608) (418) Net Deferred Tax Assets (Liabilities) $ (288) $ (285)
Reconciliation of Unrecognized Tax Benefits	Below is a reconciliation of the gross beginning and ending amounts of unrecognized tax benefits: 2023 2022 2021 (In millions) Balance at January 1 $ 120 $ 133 $ 166 Additions based on tax positions taken in the current year — 17 12 Additions based on tax positions of prior years — — 3 Reductions based on tax positions of prior years (9) (30) (48) Balance at December 31 $ 111 $ 120 $ 133

Outstanding and Weighted Aver_2

Outstanding and Weighted Average Common Shares (Tables)	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Net Income (Loss) & Weighted Average Number of Common Shares Used in Computation of Basic & Diluted Earnings Per Share	Net income and weighted average number of common shares used in the basic and diluted earnings per share computations were as follows: 2023 2022 2021 (In millions except per share amounts) Net Income Attributable to Hess Corporation: Net income $ 1,738 $ 2,447 $ 890 Less: Net income attributable to noncontrolling interests 356 351 331 Net income attributable to Hess Corporation $ 1,382 $ 2,096 $ 559 Weighted Average Number of Common Shares Outstanding: Basic 305.9 308.1 307.4 Effect of dilutive securities Restricted common stock 0.5 0.7 0.7 Stock options 0.7 0.6 0.4 Performance share units 0.5 0.2 0.8 Diluted 307.6 309.6 309.3 Net Income Attributable to Hess Corporation per Common Share: Basic $ 4.52 $ 6.80 $ 1.82 Diluted $ 4.49 $ 6.77 $ 1.81 Antidilutive shares excluded from the computation of diluted shares: Restricted common stock — — — Stock options 0.2 0.2 0.7 Performance share units — — —
Changes in Outstanding Common Shares	The following table provides the changes in our outstanding common shares: 2023 2022 2021 (In millions) Balance at January 1 306.2 309.7 307.0 Activity related to restricted stock awards, net 0.4 0.5 0.7 Stock options exercised 0.2 0.9 1.5 PSUs vested 0.4 0.5 0.5 Shares repurchased — (5.4) — Balance at December 31 307.2 306.2 309.7

Supplementary Cash Flow Infor_2

Supplementary Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2023
Supplemental Cash Flow Elements [Abstract]
Schedule of Cash Flow Supplemental Disclosures	The following information supplements the Statement of Consolidated Cash Flows : 2023 2022 2021 (In millions) Cash Flows From Operating Activities Interest paid $ (470) $ (486) $ (459) Net income taxes (paid) refunded (71) (1,036) (16) Cash Flows From Investing Activities Additions to property, plant and equipment – E&P: Capital expenditures incurred – E&P $ (4,033) $ (2,589) $ (1,698) Increase (decrease) in related liabilities 149 102 114 Additions to property, plant and equipment – E&P $ (3,884) $ (2,487) $ (1,584) Additions to property, plant and equipment – Midstream: Capital expenditures incurred – Midstream $ (246) $ (232) $ (183) Increase (decrease) in related liabilities 22 (6) 20 Additions to property, plant and equipment – Midstream $ (224) $ (238) $ (163)

Guarantees, Contingencies and_2

Guarantees, Contingencies and Commitments (Tables)	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Schedule of Unconditional Purchase Obligations & Commitments	The following table shows aggregate information for certain unconditional purchase obligations and commitments at December 31, 2023, which are not included elsewhere within these Consolidated Financial Statements : Payments Due by Period Total 2024 2025 2026 2027 2028 Thereafter (In millions) Capital expenditures $ 7,472 $ 2,371 $ 2,106 $ 1,757 $ 774 $ 371 $ 93 Operating expenses 762 238 107 55 50 63 249 Transportation and related contracts 2,243 298 260 286 277 261 861

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Financial Data by Operating Segments	The following table presents operating segment financial data (in millions): Exploration and Production Midstream Corporate, Interest and Other Eliminations Total 2023 Sales and other operating revenues $ 10,500 $ 11 $ — $ — $ 10,511 Intersegment revenues — 1,338 — (1,338) — Total sales and other operating revenues $ 10,500 $ 1,349 $ — $ (1,338) $ 10,511 Net income (loss) attributable to Hess Corporation $ 1,601 $ 252 $ (471) $ — $ 1,382 Interest expense — 179 299 — 478 Depreciation, depletion and amortization 1,852 193 1 — 2,046 Impairment and other 82 — — — 82 Provision for income taxes 695 38 — — 733 Investment in affiliates 76 90 — — 166 Identifiable assets 17,931 3,984 2,092 — 24,007 Capital expenditures 4,033 246 — — 4,279 2022 Sales and other operating revenues $ 11,324 $ — $ — $ — $ 11,324 Intersegment revenues — 1,273 — (1,273) — Total sales and other operating revenues $ 11,324 $ 1,273 $ — $ (1,273) $ 11,324 Net income (loss) attributable to Hess Corporation $ 2,396 $ 269 $ (569) $ — $ 2,096 Interest expense — 150 343 — 493 Depreciation, depletion and amortization 1,520 181 2 — 1,703 Impairment and other 54 — — — 54 Provision for income taxes 1,072 27 — — 1,099 Investment in affiliates 88 94 1 — 183 Identifiable assets 15,022 3,775 2,898 — 21,695 Capital expenditures 2,589 232 — — 2,821 2021 Sales and other operating revenues $ 7,473 $ — $ — $ — $ 7,473 Intersegment revenues — 1,204 — (1,204) — Total sales and other operating revenues $ 7,473 $ 1,204 $ — $ (1,204) $ 7,473 Net income (loss) attributable to Hess Corporation $ 770 $ 286 $ (497) $ — $ 559 Interest expense — 105 376 — 481 Depreciation, depletion and amortization 1,361 166 1 — 1,528 Impairment and other 147 — — — 147 Provision for income taxes 585 15 — — 600 Capital expenditures 1,698 183 — — 1,881 Corporate, Interest and Other had interest income of $82 million in 2023 (2022: $32 million, 2021: $1 million) which is included in Other, net in the Statement of Consolidated Income.
Financial Information by Major Geographic Area	The following table presents financial information by major geographic area: United States Guyana Malaysia and JDA Other (a) Corporate, Interest and other Total (In millions) 2023 Sales and Other Operating Revenues $ 6,092 $ 3,494 $ 925 $ — $ — $ 10,511 Property, Plant and Equipment (Net) (b) 10,554 5,957 872 42 7 17,432 2022 Sales and Other Operating Revenues $ 7,214 $ 2,636 $ 873 $ 601 $ — $ 11,324 Property, Plant and Equipment (Net) (b) 9,937 4,042 1,065 46 8 15,098 2021 Sales and Other Operating Revenues $ 5,378 $ 754 $ 738 $ 603 $ — $ 7,473 (a) Other includes our interests in Libya (sold in November 2022), Denmark (sold in August 2021), Suriname and Canada. (b)

Financial Risk Management Act_2

Financial Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Notional Amounts of Outstanding Financial Risk Management Derivative Contracts	The notional amounts of outstanding financial risk management derivative contracts were as follows: December 31, 2023 December 31, 2022 (In millions) Foreign exchange forwards and swaps $ 226 $ 177 Interest rate swaps $ 100 $ 100
Gross & Net Fair Values of Financial Risk Management Derivative Instruments	The table below reflects the gross and net fair values of risk management derivative instruments: Assets Liabilities (In millions) December 31, 2023 Derivative Contracts Designated as Hedging Instruments: Interest rate swaps $ — $ (2) Total derivative contracts designated as hedging instruments — (2) Derivative Contracts Not Designated as Hedging Instruments: Foreign exchange forwards and swaps — (6) Total derivative contracts not designated as hedging instruments — (6) Gross fair value of derivative contracts — (8) Gross amount offset in the Consolidated Balance Sheet — — Net Amounts Presented in the Consolidated Balance Sheet $ — $ (8) December 31, 2022 Derivative Contracts Designated as Hedging Instruments: Interest rate swaps — (4) Total derivative contracts designated as hedging instruments — (4) Derivative Contracts Not Designated as Hedging Instruments: Foreign exchange forwards and swaps — (2) Total derivative contracts not designated as hedging instruments — (2) Gross fair value of derivative contracts — (6) Gross amount offset in the Consolidated Balance Sheet — — Net Amounts Presented in the Consolidated Balance Sheet $ — $ (6)

Nature of Operations, Basis o_3

Nature of Operations, Basis of Presentation and Summary of Accounting Policies (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Nature of Operations, Basis of Presentation and Summary of Accounting Policies [Line Items]
Hess common stock conversion rate to the right to receive Chevron common stock	1.025
Contract liability	$ 0	$ 24,000,000
Deferred revenue included in contract liability at prior year end, recognized as revenue during the current reporting year	24,000,000
Contract asset	$ 0	0
Initial revenue contract period	10 years
Minimum volume commitments percentage of nominations	80%
Rolling period for minimum volume commitments	3
Term set for minimum volume commitments	3 years
Goodwill	$ 360,000,000	360,000,000
Reserve for estimated remediation liabilities	50,000,000
Carbon credits purchased	75,000,000	75,000,000	$ 0
Carrying value of carbon credits	$ 150,000,000	$ 75,000,000
Exploration and Production | Minimum
Nature of Operations, Basis of Presentation and Summary of Accounting Policies [Line Items]
Long-term contracts with customers remaining duration	1 year
Exploration and Production | Maximum
Nature of Operations, Basis of Presentation and Summary of Accounting Policies [Line Items]
Long-term contracts with customers remaining duration	9 years
Midstream
Nature of Operations, Basis of Presentation and Summary of Accounting Policies [Line Items]
Additional revenue contract period	10 years
Goodwill	$ 360,000,000
Hess Midstream LP
Nature of Operations, Basis of Presentation and Summary of Accounting Policies [Line Items]
Percent interest in consolidated entity	38%

Inventories - Schedule of Inven

Inventories - Schedule of Inventories (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Inventory Disclosure [Abstract]
Crude oil and natural gas liquids	$ 72	$ 63
Materials and supplies	232	154
Total Inventories	$ 304	$ 217

Property, Plant and Equipment -

Property, Plant and Equipment - Components of Property, Plant and Equipment (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Total — at cost	$ 36,771	$ 32,592
Less: Reserves for depreciation, depletion, amortization and lease impairment	19,339	17,494
Property, Plant and Equipment— Net	17,432	15,098
Exploration and Production
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment— Net	7,325	6,764
Operating Segments | Exploration and Production
Property, Plant and Equipment [Line Items]
Unproved properties	103	149
Proved properties	2,660	2,660
Wells, equipment and related facilities	29,159	25,182
Total — at cost	31,922	27,991
Operating Segments | Midstream
Property, Plant and Equipment [Line Items]
Total — at cost	4,819	4,571
Corporate, Interest and Other
Property, Plant and Equipment [Line Items]
Total — at cost	30	30
Property, Plant and Equipment— Net	$ 7	$ 8

Property, Plant and Equipment_2

Property, Plant and Equipment - Net Changes in Capitalized Exploratory Well Costs (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) well	Dec. 31, 2022 USD ($) well	Dec. 31, 2021 USD ($) well
Property, Plant and Equipment [Abstract]
Beginning balance	$ 886	$ 681	$ 459
Additions to capitalized exploratory well costs pending the determination of proved reserves	257	298	222
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	(133)	(93)	0
Capitalized exploratory well costs charged to expense	(58)	0	0
Ending balance	$ 952	$ 886	$ 681
Exploration and appraisal wells | well	43	43	35

Property, Plant and Equipment_3

Property, Plant and Equipment - Exploratory Drilling Costs Capitalized (Detail) $ in Millions	Dec. 31, 2023 USD ($)
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized exploratory well costs that have been capitalized for period greater than one year	$ 728
2022
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized exploratory well costs that have been capitalized for period greater than one year	261
2021
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized exploratory well costs that have been capitalized for period greater than one year	162
2020
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized exploratory well costs that have been capitalized for period greater than one year	8
2019
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized exploratory well costs that have been capitalized for period greater than one year	139
2018 and prior
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Capitalized exploratory well costs that have been capitalized for period greater than one year	$ 158

Property, Plant and Equipment_4

Property, Plant and Equipment - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) well	Dec. 31, 2022 USD ($) well	Dec. 31, 2021 USD ($) well	Dec. 31, 2020 USD ($)
Capitalized Exploratory Well Costs [Line Items]
Exploration and appraisal wells | well	43	43	35
Capitalized exploratory well costs | $	$ 952	$ 886	$ 681	$ 459
Capitalized exploratory well costs charged to expense | $	58	0	0
Well costs incurred and expensed | $	$ 89	$ 56	$ 11
Stabroek Block, Offshore Guyana
Capitalized Exploratory Well Costs [Line Items]
Participation interest percentage	30%
Exploration and appraisal wells | well	36
Capitalized exploratory well costs | $	$ 841
Capitalized well costs percentage	87%
Pickerel-1 Well, Gulf of Mexico
Capitalized Exploratory Well Costs [Line Items]
Participation interest percentage	100%
Huron-1 Well, Gulf of Mexico
Capitalized Exploratory Well Costs [Line Items]
Participation interest percentage	40%
Zanderij-1 Well, Block 42, Offshore Suriname
Capitalized Exploratory Well Costs [Line Items]
Participation interest percentage	33%
Capitalized well costs percentage	6%
JDA, Gulf of Thailand
Capitalized Exploratory Well Costs [Line Items]
Participation interest percentage	50%
Capitalized well costs percentage	5%
Successful exploration wells | well	3
North Malay Basin, Offshore Peninsular Malaysia
Capitalized Exploratory Well Costs [Line Items]
Participation interest percentage	50%
Capitalized well costs percentage	2%
Successful exploration wells | well	2

Hess Midstream LP (Detail)

Hess Midstream LP (Detail) shares in Thousands, bbl in Millions, $ in Millions	1 Months Ended					12 Months Ended
	Nov. 30, 2023 USD ($)	Aug. 31, 2023 USD ($) shares	May 31, 2023 USD ($) shares	Apr. 30, 2022 shares	Aug. 31, 2021 shares	Dec. 31, 2023 USD ($) shares bbl	Dec. 31, 2022 USD ($) shares	Dec. 31, 2021 USD ($) shares
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Number of underwritten public equity offerings completed								2
Proceeds from sale of Class A shares of Hess Midstream LP			$ 167			$ 167	$ 146	$ 178
Sale of Class A shares of Hess Midstream LP						333	218	255
Deferred tax impact to noncontrolling interests from sale of units held by parent by consolidated subsidiary		$ 82	84				72	77
Proceeds from repurchase of units held by Hess Corporation and Global Infrastructure Partners, by Hess Midstream Operations LP	$ 100					400	400	750
Proceeds from repurchase of units held by Hess Corporation by Hess Midstream Operations LP	38
Senior unsecured fixed-rate note issued by Hess Midstream Operations LP							$ 400	$ 750
Interest rate of senior unsecured fixed-rate note issued by Hess Midstream Operations LP							5.50%	4.25%
Repurchase of Class B units of Hess Midstream Operations LP						(189)	$ (183)	$ (362)
Deferred tax impact to noncontrolling interests from repurchase of units held by parent by consolidated subsidiary	7					23	17	15
Proceeds to noncontrolling interests from repurchase of units held by parent by consolidated subsidiary	$ 62					$ 212	200	375
Participation by parent in repurchase subsidiary shares						5,000%
Participation by noncontrolling interest in repurchase of units of consolidated subsidiary						5,000%
Variable Interest Entity, Measure of Activity [Abstract]
Liabilities						$ 14,405	13,199
Cash and cash equivalents						1,688	2,486
Property, plant and equipment — net						$ 17,432	15,098
Joint venture percentage owned by Targa Resources Corp						50%
Capital in Excess of Par
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Sale of Class A shares of Hess Midstream LP			158			$ 158	130	152
Repurchase of Class B units of Hess Midstream Operations LP						31	32	28
Noncontrolling Interests
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Sale of Class A shares of Hess Midstream LP			93			175	88	103
Repurchase of Class B units of Hess Midstream Operations LP						$ (220)	(215)	(390)
Noncontrolling Interests | Change In Ownership
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Sale of Class A shares of Hess Midstream LP			$ 9				$ 16	$ 26
Class A Shares
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Number of Class A shares of subsidiary public offering (in shares) | shares		11,500	12,800				10,200	15,500
Class B Shares
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Number of Class B units repurchased by Hess Midstream LP (in shares) | shares						13,600	13,600	31,250
Hess Midstream LP
Ownership [Abstract]
Percent interest in consolidated entity						38%
Hess Midstream LP | Capital in Excess of Par
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Sale of Class A shares of Hess Midstream LP							$ 130	$ 152
Repurchase of Class B units of Hess Midstream Operations LP						$ 31	32	28
Hess Midstream LP | Noncontrolling Interests
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Sale of Class A shares of Hess Midstream LP							88	103
Repurchase of Class B units of Hess Midstream Operations LP						$ 31	32	28
Hess Midstream LP | Public Shareholders
Ownership [Abstract]
Noncontrolling interest ownership percentage of GIP						30%
Hess Midstream LP | Global Infrastructure Partners
Ownership [Abstract]
Noncontrolling interest ownership percentage of GIP						32%
Midstream
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Number of Class B units repurchased by Hess Midstream LP (in shares) | shares				13,600	31,250
Senior unsecured fixed-rate note issued by Hess Midstream Operations LP						$ 2,477	2,472
Variable Interest Entity | Hess Midstream LP
Variable Interest Entity, Measure of Activity [Abstract]
Cash and cash equivalents						$ 5	3
Gas processing capacity of LM4 | bbl						200
Processing fees incurred						$ 24	21	$ 28
Variable Interest Entity | Hess Midstream LP | Little Missouri Four
Variable Interest Entity, Measure of Activity [Abstract]
Equity method investment						$ 90	94
Equity method investment, ownership percentage						50%
Variable Interest Entity | Hess Midstream LP | Nonrecourse
Variable Interest Entity, Measure of Activity [Abstract]
Liabilities						$ 3,385	3,027
Variable Interest Entity | Midstream
Variable Interest Entity, Measure of Activity [Abstract]
Property, plant and equipment — net						$ 3,229	$ 3,173

Accrued Liabilities - Schedule

Accrued Liabilities - Schedule of Accrued Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Payables and Accruals [Abstract]
Accrued operating and marketing expenditures	$ 593	$ 522
Accrued capital expenditures	670	499
Current portion of asset retirement obligations	160	207
Accrued payments to royalty and working interest owners	178	201
Accrued interest on debt	144	143
Accrued compensation and benefits	193	132
Other accruals	164	136
Accrued liabilities	$ 2,102	$ 1,840

Leases - Balance Sheet Informat

Leases - Balance Sheet Information Related to Operating & Finance Leases (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Operating lease right-of-use assets — net	$ 720	$ 570
Finance lease right-of-use assets — net	$ 108	$ 126
Operating Lease obligations:
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]	Current portion of operating and finance lease obligations	Current portion of operating and finance lease obligations
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Current portion of operating and finance lease obligations	Current portion of operating and finance lease obligations
Current operating lease obligations	$ 347	$ 200
Long-term operating lease obligations	459	469
Total lease obligations	806	669
Finance Lease Obligations:
Current finance lease obligations	23	21
Long-term finance lease obligations	156	179
Total lease obligations	179	200
Finance lease ROU assets cost	212	212
Finance lease ROU assets accumulated amortization	$ 104	$ 86

Leases - Maturity Profile of Le

Leases - Maturity Profile of Lease Obligations (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Operating Leases
2024	$ 377
2025	197
2026	89
2027	48
2028	22
Remaining years	165
Total lease payments	898
Less: Imputed interest	(92)
Total lease obligations	806	$ 669
Finance Leases
2024	36
2025	36
2026	31
2027	22
2028	23
Remaining years	99
Total lease payments	247
Less: Imputed interest	(68)
Total lease obligations	$ 179	$ 200

Leases - Term & Rate Informatio

Leases - Term & Rate Information Related to Operating & Finance Leases (Detail)	Dec. 31, 2023	Dec. 31, 2022
Operating Leases
Weighted average remaining lease term	5 years	6 years 9 months 18 days
Weighted average discount rate	5.10%	4.50%
Finance Leases
Weighted average remaining lease term	9 years 9 months 18 days	10 years 9 months 18 days
Range of remaining lease terms	9 years 9 months 18 days	10 years 9 months 18 days
Weighted average discount rate	7.90%	7.90%
Minimum
Operating Leases
Range of remaining lease terms	1 month 6 days	3 months 18 days
Maximum
Operating Leases
Range of remaining lease terms	12 years 6 months	13 years 6 months

Leases - Components of Lease Co

Leases - Components of Lease Costs (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Leases [Abstract]
Operating lease cost (a)	$ 241	$ 114	$ 88
Finance lease cost: Amortization of leased assets	18	18	24
Finance lease cost: Interest on lease obligations	15	18	18
Short-term lease cost	294	311	137
Variable lease cost	67	33	21
Sublease income	(19)	(18)	(17)
Total lease cost	$ 616	$ 476	$ 271
Number of well in development drilling program	15

Leases - Supplemental Cash Flow

Leases - Supplemental Cash Flow Information Related to Leases (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash paid for amounts included in the measurement of lease obligations:
Cash paid for operating leases (operating cash flows)	$ 254	$ 126	$ 87
Cash paid for finance leases (operating cash flows)	15	18	18
Cash paid for finance leases (financing cash flows)	21	19	18
Noncash transactions:
Operating Leases - Leased assets recognized for new lease obligations incurred	267	294	12
Finance Leases - Leased assets recognized for new lease obligations incurred	0	0	0
Operating Leases - Changes in leased assets and lease obligations due to lease modifications	97	16	29
Finance Leases - Changes in leased assets and lease obligations due to lease modifications	$ 0	$ 0	$ 0

Leases - Additional Information

Leases - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Lease obligations - Represented percentage of present value of future minimum lease payments in lease arrangement	100%
Remaining lease term on Floating, Storage and Offloading Vessel (FSO)	9 years 9 months 18 days	10 years 9 months 18 days
Lease costs - Represented percentage of the lease payments due for the period	100%

Debt - Components of Debt (Deta

Debt - Components of Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Apr. 30, 2022	Dec. 31, 2021	Aug. 31, 2021
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes		$ 400		$ 750
Current portion of long-term debt	$ 311	3
Long-term debt	8,302	8,278
Total Debt	$ 8,613	$ 8,281
Interest rate of senior unsecured fixed-rate note		5.50%		4.25%
3.500% due 2024
Debt Instrument [Line Items]
Interest rate of senior unsecured fixed-rate note	3.50%
4.300% due 2027
Debt Instrument [Line Items]
Interest rate of senior unsecured fixed-rate note	4.30%
7.875% due 2029
Debt Instrument [Line Items]
Interest rate of senior unsecured fixed-rate note	7.875%
7.300% due 2031
Debt Instrument [Line Items]
Interest rate of senior unsecured fixed-rate note	7.30%
7.125% due 2033
Debt Instrument [Line Items]
Interest rate of senior unsecured fixed-rate note	7.125%
6.000% due 2040
Debt Instrument [Line Items]
Interest rate of senior unsecured fixed-rate note	6%
5.600% due 2041
Debt Instrument [Line Items]
Interest rate of senior unsecured fixed-rate note	5.60%
5.800% due 2047
Debt Instrument [Line Items]
Interest rate of senior unsecured fixed-rate note	5.80%
5.625% due 2026
Debt Instrument [Line Items]
Interest rate of senior unsecured fixed-rate note	5.625%
5.125% due 2028
Debt Instrument [Line Items]
Interest rate of senior unsecured fixed-rate note	5.125%
4.250% due 2030
Debt Instrument [Line Items]
Interest rate of senior unsecured fixed-rate note	4.25%
5.500% due 2030
Debt Instrument [Line Items]
Interest rate of senior unsecured fixed-rate note	5.50%
Hess Corporation
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	$ 5,404	$ 5,399
Fair value adjustments – interest rate hedging	(2)	(4)
Total Debt	5,402	5,395
Hess Corporation | 3.500% due 2024
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	300	300
Hess Corporation | 4.300% due 2027
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	997	996
Hess Corporation | 7.875% due 2029
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	465	464
Hess Corporation | 7.300% due 2031
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	629	629
Hess Corporation | 7.125% due 2033
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	537	537
Hess Corporation | 6.000% due 2040
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	743	742
Hess Corporation | 5.600% due 2041
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	1,238	1,237
Hess Corporation | 5.800% due 2047
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	495	494
Midstream
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	2,477	2,472
Term loan facility	394	396
Revolving credit facility - outstanding amount	340	18
Total Debt	3,211	2,886
Midstream | 5.625% due 2026
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	795	793
Midstream | 5.125% due 2028
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	545	544
Midstream | 4.250% due 2030
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	742	740
Interest rate of senior unsecured fixed-rate note					4.25%
Midstream | 5.500% due 2030
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	$ 395	$ 395
Interest rate of senior unsecured fixed-rate note			5.50%

Debt - Maturity Profile of Debt

Debt - Maturity Profile of Debt (Detail) $ in Millions	Dec. 31, 2023 USD ($)
Debt Instrument [Line Items]
2024	$ 311
2025	22
2026	832
2027	1,670
2028	550
Thereafter	5,290
Total Borrowings	8,675
Less: Deferred financing costs and discounts	(62)
Total Debt (excluding interest)	8,613
Hess Corporation
Debt Instrument [Line Items]
2024	298
2025	0
2026	0
2027	1,000
2028	0
Thereafter	4,140
Total Borrowings	5,438
Less: Deferred financing costs and discounts	(36)
Total Debt (excluding interest)	5,402
Midstream
Debt Instrument [Line Items]
2024	13
2025	22
2026	832
2027	670
2028	550
Thereafter	1,150
Total Borrowings	3,237
Less: Deferred financing costs and discounts	(26)
Total Debt (excluding interest)	$ 3,211

Debt - Other Outstanding Letter

Debt - Other Outstanding Letters of Credit (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Line of Credit Facility [Line Items]
Other outstanding letters of credit	$ 88	$ 83
Committed Lines
Line of Credit Facility [Line Items]
Other outstanding letters of credit	2	0
Uncommitted Lines
Line of Credit Facility [Line Items]
Other outstanding letters of credit	$ 86	$ 83

Debt - Additional Information -

Debt - Additional Information - Hess Corporation (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Capitalized interest	$ 48,000,000	$ 10,000,000	$ 0
Letters of credit - outstanding amount	$ 88,000,000	83,000,000
Hess Corporation
Debt Instrument [Line Items]
Debt instrument covenant, secured debt to net tangible assets ratio	15%
Debt instrument covenant, debt to capital ratio	65%
Hess Corporation | Revolving Credit Facility
Debt Instrument [Line Items]
Debt instrument covenant, secured debt to net tangible assets ratio	15%
Interest rate applicable margin	1.40%
Revolving credit facility - outstanding amount	$ 0
Letters of credit - outstanding amount	$ 0
Debt instrument covenant, debt to capital ratio	65%
Hess Corporation | Senior Unsecured Fixed-Rate Public Notes
Debt Instrument [Line Items]
Principal amount of senior unsecured fixed-rate public notes	$ 5,438,000,000	$ 5,438,000,000
Weighted average interest rate of senior unsecured fixed-rate public notes	5.90%	5.90%
Debt instrument covenant, secured debt to net tangible assets ratio	15%
Hess Corporation | Senior Unsecured Fixed-Rate Public Notes | Revolving Credit Facility
Debt Instrument [Line Items]
Maximum additional amount allowed to borrow under financial covenants	$ 2,515,000,000

Debt - Additional Information_2

Debt - Additional Information - Midstream (Detail) - USD ($) shares in Thousands, $ in Millions	1 Months Ended		12 Months Ended
	Apr. 30, 2022	Aug. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Interest rate of senior unsecured fixed-rate note				5.50%	4.25%
Borrowings			$ 8,675
5.500% due 2030
Debt Instrument [Line Items]
Interest rate of senior unsecured fixed-rate note			5.50%
4.250% due 2030
Debt Instrument [Line Items]
Interest rate of senior unsecured fixed-rate note			4.25%
Midstream
Debt Instrument [Line Items]
Principal amount of senior unsecured fixed-rate public notes			$ 2,500	$ 2,500
Weighted average interest rate of senior unsecured fixed-rate public notes			5.10%	5.10%
Number of Class B units repurchased by Hess Midstream LP (in shares)	13,600	31,250
Senior secured syndicated credit facilities			$ 1,400
Term loan facility			$ 394	$ 396
Ratio of debt to EBITDA for prior four fiscal quarter - Maximum			500%
Ratio of debt to EBITDA for period after acquisitions - Maximum			550%
Secured leverage ratio - Maximum			400%
Revolving credit facility - outstanding amount			$ 340	$ 18
Borrowings			3,237
Midstream | Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility - maximum borrowing capacity			1,000
Revolving credit facility - outstanding amount			$ 340
Midstream | Revolving Credit Facility | Minimum
Debt Instrument [Line Items]
Interest rate applicable margin			1.375%
Midstream | Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Interest rate applicable margin			2.05%
Midstream | 5.500% due 2030
Debt Instrument [Line Items]
Principal amount of senior unsecured fixed-rate public notes	$ 400
Interest rate of senior unsecured fixed-rate note	5.50%
Midstream | 4.250% due 2030
Debt Instrument [Line Items]
Principal amount of senior unsecured fixed-rate public notes		$ 750
Interest rate of senior unsecured fixed-rate note		4.25%
Midstream | Term Loan
Debt Instrument [Line Items]
Term loan facility			$ 400
Borrowings			$ 397
Midstream | Term Loan | Minimum
Debt Instrument [Line Items]
Interest rate applicable margin			1.65%
Midstream | Term Loan | Maximum
Debt Instrument [Line Items]
Interest rate applicable margin			2.55%

Asset Retirement Obligations -

Asset Retirement Obligations - Changes to Asset Retirement Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$ 1,241	$ 1,190
Liabilities incurred	135	126
Liabilities settled or disposed of (a)	(240)	(213)
Accretion expense	61	48
Revisions of estimated liabilities	148	92
Foreign currency remeasurement	1	(2)
Asset retirement obligations at end of period	1,346	1,241
Current portion of asset retirement obligations	160	207
Long-term asset retirement obligations	1,186	1,034
Asset retirement obligations	$ 1,346	$ 1,241

Asset Retirement Obligations _2

Asset Retirement Obligations - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligations [Line Items]
Revisions of estimated liabilities	$ 148	$ 92
Fair value of sinking fund deposits legally restricted for purposes of settling asset retirement obligations	294	$ 261
West Delta Field in the Gulf of Mexico
Asset Retirement Obligations [Line Items]
Revisions of estimated liabilities	$ 82

Retirement Plans - Change in Be

Retirement Plans - Change in Benefit Obligation, Fair Value of Plan Assets & Funded Status of Pension Plans & Postretirement Medical Plan (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Change in Fair Value of Plan Assets
Beginning balance	$ 2,450
Ending balance	2,445	$ 2,450
Changes in Discount Rate Assumptions
Change in Benefit Obligation
Actuarial (gains) loss	(56)	(874)
Change in Fair Value of Plan Assets
Actuarial gains or losses resulted from changes in assumptions	56	874
Updates to Census Data
Change in Benefit Obligation
Actuarial (gains) loss	(18)
Change in Fair Value of Plan Assets
Actuarial gains or losses resulted from changes in assumptions	18
Alignment of PBO to Settlement Payments
Change in Benefit Obligation
Actuarial (gains) loss	(20)
Change in Fair Value of Plan Assets
Actuarial gains or losses resulted from changes in assumptions	20
Changes in Mortality Assumptions
Change in Benefit Obligation
Actuarial (gains) loss		(8)
Change in Fair Value of Plan Assets
Actuarial gains or losses resulted from changes in assumptions		8
All Other Assumptions
Change in Benefit Obligation
Actuarial (gains) loss	(2)	(3)
Change in Fair Value of Plan Assets
Actuarial gains or losses resulted from changes in assumptions	2	3
Funded Pension Plans
Change in Benefit Obligation
Beginning balance	1,802	2,948
Service cost	26	33
Interest cost	88	66
Actuarial (gains) loss	44	(818)
Plan settlements	143	266
Benefit payments	(77)	(90)
Foreign currency exchange rate changes	20	(71)
Ending balance	1,760	1,802
Change in Fair Value of Plan Assets
Beginning balance	2,450	3,357
Actual return on plan assets	186	(469)
Employer contributions	1	1
Plan settlements	143	266
Benefit payments	(77)	(90)
Foreign currency exchange rate changes	28	(83)
Ending balance	2,445	2,450
Funded Status (Plan assets greater (less) than benefit obligations) at December 31,	685	648
Unrecognized Net Actuarial (Gains) Losses (c)	332	337
Actuarial gains or losses resulted from changes in assumptions	(44)	818
Accumulated benefit obligation	1,684	1,743
Funded Pension Plans | Hess U.K. Pension Plan
Change in Fair Value of Plan Assets
Unrecognized Net Actuarial (Gains) Losses (c)	179	175
Unfunded Pension Plan
Change in Benefit Obligation
Beginning balance	212	248
Service cost	9	11
Interest cost	9	3
Actuarial (gains) loss	7	(38)
Plan settlements	0	0
Benefit payments	(15)	(12)
Foreign currency exchange rate changes	0	0
Ending balance	222	212
Change in Fair Value of Plan Assets
Beginning balance	0	0
Actual return on plan assets	0	0
Employer contributions	15	12
Plan settlements	0	0
Benefit payments	(15)	(12)
Foreign currency exchange rate changes	0	0
Ending balance	0	0
Funded Status (Plan assets greater (less) than benefit obligations) at December 31,	(222)	(212)
Unrecognized Net Actuarial (Gains) Losses (c)	30	23
Actuarial gains or losses resulted from changes in assumptions	(7)	38
Accumulated benefit obligation	181	180
Postretirement Medical Plan
Change in Benefit Obligation
Beginning balance	52	59
Service cost	3	3
Interest cost	2	1
Actuarial (gains) loss	1	(7)
Plan settlements	0	0
Benefit payments	(5)	(4)
Foreign currency exchange rate changes	0	0
Ending balance	53	52
Change in Fair Value of Plan Assets
Beginning balance	0	0
Actual return on plan assets	0	0
Employer contributions	5	4
Plan settlements	0	0
Benefit payments	(5)	(4)
Foreign currency exchange rate changes	0	0
Ending balance	0	0
Funded Status (Plan assets greater (less) than benefit obligations) at December 31,	(53)	(52)
Unrecognized Net Actuarial (Gains) Losses (c)	(25)	(27)
Actuarial gains or losses resulted from changes in assumptions	$ (1)	$ 7

Retirement Plans - Amounts Reco

Retirement Plans - Amounts Recognized in Balance Sheet for Pension Plans & Postretirement Medical Plan (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Noncurrent assets	$ 685	$ 648
Accumulated other comprehensive (gain) loss related to retirement plans, after-tax - Deficit	134	131
Funded Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Noncurrent assets	685	648
Current liabilities	0	0
Noncurrent liabilities	0	0
Post-retirement benefit assets / (liabilities)	685	648
Accumulated other comprehensive loss, pre-tax	332	337
Unfunded Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Noncurrent assets	0	0
Current liabilities	(23)	(24)
Noncurrent liabilities	(199)	(188)
Post-retirement benefit assets / (liabilities)	(222)	(212)
Accumulated other comprehensive loss, pre-tax	30	23
Postretirement Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Noncurrent assets	0	0
Current liabilities	(5)	(6)
Noncurrent liabilities	(48)	(46)
Post-retirement benefit assets / (liabilities)	(53)	(52)
Accumulated other comprehensive loss, pre-tax	$ (25)	$ (27)

Retirement Plans - Components o

Retirement Plans - Components of Net Periodic Benefit Cost for Pension Plans & Postretirement Medical Plan (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Settlement loss	$ 17	$ 2	$ 9
Net non-service pension (income) costs included in Other, net	(39)	(114)	(75)
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	35	44	51
Interest cost	97	69	55
Expected return on plan assets	(156)	(196)	(197)
Amortization of unrecognized net actuarial losses (gains)	3	11	58
Settlement loss	17	2	9
Net Periodic Benefit Cost	(4)	(70)	(24)
Postretirement Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	3	3	3
Interest cost	2	1	1
Expected return on plan assets	0	0	0
Amortization of unrecognized net actuarial losses (gains)	(2)	(1)	(1)
Settlement loss	0	0	0
Net Periodic Benefit Cost	$ 3	$ 3	$ 3

Retirement Plans - Actuarial As

Retirement Plans - Actuarial Assumptions Used for Pension Plans & Postretirement Medical Plan (Detail)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Plans
Benefit Obligations:
Discount rate	4.80%	5%	2.50%
Rate of compensation increase	3.90%	4%	3.80%
Net Periodic Benefit Cost:
Expected rate of return on plan assets	6.50%	6.50%	6.60%
Rate of compensation increase	4%	3.80%	3.80%
Pension Plans | Service Cost
Net Periodic Benefit Cost:
Discount rate, Service cost	5%	3.30%	2.60%
Pension Plans | Interest Cost
Net Periodic Benefit Cost:
Discount rate, Service cost	4.90%	3%	1.70%
Postretirement Medical Plan
Benefit Obligations:
Discount rate	4.70%	4.90%	2.40%
Initial health care trend rate	6%	6.30%	5.50%
Ultimate trend rate	4%	4%	4%
Year in which ultimate trend rate is reached	2046	2046	2046

Retirement Plans - Fair Value o

Retirement Plans - Fair Value of Financial Assets of Funded Pension Plans (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	$ 2,445	$ 2,450
Cash and Short-term Investment Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	27	51
U.S. Equities (domestic)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	309	420
International Equities (non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	210	379
Global Equities (domestic and non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	61	95
Treasury and Government Related - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	581	364
Mortgage-backed Securities - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	110	160
Corporate - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	550	312
Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	75
Private Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	414	374
Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	183	220
Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	388	531
Level 1 | Cash and Short-term Investment Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	27	51
Level 1 | U.S. Equities (domestic)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	309	409
Level 1 | International Equities (non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	52	62
Level 1 | Global Equities (domestic and non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 1 | Treasury and Government Related - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 1 | Mortgage-backed Securities - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 1 | Corporate - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 1 | Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 1 | Private Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 1 | Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	9
Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	1,232	826
Level 2 | Cash and Short-term Investment Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 2 | U.S. Equities (domestic)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 2 | International Equities (non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	11
Level 2 | Global Equities (domestic and non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	6	5
Level 2 | Treasury and Government Related - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	581	364
Level 2 | Mortgage-backed Securities - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	98	142
Level 2 | Corporate - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	547	304
Level 2 | Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 2 | Private Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 2 | Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3 | Cash and Short-term Investment Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3 | U.S. Equities (domestic)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3 | International Equities (non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3 | Global Equities (domestic and non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3 | Treasury and Government Related - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3 | Mortgage-backed Securities - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3 | Corporate - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3 | Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3 | Private Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Level 3 | Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Net Asset Value
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	825	1,093
Net Asset Value | Cash and Short-term Investment Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Net Asset Value | U.S. Equities (domestic)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	11
Net Asset Value | International Equities (non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	158	306
Net Asset Value | Global Equities (domestic and non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	55	90
Net Asset Value | Treasury and Government Related - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	0
Net Asset Value | Mortgage-backed Securities - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	12	18
Net Asset Value | Corporate - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	3	8
Net Asset Value | Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	0	75
Net Asset Value | Private Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	414	374
Net Asset Value | Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	$ 183	$ 211

Retirement Plans - Estimated Fu

Retirement Plans - Estimated Future Benefit Payments for Pension Plans & Postretirement Medical Plan (Detail) $ in Millions	Dec. 31, 2023 USD ($)
Retirement Benefits [Abstract]
2024	$ 112
2025	117
2026	167
2027	117
2028	123
Years 2029 to 2033	$ 611

Retirement Plans - Additional I

Retirement Plans - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Retirement benefits, description		Additionally, we maintain an unfunded post-retirement medical plan that provides health benefits to certain U.S. qualified retirees from ages 55 through 65.
Settlement loss		$ (17)	$ (2)	$ (9)
Budgeted contributions to funded pension plans for next year		25
Expense for defined contribution plans		$ 24	22	$ 18
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Interest Cost, Statement of Income or Comprehensive Income [Extensible Enumeration]		Other, net
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) Excluding Service Cost, Statement of Income or Comprehensive Income [Extensible Enumeration]		Other, net
Scenario Forecast
Defined Benefit Plan Disclosure [Line Items]
Service costs	$ 40
Net non-service pension costs	65
Interest costs	90
Expected return on plan assets	$ 155
Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage for plan assets		30%
Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage for plan assets		50%
Other Types of Investments
Defined Benefit Plan Disclosure [Line Items]
Target allocation percentage for plan assets		20%
Lump sum Payment
Defined Benefit Plan Disclosure [Line Items]
Plan settlements		$ 143
Hess Corporation Employees' Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Settlement loss		$ 17	13
Hess Corporation Employees' Pension Plan | Single Premium Annuity Contract
Defined Benefit Plan Disclosure [Line Items]
Plan settlements			166
Hovensa Legacy Employees' Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Settlement loss			11
Defined Benefit Plan, Benefit Obligation			15
Hovensa Legacy Employees' Pension Plan | Single Premium Annuity Contract
Defined Benefit Plan Disclosure [Line Items]
Plan settlements			80
Hovensa Legacy Employees' Pension Plan | Lump sum Payment
Defined Benefit Plan Disclosure [Line Items]
Plan settlements			$ 20

Revenue - Summary of Revenue fr

Revenue - Summary of Revenue from Contracts with Customers on a Disaggregated Basis (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax			$ 7,683,000,000
Revenue from both contract with customer and not from contract with customer, excluding assessed tax	$ 10,667,000,000	$ 11,865,000,000
Other operating revenues	(156,000,000)	(541,000,000)	(210,000,000)
Total sales and other operating revenues	10,511,000,000	11,324,000,000	7,473,000,000
Gain (loss) on commodity derivatives	$ (190,000,000)	$ (585,000,000)	$ (243,000,000)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Total sales and other operating revenues	Total sales and other operating revenues	Total sales and other operating revenues
Crude Oil Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax			$ 4,325,000,000
Revenue from both contract with customer and not from contract with customer, excluding assessed tax	$ 6,688,000,000	$ 6,821,000,000
Natural Gas Liquids Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	529,000,000	703,000,000	594,000,000
Natural Gas Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	982,000,000	1,198,000,000	1,015,000,000
Sales of Purchased Oil and Gas
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	2,460,000,000	3,143,000,000	1,749,000,000
Third-Party Services
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	8,000,000
Guyana | Crude Oil Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contracts with customer	433,000,000	230,000,000	0
Exploration and Production
Disaggregation of Revenue [Line Items]
Total sales and other operating revenues	10,500,000,000	11,324,000,000	7,473,000,000
Exploration and Production | Crude Oil Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax			4,325,000,000
Revenue from both contract with customer and not from contract with customer, excluding assessed tax	6,688,000,000	6,821,000,000
Exploration and Production | Natural Gas Liquids Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	529,000,000	703,000,000	594,000,000
Exploration and Production | Natural Gas Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	982,000,000	1,198,000,000	1,015,000,000
Exploration and Production | Sales of Purchased Oil and Gas
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	2,460,000,000	3,143,000,000	1,749,000,000
Exploration and Production | Third-Party Services
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0
Exploration and Production | United States | Crude Oil Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	3,058,000,000	3,407,000,000	2,958,000,000
Exploration and Production | United States | Natural Gas Liquids Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	529,000,000	703,000,000	594,000,000
Exploration and Production | United States | Natural Gas Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	182,000,000	438,000,000	350,000,000
Exploration and Production | United States | Sales of Purchased Oil and Gas
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	2,390,000,000	2,978,000,000	1,638,000,000
Exploration and Production | United States | Third-Party Services
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0
Exploration and Production | Guyana | Crude Oil Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax			765,000,000
Revenue from both contract with customer and not from contract with customer, excluding assessed tax	3,486,000,000	2,771,000,000
Exploration and Production | Guyana | Natural Gas Liquids Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	0	0
Exploration and Production | Guyana | Natural Gas Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	0	0
Exploration and Production | Guyana | Sales of Purchased Oil and Gas
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	70,000,000	53,000,000	16,000,000
Exploration and Production | Guyana | Third-Party Services
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0
Exploration and Production | Malaysia and JDA | Crude Oil Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	144,000,000	134,000,000	83,000,000
Exploration and Production | Malaysia and JDA | Natural Gas Liquids Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	0	0
Exploration and Production | Malaysia and JDA | Natural Gas Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	800,000,000	739,000,000	655,000,000
Exploration and Production | Malaysia and JDA | Sales of Purchased Oil and Gas
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	0	0
Exploration and Production | Malaysia and JDA | Third-Party Services
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0
Exploration and Production | Other | Crude Oil Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	509,000,000	519,000,000
Exploration and Production | Other | Natural Gas Liquids Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	0	0
Exploration and Production | Other | Natural Gas Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	21,000,000	10,000,000
Exploration and Production | Other | Sales of Purchased Oil and Gas
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	112,000,000	95,000,000
Exploration and Production | Other | Third-Party Services
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0
Midstream
Disaggregation of Revenue [Line Items]
Total sales and other operating revenues	11,000,000	0	0
Midstream | Crude Oil Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	0	0
Midstream | Natural Gas Liquids Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	0	0
Midstream | Natural Gas Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	0	0
Midstream | Sales of Purchased Oil and Gas
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	0	0
Midstream | Third-Party Services
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	8,000,000
Operating Segments | United States
Disaggregation of Revenue [Line Items]
Total sales and other operating revenues	6,092,000,000	7,214,000,000	5,378,000,000
Operating Segments | Guyana
Disaggregation of Revenue [Line Items]
Total sales and other operating revenues	3,494,000,000	2,636,000,000	754,000,000
Operating Segments | Malaysia and JDA
Disaggregation of Revenue [Line Items]
Total sales and other operating revenues	925,000,000	873,000,000	738,000,000
Operating Segments | Other
Disaggregation of Revenue [Line Items]
Total sales and other operating revenues	0	601,000,000	603,000,000
Operating Segments | Exploration and Production
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax			7,683,000,000
Revenue from both contract with customer and not from contract with customer, excluding assessed tax	10,659,000,000	11,865,000,000
Other operating revenues	(159,000,000)	(541,000,000)	(210,000,000)
Total sales and other operating revenues	10,500,000,000	11,324,000,000	7,473,000,000
Operating Segments | Exploration and Production | United States
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	6,159,000,000	7,526,000,000	5,540,000,000
Other operating revenues	(78,000,000)	(312,000,000)	(162,000,000)
Total sales and other operating revenues	6,081,000,000	7,214,000,000	5,378,000,000
Operating Segments | Exploration and Production | Guyana
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax			781,000,000
Revenue from both contract with customer and not from contract with customer, excluding assessed tax	3,556,000,000	2,824,000,000
Other operating revenues	(62,000,000)	(188,000,000)	(27,000,000)
Total sales and other operating revenues	3,494,000,000	2,636,000,000	754,000,000
Operating Segments | Exploration and Production | Malaysia and JDA
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	944,000,000	873,000,000	738,000,000
Other operating revenues	(19,000,000)	0	0
Total sales and other operating revenues	925,000,000	873,000,000	738,000,000
Operating Segments | Exploration and Production | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	642,000,000	624,000,000
Other operating revenues	0	(41,000,000)	(21,000,000)
Total sales and other operating revenues	0	601,000,000	603,000,000
Operating Segments | Midstream
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	1,346,000,000	1,273,000,000	1,204,000,000
Other operating revenues	3,000,000	0	0
Total sales and other operating revenues	1,349,000,000	1,273,000,000	1,204,000,000
Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	(1,338,000,000)	(1,273,000,000)	(1,204,000,000)
Other operating revenues	0	0	0
Total sales and other operating revenues	(1,338,000,000)	(1,273,000,000)	(1,204,000,000)
Eliminations | Exploration and Production
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	0	0
Total sales and other operating revenues	0	0	0
Eliminations | Exploration and Production | United States
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	0	0
Eliminations | Exploration and Production | Guyana
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	0	0
Eliminations | Exploration and Production | Malaysia and JDA
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	0	0
Eliminations | Exploration and Production | Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	0	0	0
Eliminations | Midstream
Disaggregation of Revenue [Line Items]
Revenue from contract with customer, excluding assessed tax	1,338,000,000	1,273,000,000	1,204,000,000
Total sales and other operating revenues	$ 1,338,000,000	$ 1,273,000,000	$ 1,204,000,000

Dispositions (Detail)

Dispositions (Detail)	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($) a	Nov. 30, 2022
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales	$ 3,000,000	$ 178,000,000	$ 427,000,000
Gain (loss) on asset sales, pre-tax	$ 2,000,000	101,000,000	29,000,000
Interest in Waha Concession in Libya
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales		150,000,000
Gain (loss) on asset sales, pre-tax		76,000,000
Gain (loss) on asset sale, after income taxes		76,000,000
Participation interest percentage				8%
Former Downstream Business
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales		24,000,000
Gain (loss) on asset sales, pre-tax		22,000,000
Gain (loss) on asset sale, after income taxes		$ 22,000,000
Interests in Denmark
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales			130,000,000
Gain (loss) on asset sales, pre-tax			29,000,000
Gain (loss) on asset sale, after income taxes			29,000,000
Little Knife & Murphy Creek Acreage Interests in Bakken
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales			297,000,000
Gain (loss) on asset sales, pre-tax			$ 0
Developed and undeveloped acreage sold | a			78,700

Impairment and Other (Detail)

Impairment and Other (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($) u_hesLease
Impairments [Line Items]
Impairment and other charge, pre-tax	$ 82	$ 54	$ 147
Number of offshore Gulf of Mexico leases abandoned | u_hesLease			7
West Delta Field in the Gulf of Mexico
Impairments [Line Items]
Impairment and other charge, pre-tax	82		$ 147
Impairment and other charge, after income taxes	$ 82		$ 147
Oil and Gas Properties | Non-Producing Properties in Gulf of Mexico
Impairments [Line Items]
Impairment and other charge, pre-tax		28
Impairment and other charge, after income taxes		28
Oil and Gas Properties | Penn State Field in Gulf of Mexico
Impairments [Line Items]
Impairment and other charge, pre-tax		26
Impairment and other charge, after income taxes		$ 26

Share-based Compensation - Shar

Share-based Compensation - Share-based Compensation Cost by Award Type (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Share-based compensation expense before income taxes	$ 87	$ 83	$ 77
Income tax benefit on share-based compensation expense	0	0	0
Restricted Stock
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Share-based compensation expense before income taxes	55	52	49
Performance Share Units
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Share-based compensation expense before income taxes	21	20	18
Stock Options
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Share-based compensation expense before income taxes	$ 11	$ 11	$ 10

Share-based Compensation - Summ

Share-based Compensation - Summary of Restricted Stock Award Activity (Detail) - Restricted Stock - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards - Outstanding at beginning of period (in shares)	1,312
Awards - Granted (in shares)	470
Awards - Vested (in shares)	(735)
Awards - Forfeited (in shares)	(26)
Awards - Outstanding at end of period (in shares)	1,021	1,312
Weighted average fair value on date of grant - Outstanding at beginning of period (in dollars per share)	$ 80.61
Weighted average fair value on date of grant - Granted (in dollars per share)	141.76
Weighted average fair value on date of grant - Vested (in dollars per share)	73.24
Weighted average fair value on date of grant - Forfeited (in dollars per share)	104.14
Weighted average fair value on date of grant - Outstanding at end of period (in dollars per share)	$ 113.47	$ 80.61
Fair value of vested shares	$ 104	$ 86	$ 72

Share-based Compensation - Su_2

Share-based Compensation - Summary of Performance Share Units Activity (Detail) - Performance Share Units - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards - Outstanding at beginning of period (in shares)	686
Awards - Granted (in shares)	130
Awards - Vested (in shares)	(303)
Awards - Forfeited (in shares)	(1)
Awards - Outstanding at end of period (in shares)	512	686
Weighted average fair value on date of grant - Outstanding at beginning of period (in dollars per share)	$ 81.25
Weighted average fair value on date of grant - Granted (in dollars per share)	178.80
Weighted average fair value on date of grant - Vested (in dollars per share)	57.93
Weighted average fair value on date of grant - Forfeited (in dollars per share)	104.54
Weighted average fair value on date of grant - Outstanding at end of period (in dollars per share)	$ 119.77	$ 81.25
Fair value of vested shares	$ 55	$ 37	$ 30

Share-based Compensation - Assu

Share-based Compensation - Assumptions to Estimate Fair Value of Performance Share Units (Detail) - Performance Share Units - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk free interest rate	4.61%	1.59%	0.29%
Stock price volatility	47.80%	58.40%	57.90%
Contractual term in years	3 years	3 years	3 years
Grant date price of Hess common stock (in dollars per share)	$ 141.95	$ 101.17	$ 75.04

Share-based Compensation - Su_3

Share-based Compensation - Summary of Stock Options Activity (Detail) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-Based Payment Arrangement [Abstract]
Options - Outstanding at beginning of period (in shares)	1,481
Options - Granted (in shares)	189
Options - Exercised (in shares)	(157)	(900)	(1,500)
Options - Forfeited (in shares)	(3)
Options - Outstanding at end of period (in shares)	1,510	1,481
Weighted average exercise price per share - Outstanding at beginning of period (in dollars per share)	$ 69.31
Weighted average exercise price per share - Granted (in dollars per share)	141.71
Weighted average exercise price per share - Exercised (in dollars per share)	64.34
Weighted average exercise price per share - Forfeited (in dollars per share)	90.73
Weighted average exercise price per share - Outstanding at end of period (in dollars per share)	$ 78.85	$ 69.31
Weighted average remaining contractual term - Outstanding	6 years 1 month 6 days	6 years 7 months 6 days

Share-based Compensation - As_2

Share-based Compensation - Assumptions to Estimate Fair Value of Stock Options (Detail) - Stock Options - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk free interest rate	4.20%	1.66%	0.95%
Stock price volatility	46.90%	45.70%	47%
Dividend yield	1.24%	1.48%	1.33%
Expected life in years	6 years	6 years	6 years
Weighted average fair value per option granted (in dollars per share)	$ 63.45	$ 39.51	$ 29.66

Share-based Compensation - Addi

Share-based Compensation - Additional Information (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of authorized common stock shares under LTIP (in shares)	63,500
Number of shares under LTIP, available for issuance of restricted common shares, performance share units and stock options	19,900
Unearned compensation expense, before income taxes	$ 89
Weighed average period of recognition for unearned compensation expense	1 year 9 months 18 days
Outstanding stock options (in shares)	1,510	1,481
Number of stock options, exercisable (in shares)	1,000
Weighted average exercise price per share - Outstanding at end of period (in dollars per share)	$ 78.85	$ 69.31
Weighted average exercise price per share - stock options exercisable (in dollars per share)	$ 64.07
Weighted average remaining contractual term - Outstanding	6 years 1 month 6 days	6 years 7 months 6 days
Weighted average remaining contractual life for options, exercisable	5 years 1 month 6 days
Aggregated intrinsic value	$ 105
Aggregated intrinsic value for exercisable options	88
Aggregated intrinsic value for options exercised	$ 13	$ 44	$ 45
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Performance Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Valuation method used for performance share units	Monte Carlo simulation
Performance period	3 years
Payout percentage modifier	10%
Performance Share Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout percentage	0%	0%
Payout percentage including modifier	0%
Performance Share Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout percentage	200%	200%
Payout percentage including modifier	210%
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Contractual term of stock options	10 years

Income Taxes - Components of In

Income Taxes - Components of Income Tax Provision (Benefit) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
United States - Federal, Current income tax expense (benefit)	$ 0	$ 0	$ 0
United States - Federal, Deferred income taxes and other accruals expense (benefit)	31	22	12
United States - State, Current & Deferred income taxes and other accruals expense (benefit)	7	5	3
United States - Current & Deferred income taxes, and other accruals expense (benefit)	38	27	15
Foreign - Current income tax expense (benefit)	537	789	478
Foreign - Deferred income taxes and other accruals expense (benefit)	158	283	107
Foreign - Current & Deferred income taxes and other accruals expense (benefit)	695	1,072	585
Provision (Benefit) For Income Taxes	$ 733	$ 1,099	$ 600

Income Taxes - Components of _2

Income Taxes - Components of Income (Loss) Before Income Taxes (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
United States - Income (Loss) Before Income Taxes	$ (191)	$ 569	$ 143
Foreign - Income (Loss) Before Income Taxes	2,662	2,977	1,347
Income Before Income Taxes	$ 2,471	$ 3,546	$ 1,490

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Effective Income Tax Rate (Detail)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
U.S. statutory rate	21%	21%	21%
Effect of foreign operations	7.50%	16.50%	28%
State income taxes, net of federal income tax	0.20%	0.10%	0.20%
Valuation allowance on current year operations	4.50%	(4.80%)	(5.30%)
Release of valuation allowance	(1.30%)	0%	0%
Noncontrolling interests in Midstream	(2.00%)	(1.60%)	(4.00%)
Equity and executive compensation	(0.20%)	(0.20%)	0.40%
Total	29.70%	31%	40.30%

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Assets & Liabilities (Detail) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Deferred Tax Liabilities
Property, plant and equipment and investments	$ (2,117)	$ (2,117)	$ (1,742)
Other	(108)	(108)	(99)
Total Deferred Tax Liabilities	(2,225)	(2,225)	(1,841)
Deferred Tax Assets
Net operating loss carryforwards	4,406	4,406	4,226
Tax credit carryforwards	109	109	98
Property, plant and equipment and investments	413	413	233
Accrued compensation, deferred credits and other liabilities	109	109	85
Asset retirement obligations	296	296	279
Other	256	256	293
Total Deferred Tax Assets	5,589	5,589	5,214
Valuation allowances	(3,652)	(3,652)	(3,658)
Total deferred tax assets, net of valuation allowances	1,937	1,937	1,556
Net Deferred Tax Assets (Liabilities)	(288)	(288)	(285)
Valuation allowance increase (decrease) amount	33	(6)	180	$ (1,553)
Deferred Tax Liabilities, Net [Abstract]
Deferred income taxes (long-term asset)	320	320	133
Deferred income taxes (long-term liability)	(608)	(608)	(418)
Net Deferred Tax Assets (Liabilities)	$ (288)	$ (288)	$ (285)

Income Taxes - Reconciliation_2

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Beginning balance	$ 120	$ 133	$ 166
Additions based on tax positions taken in the current year	0	17	12
Additions based on tax positions of prior years	0	0	3
Reductions based on tax positions of prior years	(9)	(30)	(48)
Ending balance	$ 111	$ 120	$ 133

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)	1 Months Ended	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Examination [Line Items]
Gross deferred tax asset related to net operating loss carryforwards	$ 4,406,000,000	$ 4,406,000,000	$ 4,226,000,000
Gross deferred tax asset related to foreign net operating loss carryforwards	127,000,000	127,000,000
Gross deferred tax asset related to net U.S. federal operating loss carryforwards	3,778,000,000	3,778,000,000
Gross deferred tax asset related to net operating loss carryforwards for various U.S. states	501,000,000	501,000,000
Deferred tax asset related to foreign net operating loss carryforwards, net of valuation allowance	23,000,000	23,000,000
U.S. state tax credit carryforwards	27,000,000	27,000,000
Other business credit carryforwards	81,000,000	81,000,000
Foreign tax credit carryforwards - Before valuation allowance	1,000,000	1,000,000
Valuation allowance against net deferred tax assets	3,652,000,000	3,652,000,000	3,658,000,000
Release of valuation allowance established against a portion of the net deferred tax assets in Malaysia, related to the Marginal Field tax ring-fence	33,000,000	(6,000,000)	180,000,000	$ (1,553,000,000)
Unrecognized tax benefits that would impact effective income tax rate	0	0
Unrecognized tax benefits decrease reasonably possible	0	0
Accrued interest and penalties	0	0	$ 0
Midstream
Income Tax Examination [Line Items]
Gross deferred tax asset related to net U.S. federal operating loss carryforwards	38,000,000	38,000,000
Gross deferred tax asset related to net operating loss carryforwards for various U.S. states	$ 8,000,000	$ 8,000,000

Outstanding and Weighted Aver_3

Outstanding and Weighted Average Common Shares - Net Income (Loss) & Weighted Average Number of Common Shares Used in Computation of Basic & Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Net Income (Loss) Attributable to Hess Corporation Common Stockholders:
Net Income	$ 1,738	$ 2,447	$ 890
Less: Net income attributable to noncontrolling interests	356	351	331
Net Income (Loss) Available to Common Stockholders, Basic, Total	$ 1,382	$ 2,096	$ 559
Weighted Average Number of Common Shares Outstanding:
Shares outstanding – Basic (in shares)	305.9	308.1	307.4
Weighted Average Number of Common Shares Outstanding (Diluted) (in shares)	307.6	309.6	309.3
Basic (in dollars per share)	$ 4.52	$ 6.80	$ 1.82
Diluted (in dollars per share)	$ 4.49	$ 6.77	$ 1.81
Restricted Common Stock
Weighted Average Number of Common Shares Outstanding:
Antidilutive shares excluded from computation of diluted shares (in shares)	0	0	0
Stock Options
Weighted Average Number of Common Shares Outstanding:
Antidilutive shares excluded from computation of diluted shares (in shares)	0.2	0.2	0.7
Performance Share Units
Weighted Average Number of Common Shares Outstanding:
Antidilutive shares excluded from computation of diluted shares (in shares)	0	0	0
Restricted Common Stock
Weighted Average Number of Common Shares Outstanding:
Effect of dilutive securities (in shares)	0.5	0.7	0.7
Stock Options
Weighted Average Number of Common Shares Outstanding:
Effect of dilutive securities (in shares)	0.7	0.6	0.4
Performance Share Units
Weighted Average Number of Common Shares Outstanding:
Effect of dilutive securities (in shares)	0.5	0.2	0.8

Outstanding and Weighted Aver_4

Outstanding and Weighted Average Common Shares - Changes in Outstanding Common Shares (Detail) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity [Abstract]
Beginning balance (in shares)	306,200	309,700	307,000
Activity related to restricted stock awards, net (in shares)	400	500	700
Stock options exercised (in shares)	157	900	1,500
PSUs vested (in shares)	400	500	500
Shares repurchased (in shares)	0	5,400	0
Ending balance (in shares)	307,200	306,200	309,700

Outstanding and Weighted Aver_5

Outstanding and Weighted Average Common Shares - Additional Information (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity [Abstract]
Stock repurchase program, authorized amount	$ 1,000
Shares repurchased (in shares)	0	5,400	0
Common stock acquired and retired		$ 650
Common stock acquired and retired	$ 20	$ 630	$ 0
Cash dividends on common stock (in dollars per share)	$ 1.75	$ 1.50	$ 1

Supplementary Cash Flow Infor_3

Supplementary Cash Flow Information - Schedule of Cash Flow Supplemental Disclosures (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash Flows From Operating Activities
Interest paid	$ (470)	$ (486)	$ (459)
Net income taxes (paid) refunded	(71)	(1,036)	(16)
Cash Flows From Investing Activities
Additions to property, plant and equipment – E&P	(3,884)	(2,487)	(1,584)
Additions to property, plant and equipment – Midstream	(224)	(238)	(163)
Exploration and Production
Cash Flows From Investing Activities
Capital expenditures incurred	(4,033)	(2,589)	(1,698)
Increase (decrease) in related liabilities	149	102	114
Additions to property, plant and equipment – E&P	(3,884)	(2,487)	(1,584)
Midstream
Cash Flows From Investing Activities
Capital expenditures incurred	(246)	(232)	(183)
Increase (decrease) in related liabilities	22	(6)	20
Additions to property, plant and equipment – Midstream	$ (224)	$ (238)	$ (163)

Guarantees, Contingencies and_3

Guarantees, Contingencies and Commitments - Schedule of Unconditional Purchase Obligations & Commitments (Detail) $ in Millions	Dec. 31, 2023 USD ($)
Capital Expenditures
Loss Contingencies [Line Items]
Total	$ 7,472
2024	2,371
2025	2,106
2026	1,757
2027	774
2028	371
Thereafter	93
Operating Expenses
Loss Contingencies [Line Items]
Total	762
2024	238
2025	107
2026	55
2027	50
2028	63
Thereafter	249
Transportation and Related Contracts
Loss Contingencies [Line Items]
Total	2,243
2024	298
2025	260
2026	286
2027	277
2028	261
Thereafter	$ 861

Guarantees, Contingencies and_4

Guarantees, Contingencies and Commitments - Additional Information (Detail) $ in Millions	1 Months Ended
	Mar. 31, 2014 USD ($)	Dec. 31, 2023 USD ($) Case
Loss Contingencies [Line Items]
Accrual for environmental loss contingencies | $		$ 153
MTBE Cases
Loss Contingencies [Line Items]
Total number of remaining active cases filed | Case		2
Gowanus Canal Superfund Site
Loss Contingencies [Line Items]
Estimated remediation cost | $	$ 506
Post-production Deductions from Royalty and Working Interest Payments
Loss Contingencies [Line Items]
Total number of remaining active cases filed | Case		6

Segment Information - Financial

Segment Information - Financial Data by Operating Segments (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Sales and other operating revenues	$ 10,511	$ 11,324	$ 7,473
Net income (loss) attributable to Hess Corporation	1,382	2,096	559
Interest expense	478	493	481
Depreciation, depletion and amortization	2,046	1,703	1,528
Impairment and other	82	54	147
Provision (Benefit) for Income Taxes	733	1,099	600
Investment in affiliates	166	183
Identifiable assets	24,007	21,695
Capital expenditures	4,279	2,821	1,881
Corporate, Interest and Other
Segment Reporting Information [Line Items]
Sales and other operating revenues	0	0	0
Net income (loss) attributable to Hess Corporation	(471)	(569)	(497)
Interest expense	299	343	376
Depreciation, depletion and amortization	1	2	1
Impairment and other	0	0	0
Provision (Benefit) for Income Taxes	0	0	0
Investment in affiliates	0	1
Identifiable assets	2,092	2,898
Capital expenditures	0	0	0
Interest income	82	32	1
Eliminations
Segment Reporting Information [Line Items]
Sales and other operating revenues	(1,338)	(1,273)	(1,204)
Net income (loss) attributable to Hess Corporation	0	0	0
Interest expense	0	0	0
Depreciation, depletion and amortization	0	0	0
Impairment and other	0	0	0
Provision (Benefit) for Income Taxes	0	0	0
Investment in affiliates	0	0
Identifiable assets	0	0
Capital expenditures	0	0	0
Exploration and Production
Segment Reporting Information [Line Items]
Sales and other operating revenues	10,500	11,324	7,473
Exploration and Production | Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues	10,500	11,324	7,473
Net income (loss) attributable to Hess Corporation	1,601	2,396	770
Interest expense	0	0	0
Depreciation, depletion and amortization	1,852	1,520	1,361
Impairment and other	82	54	147
Provision (Benefit) for Income Taxes	695	1,072	585
Investment in affiliates	76	88
Identifiable assets	17,931	15,022
Capital expenditures	4,033	2,589	1,698
Exploration and Production | Eliminations
Segment Reporting Information [Line Items]
Sales and other operating revenues	0	0	0
Midstream
Segment Reporting Information [Line Items]
Sales and other operating revenues	11	0	0
Midstream | Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues	1,349	1,273	1,204
Net income (loss) attributable to Hess Corporation	252	269	286
Interest expense	179	150	105
Depreciation, depletion and amortization	193	181	166
Impairment and other	0	0	0
Provision (Benefit) for Income Taxes	38	27	15
Investment in affiliates	90	94
Identifiable assets	3,984	3,775
Capital expenditures	246	232	183
Midstream | Eliminations
Segment Reporting Information [Line Items]
Sales and other operating revenues	$ 1,338	$ 1,273	$ 1,204

Segment Information - Financi_2

Segment Information - Financial Information by Major Geographic Area (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Sales and other operating revenues	$ 10,511	$ 11,324	$ 7,473
Property, Plant and Equipment— Net	17,432	15,098
Exploration and Production
Segment Reporting Information [Line Items]
Sales and other operating revenues	10,500	11,324	7,473
Property, Plant and Equipment— Net	7,325	6,764
Midstream
Segment Reporting Information [Line Items]
Sales and other operating revenues	11	0	0
Midstream | Variable Interest Entity
Segment Reporting Information [Line Items]
Property, Plant and Equipment— Net	3,229	3,173
Operating Segments | Exploration and Production
Segment Reporting Information [Line Items]
Sales and other operating revenues	10,500	11,324	7,473
Operating Segments | Midstream
Segment Reporting Information [Line Items]
Sales and other operating revenues	1,349	1,273	1,204
Corporate, Interest and Other
Segment Reporting Information [Line Items]
Sales and other operating revenues	0	0	0
Property, Plant and Equipment— Net	7	8
United States | Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues	6,092	7,214	5,378
Property, Plant and Equipment— Net	10,554	9,937
United States | Operating Segments | Exploration and Production
Segment Reporting Information [Line Items]
Sales and other operating revenues	6,081	7,214	5,378
Guyana | Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues	3,494	2,636	754
Property, Plant and Equipment— Net	5,957	4,042
Guyana | Operating Segments | Exploration and Production
Segment Reporting Information [Line Items]
Sales and other operating revenues	3,494	2,636	754
Malaysia and JDA | Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues	925	873	738
Property, Plant and Equipment— Net	872	1,065
Malaysia and JDA | Operating Segments | Exploration and Production
Segment Reporting Information [Line Items]
Sales and other operating revenues	925	873	738
Other | Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues	0	601	603
Property, Plant and Equipment— Net	42	46
Other | Operating Segments | Exploration and Production
Segment Reporting Information [Line Items]
Sales and other operating revenues	$ 0	$ 601	$ 603

Segment Information - Additiona

Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2023 segment
Segment Reporting [Abstract]
Number of operating segments for the Corporation	2

Financial Risk Management Act_3

Financial Risk Management Activities - Notional Amounts of Outstanding Financial Risk Management Derivative Contracts (Detail) - USD ($)	Dec. 31, 2023	Dec. 31, 2022
Foreign Exchange Forwards / Swaps
Derivative [Line Items]
Outstanding gross notional amount	$ 226,000,000	$ 177,000,000
Interest Rate Swaps
Derivative [Line Items]
Outstanding gross notional amount	$ 100,000,000	$ 100,000,000

Financial Risk Management Act_4

Financial Risk Management Activities - Gross & Net Fair Values of Financial Risk Management Derivative Instruments (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Derivatives, Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	$ 0	$ 0
Liabilities - Gross fair value of derivative contracts	(8)	(6)
Gross amount offset in the Consolidate Balance Sheet, Assets	0	0
Gross amount offset in the Consolidate Balance Sheet, Liabilities	0	0
Derivative Asset	0	0
Derivative Liability	$ (8)	$ (6)
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Other assets	Other assets
Derivative Contracts Designated as Hedging Instruments:
Derivatives, Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	$ 0	$ 0
Liabilities - Gross fair value of derivative contracts	(2)	(4)
Derivative Contracts Designated as Hedging Instruments: | Interest Rate Swaps
Derivatives, Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	0	0
Liabilities - Gross fair value of derivative contracts	(2)	(4)
Derivative Contracts Not Designated as Hedging Instruments:
Derivatives, Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	0	0
Liabilities - Gross fair value of derivative contracts	(6)	(2)
Derivative Contracts Not Designated as Hedging Instruments: | Foreign Exchange Forwards / Swaps
Derivatives, Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	0	0
Liabilities - Gross fair value of derivative contracts	$ (6)	$ (2)

Financial Risk Management Act_5

Financial Risk Management Activities - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Increase (decrease) in sales and other operating revenues due to hedging instruments	$ 190	$ 585	$ 243
Unrealized change in fair value of interest rate swaps - increase (decrease)	2	(6)	(3)
Foreign exchange gains (losses) reported in Other, net in the Statement of Consolidated Income	4	(16)	(3)
Net gains (losses) on foreign exchange contracts not designated as hedging instruments	$ 2	$ (14)	$ (1)

Financial Risk Management Act_6

Financial Risk Management Activities - Credit Risk - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Letters of credit - outstanding amount	$ 88	$ 83
Integrated Companies
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Concentration percentage of accounts receivable	40%
Independent E&P Companies
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Concentration percentage of accounts receivable	37%
Refining & Marketing Companies
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Concentration percentage of accounts receivable	12%
Storage & Transportation Companies
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Concentration percentage of accounts receivable	4%
National Oil Companies
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Concentration percentage of accounts receivable	1%
Others
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Concentration percentage of accounts receivable	6%

Financial Risk Management Act_7

Financial Risk Management Activities - Fair Value Measurement - Additional Information (Detail) $ in Millions	Dec. 31, 2023 USD ($)
Fair Value Disclosures [Abstract]
Carrying value of total long-term debt	$ 8,613
Fair value of total long-term debt	$ 9,006

Subsequent Events (Details)

Subsequent Events (Details) - shares shares in Millions		12 Months Ended
	Feb. 08, 2024	Dec. 31, 2023
Hess Midstream LP
Subsequent Event [Line Items]
Percent interest in consolidated entity		38%
Hess Midstream LP | Public Shareholders
Subsequent Event [Line Items]
Noncontrolling interest ownership percentage of GIP		30%
Hess Midstream LP | Global Infrastructure Partners
Subsequent Event [Line Items]
Noncontrolling interest ownership percentage of GIP		32%
Subsequent Event | Scenario Forecast
Subsequent Event [Line Items]
Number of Class A shares of subsidiary public offering (in shares)	11.5
Subsequent Event | Scenario Forecast | Hess Midstream LP
Subsequent Event [Line Items]
Percent interest in consolidated entity	38%
Subsequent Event | Scenario Forecast | Hess Midstream LP | Public Shareholders
Subsequent Event [Line Items]
Noncontrolling interest ownership percentage of GIP	35%
Subsequent Event | Scenario Forecast | Hess Midstream LP | Global Infrastructure Partners
Subsequent Event [Line Items]
Noncontrolling interest ownership percentage of GIP	27%