0001628280-22-004524 | 10-K | XBRL Viewer

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Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Current Assets:
Cash and cash equivalents	$ 2,713	$ 1,739
Accounts receivable:
From contracts with customers	1,062	710
Joint venture and other	149	150
Inventories	223	378
Other current assets	199	104
Total current assets	4,346	3,081
Property, plant and equipment:
Total — at cost	31,178	30,519
Less: Reserves for depreciation, depletion, amortization and lease impairment	16,996	16,404
Property, Plant and Equipment — Net	14,182	14,115
Operating lease right-of-use assets — net	352	426
Finance lease right-of-use assets — net	144	168
Post-retirement benefit assets	409	45
Goodwill	360	360
Deferred income taxes	71	59
Other assets	651	567
Total Assets	20,515	18,821
Current Liabilities:
Accounts payable	220	200
Accrued liabilities	1,710	1,251
Taxes payable	528	81
Current portion of long-term debt	517	10
Current portion of operating and finance lease obligations	89	81
Total current liabilities	3,064	1,623
Long-term debt	7,941	8,286
Long-term operating lease obligations	394	478
Long-term finance lease obligations	200	220
Deferred income taxes	383	342
Asset retirement obligations	1,005	894
Other liabilities and deferred credits	502	643
Total Liabilities	13,489	12,486
Hess Corporation stockholders’ equity:
Common stock, par value $1.00; Authorized 600,000,000 shares. Issued 309,744,953 shares (2020: 306,980,092)	310	307
Capital in excess of par value	6,017	5,684
Retained earnings	379	130
Accumulated other comprehensive income (loss)	(406)	(755)
Total Hess Corporation stockholders’ equity	6,300	5,366
Noncontrolling interests	726	969
Total equity	7,026	6,335
Total Liabilities and Equity	$ 20,515	$ 18,821

Consolidated Balance Sheet (Parenthetical) - $ / shares	Dec. 31, 2021	Dec. 31, 2020
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 1.00	$ 1.00
Common stock, shares authorized (in shares)	600,000,000	600,000,000
Common stock, shares issued (in shares)	309,744,953	306,980,092

Statement of Consolidated Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenues and Non-Operating Income
Sales and other operating revenues	$ 7,473	$ 4,667	$ 6,495
Gains on asset sales, net	29	87	22
Other, net	81	50	(7)
Total revenues and non-operating income	7,583	4,804	6,510
Costs and Expenses
Marketing, including purchased oil and gas	2,034	936	1,736
Operating costs and expenses	1,229	1,218	1,237
Production and severance taxes	172	124	184
Exploration expenses, including dry holes and lease impairment	162	351	233
General and administrative expenses	340	357	397
Interest expense	481	468	380
Depreciation, depletion and amortization	1,528	2,074	2,122
Impairment and other	147	2,126	0
Total costs and expenses	6,093	7,654	6,289
Income (Loss) Before Income Taxes	1,490	(2,850)	221
Provision (benefit) for income taxes	600	(11)	461
Net Income (Loss)	890	(2,839)	(240)
Less: Net income (loss) attributable to noncontrolling interests	331	254	168
Net Income (Loss) Attributable to Hess Corporation	559	(3,093)	(408)
Less: Preferred stock dividends	0	0	4
Net Income (Loss) Attributable to Hess Corporation Common Stockholders	$ 559	$ (3,093)	$ (412)
Net Income (Loss) Attributable to Hess Corporation Per Common Share:
Basic (in dollars per share)	$ 1.82	$ (10.15)	$ (1.37)
Diluted (in dollars per share)	$ 1.81	$ (10.15)	$ (1.37)
Weighted Average Number of Common Shares Outstanding:
Shares outstanding – Basic (in shares)	307.4	304.8	301.2
Weighted Average Number of Common Shares Outstanding (Diluted) (in shares)	309.3	304.8	301.2
Common Stock Dividends Per Share (in dollars per share)	$ 1.00	$ 1.00	$ 1.00

Statement of Consolidated Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net Income (Loss)	$ 890	$ (2,839)	$ (240)
Derivatives designated as cash flow hedges
Effect of hedge (gains) losses reclassified to income	243	(547)	(1)
Income taxes on effect of hedge (gains) losses reclassified to income	0	0	0
Net effect of hedge (gains) losses reclassified to income	243	(547)	(1)
Change in fair value of cash flow hedges	(315)	649	(462)
Income taxes on change in fair value of cash flow hedges	0	0	86
Net change in fair value of cash flow hedges	(315)	649	(376)
Change in derivatives designated as cash flow hedges, after taxes	(72)	102	(377)
Pension and other postretirement plans
(Increase) reduction in unrecognized actuarial losses	355	(205)	(160)
Income taxes on actuarial changes in plan liabilities	0	0	0
(Increase) reduction in unrecognized actuarial losses, net	355	(205)	(160)
Amortization of net actuarial losses	66	47	144
Income taxes on amortization of net actuarial losses	0	0	0
Net effect of amortization of net actuarial losses	66	47	144
Change in pension and other postretirement plans, after taxes	421	(158)	(16)
Other Comprehensive Income (Loss)	349	(56)	(393)
Comprehensive Income (Loss)	1,239	(2,895)	(633)
Less: Comprehensive income (loss) attributable to noncontrolling interests	331	254	168
Comprehensive Income (Loss) Attributable to Hess Corporation	$ 908	$ (3,149)	$ (801)

Statement of Consolidated Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash Flows From Operating Activities
Net income (loss)	$ 890	$ (2,839)	$ (240)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
(Gains) on asset sales, net	(29)	(87)	(22)
Depreciation, depletion and amortization	1,528	2,074	2,122
Impairment and other	147	2,126	0
Exploratory dry hole costs	11	192	49
Exploration lease and other impairment	20	51	17
Pension settlement loss	9	0	93
Stock compensation expense	77	79	85
Noncash (gains) losses on commodity derivatives, net	216	260	116
Provision (benefit) for deferred income taxes and other tax accruals	122	(53)	17
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable	(748)	267	(383)
(Increase) decrease in inventories	135	(117)	(16)
Increase (decrease) in accounts payable and accrued liabilities	241	(533)	4
Increase (decrease) in taxes payable	447	(16)	16
Changes in other operating assets and liabilities	(176)	(71)	(216)
Net cash provided by (used in) operating activities	2,890	1,333	1,642
Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P	(1,584)	(1,896)	(2,433)
Additions to property, plant and equipment - Midstream	(163)	(301)	(396)
Payments for Midstream equity investments	0	0	(33)
Proceeds from asset sales, net of cash sold	427	493	22
Other, net	(5)	(3)	(3)
Net cash provided by (used in) investing activities	(1,325)	(1,707)	(2,843)
Cash Flows From Financing Activities
Net borrowings (repayments) of debt with maturities of 90 days or less	(80)	152	32
Debt with maturities of greater than 90 days – Borrowings	750	1,000	760
Debt with maturities of greater than 90 days – Repayments	(510)	0	(8)
Proceeds from sale of Class A shares of Hess Midstream LP	178	0	0
Payments on finance lease obligations	(10)	(7)	(49)
Common stock acquired and retired	0	0	(25)
Cash dividends paid	(311)	(309)	(316)
Employee stock options exercised	77	15	40
Noncontrolling interests, net	(664)	(261)	(353)
Other, net	(21)	(22)	(29)
Net cash provided by (used in) financing activities	(591)	568	52
Net Increase (Decrease) in Cash and Cash Equivalents	974	194	(1,149)
Cash and Cash Equivalents at Beginning of Year	1,739	1,545	2,694
Cash and Cash Equivalents at End of Year	$ 2,713	$ 1,739	$ 1,545

Statement of Consolidated Equity - USD ($) $ in Millions	Total	Mandatory Convertible Preferred Stock	Common Stock	Capital in Excess of Par	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Total Hess Stockholders' Equity	Noncontrolling Interests
Balance at Dec. 31, 2018	$ 10,888	$ 1	$ 291	$ 5,386	$ 4,257	$ (306)	$ 9,629	$ 1,259
Net income (loss)	(240)				(408)		(408)	168
Other comprehensive income (loss)	(393)					(393)	(393)
Preferred stock conversion	0	1	12	11			0
Share-based compensation	125		2	123			125
Dividends on preferred stock	(4)				(4)		(4)
Dividends on common stock	(310)				(310)		(310)
Conversion of Midstream structure	(7)			15			15	(22)
Sale of water business to Hess Infrastructure Partners	0			78			78	(78)
Noncontrolling interests, net	(353)							(353)
Balance at Dec. 31, 2019	9,706	0	305	5,591	3,535	(699)	8,732	974
Net income (loss)	(2,839)				(3,093)		(3,093)	254
Other comprehensive income (loss)	(56)					(56)	(56)
Share-based compensation	90		2	93	(5)		90
Dividends on common stock	(307)				(307)		(307)
Noncontrolling interests, net	(259)							(259)
Balance at Dec. 31, 2020	6,335	0	307	5,684	130	(755)	5,366	969
Net income (loss)	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	$ 0	$ 310	$ 6,017	$ 379	$ (406)	$ 6,300	$ 726

Nature of Operations, Basis of Presentation and Summary of Accounting Policies	12 Months Ended
	Dec. 31, 2021
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 primarily in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA), and Malaysia. We conduct exploration activities primarily offshore Guyana, the U.S. Gulf of Mexico, and offshore Suriname and Canada. Our Midstream operating segment, which is comprised of Hess Corporation’s approximate 43.5% consolidated ownership interest in Hess Midstream LP at December 31, 2021 (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. Basis of Presentation and Principles of Consolidation: The consolidated financial statements include the accounts of Hess Corporation and entities in which we own more than a 50% voting interest. Commencing December 16, 2019, we consolidate Hess Midstream LP, a variable interest entity that acquired Hess Infrastructure Partners LP (HIP), based on our conclusion that we have the power through Hess Corporation’s approximate 43.5% consolidated ownership interest in Hess Midstream LP to direct those activities that most significantly impact the economic performance of Hess Midstream LP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to Hess Midstream LP. Prior to December 16, 2019, we consolidated HIP, also a variable interest entity based on the conclusion that we had the power to direct the activities that most significantly impacted the economic performance of HIP, and were obligated to absorb losses or had the right to receive benefits that could potentially be significant to HIP. This conclusion was based on a qualitative analysis that considered Hess Midstream LP’s governance structure, the commercial agreements between Hess Midstream LP and us, and the voting rights established between the members, which provide us the ability to control the operations of Hess Midstream LP. 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, pension 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 Statement 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 to eleven years. 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 is 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. 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. Midstream Our Midstream segment provides gathering, compression, processing, fractionation, storage, terminaling, loading and transportation, and water handling services. The Midstream segment has multiple long-term, fee-based commercial agreements with certain subsidiaries of Hess, each generally with an initial ten-year term that can be extended for an additional ten-year term at the unilateral right of Hess Midstream. These contracts have minimum volumes the customer is obligated to provide each calendar quarter. The minimum volume commitments are subject to fluctuation based on nominations covering substantially all of our E&P segment’s production and projected third-party volumes that will be purchased in the Bakken. As the minimum volume commitments are subject to fluctuation, and as these contracts contain fee inflation escalators and fee recalculation mechanisms, substantially all of the transaction price at contract inception is variable. The midstream segment also has long-term, fee based commercial agreements for water handling services with a subsidiary of Hess with an initial 14 year term that can be extended for an additional ten-year term at the unilateral right of Hess Midstream. Water handling services are provided for an agreed-upon fee per barrel or the reimbursement of third-party fees. The Midstream segment’s responsibilities to provide each of the above services for each year under each of the commercial agreements are considered separate, distinct performance obligations. Revenue is recognized for each performance obligation under these commercial agreements over-time as services are rendered using the output method, measured using the amount of volumes serviced during the period. The Midstream segment has elected the practical expedient under the provisions of ASC 606, Revenue from Contracts with Customers to recognize revenue in the amount it is entitled to invoice. If the commercial agreements have ship-or-pay provisions, the Midstream segment’s responsibility to stand-ready to service a minimum volume over each quarterly commitment period represent separate, distinct performance obligations. Shortfall payments received under ship-or-pay provisions are recognized as revenue in the calendar quarter the shortfall occurs as the customer does not have make-up rights beyond the calendar quarter end of the quarterly commitment period. 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. On December 30, 2020, Hess Midstream exercised its renewal options to extend the terms of certain gas gathering, crude oil gathering, gas processing and fractionation, storage, and terminal and export commercial agreements for the secondary term through December 31, 2033. There were no changes to any provisions of the existing commercial agreements as a result of the exercise of the renewal options. 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 1st or when events or circumstances indicate that the carrying amount of the goodwill may not be recoverable. To determine whether goodwill is impaired, the fair value of a reporting unit is compared with 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 charge 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, 2021, 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. Right-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 on a straight-line basis based on the nature of operation for which the ROU asset is utilized. Leases with an initial term of 12 months or less are not recorded on the balance sheet as permitted under ASC 842, Leases. We recognize lease cost for short-term leases on a straight-line basis over the term of the lease. Some of our leases include one or more options to renew. The renewal option is at our sole discretion and is not included in the lease term for measurement of the lease obligation unless we are reasonably certain at the commencement date of the lease, to renew the lease. 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 recorded deferred tax assets for those losses and credits. Additionally, we have deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If, when tested under the relevant accounting standards, it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount that is expected to be realized. The accounting standards require the evaluation of all available positive and negative evidence giving weight based on the evidence’s relative objectivity. In evaluating potential sources of positive evidence, we consider the reversal of taxable temporary differences, taxable income in carryback and carryforward periods, the availability of tax planning strategies, the existence of appreciated assets, estimates of future taxable income, and other factors. 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 no longer 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 material 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, and the asset is depreciated over 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 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 or goodwill. We determine fair value in accordance with the fair value measurements accounting standard which established a hierarchy for the inputs used to measure fair value based on the source of the inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3), including discounted cash flows and other unobservable data. Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market. Multiple inputs 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‑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: 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: 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 are expensed as incurred. Capital improvements are recorded as additions in Property, plant and equipment. Environmental Expenditures: We accrue and expense the undiscounted environmental costs necessary to remediate existing conditions related to past operations when the future costs are probable and reasonably estimable. At year‑end 2021, our reserve for estimated remediation liabilities was approximately $60 million. Environmental expenditures that increase the life or efficiency of property or reduce or prevent future adverse impacts to the environment are capitalized.

Inventories

12 Months Ended

Dec. 31, 2021

Inventory Disclosure [Abstract]

Inventories

2. Inventories

Inventories at December 31 were as follows:


	2021		2020

	(In millions)
Crude oil and natural gas liquids	$	52	$	226
Materials and supplies	171		152
Total Inventories	$	223	$	378

At December 31, 2020, crude oil inventories included $164 million associated with the cost of 4.2 million barrels of crude oil transported and stored on two chartered VLCCs for sale in Asian markets. The two VLCC cargos were sold in the first quarter of 2021.

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2021

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

3. Property, Plant and Equipment

Property, plant and equipment at December 31 were as follows:


	2021		2020

	(In millions)
Exploration and Production
Unproved properties	$	184	$	164
Proved properties	2,877		2,930
Wells, equipment and related facilities	23,745		23,224
	26,806		26,318
Midstream	4,342		4,163
Corporate and Other	30		38
Total — at cost	31,178		30,519
Less: Reserves for depreciation, depletion, amortization and lease impairment	16,996		16,404
Property, Plant and Equipment — Net	$	14,182	$	14,115

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:


	2021		2020		2019

	(In millions)
Balance at January 1	$	459	$	584	$	418
Additions to capitalized exploratory well costs pending the determination of proved reserves	222		111		224
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	—		(111)		(58)
Capitalized exploratory well costs charged to expense	—		(125)		—

Balance at December 31	$	681	$	459	$	584
Number of Wells at December 31	35		22		31

During the three years ended December 31, 2021, additions to capitalized exploratory well costs primarily related to drilling at the Stabroek Block, offshore Guyana. In 2019, other drilling activity included the Esox prospect in the Gulf of Mexico.

Reclassifications to wells, facilities and equipment based on the determination of proved reserves in 2020 resulted from sanctions of the Payara Field development, the third sanctioned project on the Stabroek Block, offshore Guyana, and an additional phase of development at the North Malay Basin, offshore Peninsular Malaysia. In 2019, reclassifications to wells, facilities and equipment resulted from sanction of the Liza Phase 2 development on the Stabroek Block and the Esox tieback well to the Tubular Bells Field in the Gulf of Mexico.

Capitalized exploratory well costs charged to expense in 2020 of $125 million primarily related to the northern portion of the Shenzi Field (Hess 28%) in the Gulf of Mexico due to reprioritization of our forward capital program in response to the significant decline in crude oil prices. The preceding table excludes well costs incurred and expensed during 2021 of $11 million (2020: $67 million; 2019: $49 million).

Exploratory well costs capitalized for greater than one year following completion of drilling were $459 million at December 31, 2021, separated by year of completion as follows (in millions):


2020	$	117
2019	173
2018	105
2017	27
2016 and prior	37
	$	459

Guyana: Approximately 90% of the capitalized well costs in excess of one year relate to successful exploration wells where hydrocarbons were encountered on the Stabroek Block (Hess 30%). In the fourth quarter of 2021, the operator submitted a fourth development plan for the Yellowtail Field to the Government of Guyana for approval. The operator also plans further appraisal drilling and is conducting pre-development planning for additional phases of development.

JDA: Approximately 8% 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: Approximately 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 one successful exploration well. Subsurface evaluation and pre-development studies are ongoing.

Hess Midstream LP	12 Months Ended
Hess Midstream LP	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Hess Midstream LP	4. Hess Midstream LP HIP was initially formed on May 21, 2015, with Hess selling 50% of HIP to GIP for approximately $2.6 billion on July 1, 2015. On April 10, 2017, HIP completed an initial public offering (IPO) of 16,997,000 common units, representing 30.5% limited partnership interests in its subsidiary Hess Midstream Partners LP (Hess Midstream Partners), for net proceeds of approximately $365.5 million. In connection with the IPO, HIP contributed a 20% controlling economic interest in each of Hess North Dakota Pipeline Operations LP, Hess TGP Operations LP, and Hess North Dakota Export Logistics Operations LP, and a 100% economic interest in Hess Mentor Storage Holdings LLC (collectively the “Contributed Businesses”). In exchange for the contributed businesses, Hess and GIP each received common and subordinated units representing a direct 33.75% limited partner interest in Hess Midstream Partners and a 50% indirect ownership interest through HIP in Hess Midstream Partners’ general partner, which had a 2% economic interest in Hess Midstream Partners plus incentive distribution rights. On December 16, 2019, Hess Midstream Partners acquired HIP, including HIP’s 80% interest in Hess Midstream Partners’ oil and gas midstream assets, HIP’s water services business and the outstanding economic general partner interest and incentive distribution rights in Hess Midstream Partners LP. In addition, Hess Midstream Partners’ organizational structure converted from a master limited partnership into an “Up-C” structure in which Hess Midstream Partners’ public unitholders received newly issued Class A shares in a new public entity named Hess Midstream LP (Hess Midstream), which is taxed as a corporation for U.S. federal and state income tax purposes. Hess Midstream Partners changed its name to “Hess Midstream Operations LP” (HESM Opco) and became a consolidated subsidiary of Hess Midstream, the new publicly listed entity. As consideration for the acquisition, Hess received a cash payment of $301 million and approximately 115 million newly issued HESM Opco Class B units. After giving effect to the acquisition and related transactions, public shareholders of Class A shares in Hess Midstream owned 6% of the consolidated entity on an as-exchanged basis and Hess and GIP each owned 47% of the consolidated entity on an as-exchanged basis, primarily through the sponsors’ ownership of Class B units in HESM Opco that are exchangeable into Class A shares of Hess Midstream on a one-for-one basis. In March 2021, Hess Midstream completed an underwritten public equity offering of 6.9 million Class A shares held by Hess and GIP. These Class A shares of Hess Midstream were obtained by Hess and GIP through the exchange of 6.9 million of their Class B units of HESM Opco. As a result of this transaction, Hess received net proceeds of $70 million and recorded an increase in additional paid-in capital and noncontrolling interests of $56 million and $41 million, respectively. The increase of $41 million in noncontrolling interests is comprised of $14 million resulting from the change in ownership and $27 million due to the recognition of a deferred tax asset as a result of an increase in the tax basis of Hess Midstream LP's investment in HESM Opco. In August 2021, HESM Opco repurchased 31.25 million Class B units held by Hess and GIP for $750 million. Hess received net proceeds of $375 million. 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 additional paid-in capital and a decrease in noncontrolling interests of $28 million, and an increase in deferred tax assets and noncontrolling interests of $15 million due to a decrease in the book basis of Hess Midstream LP's investment in HESM Opco. The $375 million paid to GIP was recorded as a reduction to noncontrolling interests. In October 2021, Hess Midstream completed an underwritten public equity offering of approximately 8.6 million Class A Shares held by Hess and GIP. These Class A shares of Hess Midstream were obtained by Hess and GIP through the exchange of approximately 8.6 million of their Class B units of HESM Opco. As a result of this transaction, Hess received net proceeds of $108 million and recorded an increase in additional paid-in capital and noncontrolling interests of $96 million and $62 million, respectively. The increase of $62 million in noncontrolling interests is comprised of $12 million resulting from the change in ownership and $50 million due to the recognition of a deferred tax asset as a result of an increase in the tax basis of Hess Midstream LP's investment in HESM Opco. After giving effect to the above transactions in 2021, public shareholders of Class A shares of Hess Midstream own approximately 13%, and Hess and GIP each own approximately 43.5%, of the consolidated entity on an as-exchanged basis at December 31, 2021. Little Missouri 4 (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 and Targa Resources Corp. Hess Midstream 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 2021, these processing fees were $28 million (2020: $26 million; 2019: $6 million) and are included in Operating costs and expenses in the Statement of Consolidated Income. At December 31, 2021, Hess Midstream liabilities totaling $2,694 million (2020: $2,026 million) are on a nonrecourse basis to Hess Corporation, while Hess Midstream assets available to settle the obligations of Hess Midstream included cash and cash equivalents totaling $2 million (2020: $3 million), property, plant and equipment, net totaling $3,125 million (2020: $3,111 million) and an equity-method investment in LM4 of $102 million (2020: $108 million).

Accrued Liabilities

12 Months Ended

Dec. 31, 2021

Payables and Accruals [Abstract]

Accrued Liabilities

5. Accrued Liabilities

The following table provides detail of our accrued liabilities at December 31:


	2021		2020

	(In millions)
Accrued capital expenditures	$	479	$	345
Accrued operating and marketing expenditures	462		325
Accrued payments to royalty and working interest owners	253		170
Current portion of asset retirement obligations	185		105
Accrued interest on debt	138		126
Accrued compensation and benefits	124		117
Other accruals	69		63
Total Accrued Liabilities	$	1,710	$	1,251

Leases

12 Months Ended

Dec. 31, 2021

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

	2021		2020		2021		2020

	(In millions)
Right-of-use assets — net (a)	$	352	$	426	$	144	$	168
Lease obligations:
Current	$	70	$	63	$	19	$	18
Long-term	394		478		200		220
Total lease obligations	$	464	$	541	$	219	$	238

(a)At December 31, 2021, finance lease ROU assets had a cost of $212 million (2020: $212 million) and accumulated amortization of $68 million (2020: $44 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, 2021 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, 2021, the remaining lease term for the FSO was 11.8 years.

Maturities of lease obligations at December 31, 2021 were as follows:


	Operating Leases		Finance Leases

	(In millions)
2022	$	87	$	36
2023	75		36
2024	69		36
2025	64		36
2026	49		31
Remaining years	219		145
Total lease payments	563		320
Less: Imputed interest	(99)		(101)
Total lease obligations	$	464	$	219

The following information relates to the operating and finance leases at December 31:

Operating Leases

Finance Leases

2021

2020

2021

2020

Weighted average remaining lease term

9.9 years

10.3 years

11.8 years

12.8 years

Range of remaining lease terms

0.1 - 14.5 years

0.1 - 15.5 years

11.8 years

12.8 years

Weighted average discount rate

4.1%

4.0%

7.9%

The components of lease costs for the years ended December 31, 2021 and 2020 were as follows:


	2021		2020

	(In millions)
Operating lease cost	$	88	$	200
Finance lease cost:
Amortization of leased assets	24		31
Interest on lease obligations	18		20
Short-term lease cost (a)	137		199
Variable lease cost (b)	21		38
Sublease income (c)	(17)		(15)
Total lease cost	$	271	$	473

(a)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.

(b)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.

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

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

Supplemental cash flow information related to leases for the years ended December 31, 2021 and 2020 were as follows:


	Operating Leases				Finance Leases

	2021		2020		2021		2020

	(In millions)
Cash paid for amounts included in the measurement of lease obligations:
Operating cash flows (a)	$	87	$	218	$	18	$	20
Financing cash flows (a)	—		—		18		17
Noncash transactions:
Leased assets recognized for new lease obligations incurred	12		51		—		—
Changes in leased assets and lease obligations due to lease modifications (b)	29		123		—		—

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

(b)In 2020, primarily related to negotiated extensions of an office lease and offshore drilling rig leases.

Leases

6. Leases

Operating and finance lease obligations at December 31 included in the Consolidated Balance Sheet were as follows:


	Operating Leases				Finance Leases

	2021		2020		2021		2020

	(In millions)
Right-of-use assets — net (a)	$	352	$	426	$	144	$	168
Lease obligations:
Current	$	70	$	63	$	19	$	18
Long-term	394		478		200		220
Total lease obligations	$	464	$	541	$	219	$	238

(a)At December 31, 2021, finance lease ROU assets had a cost of $212 million (2020: $212 million) and accumulated amortization of $68 million (2020: $44 million).

The nature of our leasing arrangements at December 31, 2021 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.

Maturities of lease obligations at December 31, 2021 were as follows:


	Operating Leases		Finance Leases

	(In millions)
2022	$	87	$	36
2023	75		36
2024	69		36
2025	64		36
2026	49		31
Remaining years	219		145
Total lease payments	563		320
Less: Imputed interest	(99)		(101)
Total lease obligations	$	464	$	219

The following information relates to the operating and finance leases at December 31:

Operating Leases

Finance Leases

2021

2020

2021

2020

Weighted average remaining lease term

9.9 years

10.3 years

11.8 years

12.8 years

Range of remaining lease terms

0.1 - 14.5 years

0.1 - 15.5 years

11.8 years

12.8 years

Weighted average discount rate

4.1%

4.0%

7.9%

The components of lease costs for the years ended December 31, 2021 and 2020 were as follows:


	2021		2020

	(In millions)
Operating lease cost	$	88	$	200
Finance lease cost:
Amortization of leased assets	24		31
Interest on lease obligations	18		20
Short-term lease cost (a)	137		199
Variable lease cost (b)	21		38
Sublease income (c)	(17)		(15)
Total lease cost	$	271	$	473

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

Supplemental cash flow information related to leases for the years ended December 31, 2021 and 2020 were as follows:


	Operating Leases				Finance Leases

	2021		2020		2021		2020

	(In millions)
Cash paid for amounts included in the measurement of lease obligations:
Operating cash flows (a)	$	87	$	218	$	18	$	20
Financing cash flows (a)	—		—		18		17
Noncash transactions:
Leased assets recognized for new lease obligations incurred	12		51		—		—
Changes in leased assets and lease obligations due to lease modifications (b)	29		123		—		—

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

(b)In 2020, primarily related to negotiated extensions of an office lease and offshore drilling rig leases.

Debt

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Debt

7. Debt

Total debt at December 31 consisted of the following:


	2021		2020

	(In millions)
Debt - Hess Corporation:
Senior unsecured fixed-rate public notes:
3.500% due 2024	$	299	$	299
4.300% due 2027	995		994
7.875% due 2029	464		464
7.300% due 2031	628		628
7.125% due 2033	537		537
6.000% due 2040	742		741
5.600% due 2041	1,236		1,236
5.800% due 2047	494		494
Total senior unsecured fixed-rate public notes	5,395		5,393
Term loan facility	497		988
Fair value adjustments - interest rate hedging	2		5
Total Debt - Hess Corporation	$	5,894	$	6,386

Debt - Midstream (Hess Midstream Operations LP):
Senior unsecured fixed-rate public notes:
5.625% due 2026	$	791	$	789
5.125% due 2028	543		542
4.250% due 2030	739		—
Total senior unsecured fixed-rate public notes	2,073		1,331
Term loan A facility	387		395
Revolving credit facility	104		184
Total Debt - Midstream	$	2,564	$	1,910

Total Debt:
Current portion of long-term debt	$	517	$	10
Long-term debt	7,941		8,286
Total Debt	$	8,458	$	8,296

At December 31, 2021, the maturity profile of total debt was as follows:


	Total		Hess Corporation		Midstream

	(In millions)
2022	$	520	$	500	$	20
2023	30		—		30
2024	744		300		444
2025	—		—		—
2026	800		—		800
Thereafter	6,438		5,138		1,300
Total Borrowings	8,532		5,938		2,594
Less: Deferred financing costs and discounts	(74)		(44)		(30)
Total Debt (excluding interest)	$	8,458	$	5,894	$	2,564

No interest was capitalized in 2021 or 2020 (2019: $38 million).

Debt – Hess Corporation:

Senior unsecured fixed-rate public notes:

At December 31, 2021, Hess Corporation’s fixed-rate public notes had a gross principal amount of $5,438 million (2020: $5,438 million) and a weighted average interest rate of 5.9% (2020: 5.9%). The indentures for our fixed-rate public 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, 2021, Hess Corporation was in compliance with this financial covenant.

Term loan and credit facility:

In March 2020, we entered into a $1 billion three year term loan agreement with a maturity date of March 16, 2023. In July 2021, we repaid $500 million of the $1 billion outstanding under the term loan, and in February 2022, we repaid the remaining $500 million. The remaining $500 million has been classified as Current portion of long-term debt in our Consolidated Balance Sheet at December 31, 2021 as it was our intent to repay the remaining $500 million in the first quarter of 2022.

In 2019, we entered into a $3.5 billion revolving credit facility with a maturity date of May 15, 2023. In April 2021, we amended this credit facility by extending this facility's expiration date for one year to May 2024 and incorporating customary provisions for the eventual replacement of LIBOR among other changes as set forth in the amended credit agreement. Borrowings on the facility will generally bear interest at 1.40% above LIBOR, though the interest rate is subject to adjustment if our credit rating changes. At December 31, 2021, Hess Corporation had no outstanding borrowings or letters of credit under this facility.

The revolving credit facility and term loan are 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 and the term loan agreement). As of December 31, 2021, Hess Corporation was in compliance with these financial covenants.

The most restrictive of the financial covenants related to our fixed-rate public notes and our term loan and revolving credit facility would allow us to borrow up to an additional $1,843 million of secured debt at December 31, 2021.

Other outstanding letters of credit at December 31 were as follows:


	2021		2020

	(In millions)
Committed lines (a)	$	29	$	54
Uncommitted lines (a)	230		215
Total	$	259	$	269

(a)At December 31, 2021, committed and uncommitted lines have expiration dates through 2022.

Debt - Midstream:

Senior unsecured fixed-rate public notes:

In November 2017, HIP issued $800 million in aggregate principal amount of 5.625% fixed-rate senior unsecured notes due in 2026. In December 2019, in connection with the acquisition of HIP and corporate restructuring described in Note 4, Hess Midstream LP, HESM Opco assumed $800 million of outstanding HIP senior unsecured notes in a par-for-par exchange. In addition, in December 2019, HESM Opco issued $550 million in aggregate principal amount of 5.125% fixed-rate senior unsecured notes due in 2028 to finance the acquisition of HIP and repay outstanding borrowings under HIP’s credit facilities. 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. These 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.

Credit facilities:

At December 31, 2021, HESM Opco had $1.4 billion of senior secured syndicated credit facilities maturing December 2024, consisting of a $1 billion 5-year revolving credit facility and a fully drawn $400 million 5-year term loan A facility. The revolving credit facility can be used for borrowings and letters of credit to fund HESM Opco’s operating activities, capital expenditures, distributions and for other general corporate purposes. Borrowings under the 5-year term loan A facility will generally bear interest at LIBOR plus an applicable margin ranging from 1.55% to 2.50%, while the applicable margin for the 5-year syndicated revolving credit facility ranges from 1.275% to 2.000%. Pricing levels for the facility fee and interest-rate margins are based on HESM Opco’s ratio of total debt to EBITDA (as defined in the credit facilities). If HESM Opco obtains an investment grade credit rating, the pricing levels will be based on HESM Opco’s credit ratings in effect from time to time. The credit facilities contain covenants that require HESM Opco to maintain a ratio of total debt to EBITDA (as defined in the credit facilities) for the prior four fiscal quarters of not greater than 5.00 to 1.00 as of the last day of each fiscal quarter (5.50 to 1.00 during the specified period following certain acquisitions) and, prior to HESM Opco obtaining an investment grade credit rating, a ratio of secured debt to EBITDA for the prior four fiscal quarters of not greater than 4.00 to 1.00 as of the last day of each fiscal quarter. HESM Opco was in compliance with these financial covenants at December 31, 2021. 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, 2021, borrowings of $104 million were drawn

under HESM Opco’s revolving credit facility, and borrowings of $390 million, excluding deferred issuance costs, were drawn under HESM Opco’s term loan A facility. Borrowings under these credit facilities are non-recourse to Hess Corporation.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References

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-Name Accounting Standards Codification
-Topic 470
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-Paragraph 1B
-Subparagraph (h)
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+ Details

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2021

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:


	2021		2020

	(In millions)
Balance at January 1	$	999	$	1,024
Liabilities incurred	229		36
Liabilities settled or disposed of	(207)		(161)
Accretion expense	44		46
Revisions of estimated liabilities	126		52
Foreign currency remeasurement	(1)		2
Balance at December 31	$	1,190	$	999

Total Asset Retirement Obligations at December 31:
Current portion of asset retirement obligations	$	185	$	105
Long-term asset retirement obligations	1,005		894
Total at December 31	$	1,190	$	999

The liabilities incurred in 2021 on Hess owned properties primarily relate to operations in the U.S. and Guyana while liabilities incurred in 2020 primarily relate to operations in Guyana, the U.S. and Malaysia. In August 2020, Fieldwood and related entities filed for bankruptcy relief under Chapter 11 of the U.S. Bankruptcy Code. Fieldwood’s Bankruptcy Plan, which was approved by the U.S. Bankruptcy Court in June 2021, includes 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, in October 2021 and February 2022, we received decommissioning orders from the BSEE requiring us to decommission certain wells and related facilities located on six of the seven West Delta leases. We expect to receive additional orders covering the remainder of the West Delta decommissioning obligations in the near future and are actively engaged with the BSEE to agree on the scope and timing of decommissioning activities. Our decommissioning obligation derives from our former ownership of the facilities. We are seeking contribution from other parties that owned an interest in the facilities. Liabilities incurred in 2021 include $147 million representing total estimated abandonment obligations in the West Delta Field. Potential recoveries from other parties that previously owned an interest in the West Delta Field have not been recognized as of December 31, 2021.

The liabilities settled or disposed of in 2021 primarily result from the sale of our interests in Denmark and abandonment activity completed in the Gulf of Mexico and the Bakken. Liabilities settled or disposed of in 2020 primarily result from an asset sale in the Gulf of Mexico and abandonment activity completed in the Gulf of Mexico, the Bakken and the U.K. North Sea. Revisions of estimated liabilities in 2021 and 2020 primarily reflect an acceleration of planned abandonment activity in the Gulf of Mexico and 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 $233 million at December 31, 2021 (2020: $207 million).

Retirement Plans

12 Months Ended

Dec. 31, 2021

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 postretirement 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 Pension Plans				Unfunded Pension Plan				Postretirement Medical Plan
	2021		2020		2021		2020		2021		2020

	(In millions)
Change in Benefit Obligation
Balance at January 1,	$	3,085	$	2,667	$	269	$	242	$	65	$	75
Service cost	41		37		10		13		3		3
Interest cost	52		68		3		5		1		1
Actuarial (gains) loss (a)	(126)		385		(8)		26		(3)		(8)
Benefit payments (b)	(100)		(93)		(26)		(17)		(7)		(6)

Plan amendments	2		—		—		—		—		—

Foreign currency exchange rate changes	(6)		21		—		—		—		—
Balance at December 31, (c)	2,948		3,085		248		269		59		65
Change in Fair Value of Plan Assets
Balance at January 1,	$	3,043	$	2,732	$	—	$	—	$	—	$	—
Actual return on plan assets	417		378		—		—		—		—
Employer contributions	6		4		26		17		7		6
Benefit payments (b)	(100)		(93)		(26)		(17)		(7)		(6)
Foreign currency exchange rate changes	(9)		22		—		—		—		—
Balance at December 31,	3,357		3,043		—		—		—		—

Funded Status (Plan assets greater (less) than benefit obligations) at December 31,	$	409	$	(42)	$	(248)	$	(269)	$	(59)	$	(65)

Unrecognized Net Actuarial (Gains) Losses	$	501	$	900	$	66	$	86	$	(21)	$	(19)

(a)Changes in discount rates resulted in actuarial gains of $178 million in 2021 (2020: $387 million of actuarial losses). Changes in the inflation assumptions for our U.K. pension plan resulted in actuarial losses of $36 million in 2021 (2020: $24 million of actuarial losses). Changes in mortality assumptions resulted in actuarial losses of $7 million in 2021 (2020: $18 million of actuarial gains). Changes in all other assumptions, including demographic assumptions, resulted in actuarial gains of $2 million in 2021 (2020: $10 million of actuarial losses).

(b)Benefit payments include lump-sum settlement payments of $34 million in 2021 (2020: $23 million).

(c)At December 31, 2021, the accumulated benefit obligation for the funded and unfunded defined benefit pension plans was $2,856 million and $208 million, respectively (2020: $2,993 million and $228 million, respectively).

Amounts recognized in the Consolidated Balance Sheet at December 31 consisted of the following:


	Funded Pension Plans				Unfunded Pension Plan				Postretirement Medical Plan
	2021		2020		2021		2020		2021		2020

	(In millions)
Noncurrent assets	$	409	$	45	$	—	$	—	$	—	$	—
Current liabilities	—		—		(34)		(49)		(6)		(7)
Noncurrent liabilities	—		(87)		(214)		(220)		(53)		(58)
Pension assets / (accrued benefit liability)	$	409	$	(42)	$	(248)	$	(269)	$	(59)	$	(65)

Accumulated other comprehensive (income) loss, pre-tax (a)	$	501	$	900	$	66	$	86	$	(21)	$	(19)

(a)The after‑tax deficit reflected in Accumulated other comprehensive income (loss) was $338 million at December 31, 2021 (2020: $759 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
	2021		2020		2019		2021		2020		2019

	(In millions)
Service cost	$	51	$	50	$	44	$	3	$	3	$	2
Interest cost	55		73		89		1		1		2
Expected return on plan assets	(197)		(180)		(180)		—		—		—
Amortization of unrecognized net actuarial losses (gains)	58		48		52		(1)		(1)		(1)
Settlement loss	9		—		93		—		—		—
Curtailment gain	—		—		—		—		—		—

Net Periodic Benefit Cost / (Income) (a)	$	(24)	$	(9)	$	98	$	3	$	3	$	3

(a)Net non-service cost, which is included in Other, net in the Statement of Consolidated Income, was income of $75 million in 2021 (2020: $59 million of income; 2019: $55 million of expense).

In 2019, the trust for the Hess Corporation Employees’ Pension Plan (the “Plan”) purchased a single premium annuity contract at a cost of $249 million using assets of the Plan to settle and transfer certain of its obligations to a third party. The settlement transaction resulted in a noncash charge of $88 million to recognize unamortized pension actuarial losses that is included in Other, net in the Statement of Consolidated Income.

In 2022, we forecast service cost for our pension and postretirement medical plans to be approximately $50 million and net non-service cost of approximately $135 million of income, which is comprised of interest cost of approximately $65 million, amortization of unrecognized net actuarial losses of approximately $15 million, and estimated expected return on plan assets of approximately $215 million.

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:


	2021	2020	2019
Benefit Obligations:
Discount rate	2.5%	2.2%	2.9%
Rate of compensation increase	3.8%	3.8%	3.8%

Net Periodic Benefit Cost:
Discount rate
Service cost	2.6%	3.2%	3.9%
Interest cost	1.7%	2.6%	3.4%
Expected return on plan assets	6.6%	6.7%	7.1%
Rate of compensation increase	3.8%	3.8%	3.8%

The actuarial assumptions used to determine benefit obligations at December 31 for the postretirement medical plan were as follows:


	2021	2020	2019
Discount rate	2.4%	1.9%	2.8%
Initial health care trend rate	5.5%	6.0%	6.5%
Ultimate trend rate	4.0%	4.5%	4.5%
Year in which ultimate trend rate is reached	2046	2038	2038

The assumptions used to determine net periodic benefit cost for each year were established at the end of each previous year while the assumptions used to determine benefit obligations were established at each year‑end. The net periodic benefit cost and the actuarial present value of benefit obligations are based on actuarial assumptions that are reviewed on an annual basis. The discount rate is 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 return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of pension assets to that asset category. The future expected return assumptions for individual asset categories are largely based on inputs from various investment experts regarding their future return expectations for particular asset categories.

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 for plan assets are 45% equity securities, 35% 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, 2021 and 2020 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 Value (c)		Total

	(In millions)
December 31, 2021
Cash and Short-Term Investment Funds	$	19	$	—	$	—	$	—	$	19
Equities:
U.S. equities (domestic)	601		—		—		87		688
International equities (non-U.S.)	73		56		—		375		504
Global equities (domestic and non-U.S.)	—		7		—		224		231
Fixed Income:
Treasury and government related (a)	—		361		—		41		402
Mortgage-backed securities (b)	—		128		—		63		191
Corporate	128		452		—		55		635
Other:
Hedge funds	—		—		—		81		81
Private equity funds	—		—		—		382		382
Real estate funds	29		—		—		195		224
Total investments	$	850	$	1,004	$	—	$	1,503	$	3,357
December 31, 2020
Cash and Short-Term Investment Funds	$	44	$	—	$	—	$	—	$	44
Equities:
U.S. equities (domestic)	585		—		—		164		749
International equities (non-U.S.)	94		43		—		352		489
Global equities (domestic and non-U.S.)	—		8		—		217		225
Fixed Income:
Treasury and government related (a)	—		350		—		49		399
Mortgage-backed securities (b)	—		116		—		70		186
Corporate	—		381		—		62		443
Other:
Hedge funds	—		—		—		73		73
Private equity funds	—		—		—		251		251
Real estate funds	23		—		—		161		184
Total investments	$	746	$	898	$	—	$	1,399	$	3,043

(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, 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 of fixed income securities. Individual fixed income securities are generally priced based on

evaluated prices from independent pricing services, which are monitored and provided by the 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 2022, we expect to contribute approximately $45 million to our funded pension plans.

Estimated future benefit payments by the funded and unfunded pension plans, and the postretirement medical plan, which reflect expected future service, are as follows (in millions):


2022	$	131
2023	132
2024	137
2025	125
2026	131
Years 2027 to 2031	662

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 $18 million in 2021 for contributions to these plans (2020: $22 million; 2019: $20 million).

- Definition

The entire disclosure for retirement benefits.

+ References

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+ Details

Revenue

12 Months Ended

Dec. 31, 2021

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
2021
Sales of our 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 revenues from contracts with customers	5,540		781		738		624		7,683		1,204		(1,204)		7,683
Other operating revenues (b)	(162)		(27)		—		(21)		(210)		—		—		(210)
Total sales and other operating revenues	$	5,378	$	754	$	738	$	603	$	7,473	$	1,204	$	(1,204)	$	7,473
2020
Sales of our net production volumes:
Crude oil revenue	$	1,898	$	278	$	34	$	153	$	2,363	$	—	$	—	$	2,363
Natural gas liquids revenue	253		—		—		—		253		—		—		253
Natural gas revenue	144		—		477		10		631		—		—		631
Sales of purchased oil and gas	831		5		—		11		847		—		—		847
Intercompany revenue	—		—		—		—		—		1,092		(1,092)		—
Total revenues from contracts with customers	3,126		283		511		174		4,094		1,092		(1,092)		4,094
Other operating revenues (b)	478		67		—		28		573		—		—		573
Total sales and other operating revenues	$	3,604	$	350	$	511	$	202	$	4,667	$	1,092	$	(1,092)	$	4,667
2019
Sales of our net production volumes:
Crude oil revenue	$	2,981	$	—	$	113	$	566	$	3,660	$	—	$	—	$	3,660
Natural gas liquids revenue	229		—		—		—		229		—		—		229
Natural gas revenue	150		—		646		33		829		—		—		829
Sales of purchased oil and gas	1,644		—		3		91		1,738		—		—		1,738
Intercompany revenue	—		—		—		—		—		848		(848)		—
Total revenues from contracts with customers	5,004		—		762		690		6,456		848		(848)		6,456
Other operating revenues (b)	39		—		—		—		39		—		—		39
Total sales and other operating revenues	$	5,043	$	—	$	762	$	690	$	6,495	$	848	$	(848)	$	6,495

(a)Other includes our interests in Denmark, which were sold in August 2021, and Libya.

(b)Includes gains (losses) on commodity derivatives of $(243) million in 2021, $547 million in 2020, and $1 million in 2019.

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-URI http://asc.fasb.org/topic&trid=49130388

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130551-203045

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130556-203045

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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-Subparagraph (b)
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
-Topic 606
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-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130550-203045

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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-Subparagraph (e)
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130554-203045

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130554-203045

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130554-203045

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130558-203045

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130554-203045

+ Details

Dispositions	12 Months Ended
Dispositions	Dec. 31, 2021
Disposal Group, Not Discontinued Operation, Disposal Disclosures [Abstract]
Dispositions	11. Dispositions 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. 2020: We completed the sale of our 28% working interest in the Shenzi Field in the deepwater Gulf of Mexico for proceeds of $482 million, after normal closing adjustments, and recognized a pre-tax gain of $79 million ($79 million after income taxes). 2019: We completed the sale of our remaining acreage in the Utica shale play in eastern Ohio for proceeds of $22 million, after normal closing adjustments, and recognized a pre-tax gain of $22 million ($22 million after income taxes).

Impairment and Other	12 Months Ended
Impairment and Other	Dec. 31, 2021
Asset Impairment Charges [Abstract]
Impairment and Other	12. Impairment and Other Oil and Gas Properties: In June 2021, the U.S. Bankruptcy Court approved the bankruptcy plan for Fieldwood which includes transferring abandonment obligations of Fieldwood to predecessors in title of certain of its assets, including Hess, who are jointly and severally liable for the obligations. As a result, we recognized a charge of $147 million ($147 million after income taxes) in connection with total estimated abandonment obligations for seven leases in the West Delta Field in the Gulf of Mexico, which we sold to a Fieldwood predecessor in 2004. See Note 8, Asset Retirement Obligations. As a result of the significant decline in crude oil prices due to the global economic slowdown from COVID-19, we reviewed our oil and gas properties within the Exploration and Production operating segment for impairment in the first quarter of 2020. We recognized pre-tax impairment charges in the first quarter of 2020 to reduce the carrying value of our oil and gas properties and certain related right-of-use assets at the North Malay Basin in Malaysia by $755 million ($755 million after income taxes), the South Arne Field in Denmark by $670 million ($594 million after income taxes), and in the Gulf of Mexico, the Stampede Field by $410 million ($410 million after income taxes) and the Tubular Bells Field by $270 million ($270 million after income taxes) primarily as a result of a lower long-term crude oil price outlook. The impairment charges were based on estimates of fair value at March 31, 2020 determined by discounting internally developed future net cash flows, a Level 3 fair value measurement. The total of the fair value estimates was approximately $1.05 billion. Significant inputs used in determining the discounted future net cash flows include future prices, projected production volumes using risk adjusted oil and gas reserves, and discount rates. The future pricing assumptions used were based on forward strip crude oil prices as of March 31, 2020 for the remainder of 2020 through 2022, and $50 per barrel for WTI ($55 per barrel for Brent) in 2023 and thereafter to the end of field life. The weighted average crude oil benchmark price based on total projected crude oil volumes for the impaired assets was $48.82 per barrel. A discount rate of 10% was used in each of the fair value measurements which represents the estimated discount rate a market participant would use. We determined the discount rate by considering the weighted average cost of capital for a group of peer companies. Other Assets: In the first quarter of 2020, we recognized impairment charges totaling $21 million pre-tax ($20 million after income taxes) related to drilling rig right-of-use assets in the Bakken and surplus materials and supplies.

Severance Costs	12 Months Ended
Severance Costs	Dec. 31, 2021
Restructuring and Related Activities [Abstract]
Exit and Disposal Costs	13. Severance CostsWe incurred employee termination costs of $27 million in 2020 related to cost reduction initiatives. All charges were based on amounts incurred under ongoing severance arrangements or other statutory requirements, plus amounts earned under enhanced benefit arrangements. Payments for termination costs were $7 million in 2021 (2020: $20 million; 2019: $4 million)

Share-based Compensation

12 Months Ended

Dec. 31, 2021

Share-based Payment Arrangement [Abstract]

Share-based Compensation

14. Share-based Compensation

We have established and maintain long term incentive plans (LTIP) for the granting of restricted common shares, performance share units (PSUs) and stock options to our employees. At December 31, 2021, the total number of authorized common stock under the LTIP was 63.5 million shares, of which we have 23.6 million shares available for issuance. Share‑based compensation expense consisted of the following:


	2021		2020		2019

	(In millions)
Restricted stock	$	49	$	51	$	53
Performance share units	18		18		22
Stock options	10		10		10
Share-based compensation expense before income taxes	$	77	$	79	$	85
Income tax benefit on share-based compensation expense	$	—	$	—	$	—

Based on share‑based compensation awards outstanding at December 31, 2021, unearned compensation expense, before income taxes, of $79 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 2021:


	Shares of Restricted Common Stock	Weighted - Average Price on Date of Grant

	(In thousands, except per share amounts)
Outstanding at January 1, 2021	1,917	$	51.94
Granted	781	75.11
Vested (a)	(980)	52.72
Forfeited	(102)	57.16
Outstanding at December 31, 2021	1,616	$	62.33

(a)In 2021, restricted stock with a vesting date fair value of $72 million were vested (2020: $51 million; 2019: $102 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. 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 over a three-year performance period ending December 31 of the year prior to settlement of the grant. Beginning with the PSUs granted in 2020, the Corporation's TSR is compared to the TSR of a predetermined group of peer companies and the S&P 500 index over the three-year performance period. 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. The following is a summary of PSU activity in 2021:


	Performance Share Units	Weighted - Average Fair Value on Date of Grant

	(In thousands, except per share amounts)
Outstanding at January 1, 2021	806	$	62.36
Granted	205	86.70
Vested (a)	(274)	59.65
Forfeited	(4)	62.66
Outstanding at December 31, 2021	733	$	70.17

(a)In 2021, PSU’s with a vesting date fair value of $30 million were vested (2020: $48 million; 2019: $16 million).

The following weighted average assumptions were utilized to estimate the fair value of PSU awards:


	2021			2020			2019
Risk free interest rate	0.29		%	0.52		%	2.48		%
Stock price volatility	0.579			0.374			0.369
Contractual term in years	3.0			3.0			3.0
Grant date price of Hess common stock	$	75.04		$	49.72		$	56.74

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 2021:


	Number of options (In thousands)	Weighted Average Exercise Price per Share		Weighted Average Remaining Contractual Term
Outstanding at January 1, 2021	4,382	$	61.57	5.1 years
Granted	319	75.04
Exercised	(1,538)	49.87
Cancelled	(1,049)	83.88
Forfeited	(27)	52.07
Outstanding at December 31, 2021	2,087	$	61.15	6.5 years

At December 31, 2021, there were 2.1 million outstanding stock options (1.17 million exercisable) with a weighted average exercise price of $61.15 per share ($62.27 per share for exercisable options), a weighted average remaining contractual life of 6.5 years (5.0 years for exercisable options) and an aggregate intrinsic value of $28 million ($15 million for exercisable options). The intrinsic value of stock options exercised in 2021 was $45 million (2020: $3 million, 2019: $10 million).

The following weighted average assumptions were utilized to estimate the fair value of stock options:


	2021			2020			2019
Risk free interest rate	0.95		%	0.64		%	2.55		%
Stock price volatility	0.470			0.372			0.359
Dividend yield	1.33		%	2.01		%	1.76		%
Expected life in years	6.0			6.0			6.0
Weighted average fair value per option granted	$	29.66		$	14.30		$	18.08

In estimating the fair value of PSUs and stock options, the risk-free interest rate is based on the vesting period 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

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Income Taxes

15. Income Taxes

The provision (benefit) for income taxes consisted of:


	2021		2020		2019

	(In millions)
United States
Federal
Current	$	—	$	(4)	$	(1)
Deferred taxes and other accruals	12		6		72
State	3		(1)		16
	15		1		87
Foreign
Current (a)	478		48		447
Deferred taxes and other accruals	107		(60)		(73)
	585		(12)		374
Provision (Benefit) For Income Taxes	$	600	$	(11)	$	461

(a)Primarily comprised of Libya in 2021, 2020 and 2019.

Income (loss) before income taxes consisted of the following:


	2021		2020		2019

	(In millions)
United States (a)	$	143	$	(1,509)	$	(338)
Foreign	1,347		(1,341)		559
Income (Loss) Before Income Taxes	$	1,490	$	(2,850)	$	221

(a)Includes substantially all of our interest expense, corporate expense and the results of commodity hedging activities.

The difference between our effective income tax rate and the U.S. statutory rate is reconciled below:


	2021		2020		2019
U.S. statutory rate	21.0	%	21.0	%	21.0	%
Effect of foreign operations (a)	28.0		12.1		142.9
State income taxes, net of federal income tax	0.2		0.1		5.8
Valuation allowance on current year operations	(5.3)		(36.5)		41.8
Release valuation allowance against previously unbenefited deferred tax assets	—		—		(24.5)
Noncontrolling interests in Midstream	(4.0)		1.7		(16.0)
Intraperiod allocation	—		—		33.7
Credits	—		2.0		—
Equity and executive compensation	0.4		(0.1)		2.2
Other	—		0.1		1.2
Total	40.3	%	0.4	%	208.1	%

(a)The variance in effective income tax rates attributable to the effect of foreign operations primarily resulted from the mix of income among high, primarily Libya, and low tax rate jurisdictions.

The components of deferred tax liabilities and deferred tax assets at December 31, were as follows:


	2021		2020

	(In millions)
Deferred Tax Liabilities
Property, plant and equipment and investments	$	(1,712)	$	(847)
Other	(38)		(45)
Total Deferred Tax Liabilities	(1,750)		(892)
Deferred Tax Assets
Net operating loss carryforwards	4,323		5,037
Tax credit carryforwards	89		135
Property, plant and equipment and investments	258		55
Accrued compensation, deferred credits and other liabilities	71		196
Asset retirement obligations	258		252
Other	277		325
Total Deferred Tax Assets	5,276		6,000
Valuation allowances (a)	(3,838)		(5,391)
Total deferred tax assets, net of valuation allowances	1,438		609
Net Deferred Tax Assets (Liabilities)	$	(312)	$	(283)

(a)In 2021, the valuation allowance decreased by $1,553 million (2020: increase of $657 million; 2019: decrease of $143 million).

In the Consolidated Balance Sheet, deferred tax assets and liabilities are netted by taxing jurisdiction and are recorded at December 31, as follows:


	2021		2020

	(In millions)
Deferred income taxes (long-term asset)	$	71	$	59
Deferred income taxes (long-term liability)	(383)		(342)
Net Deferred Tax Assets (Liabilities)	$	(312)	$	(283)

At December 31, 2021, we have recognized a gross deferred tax asset related to net operating loss carryforwards of $4,323 million before application of valuation allowances. The deferred tax asset is comprised of $300 million attributable to foreign net operating losses which will begin to expire in 2025, $3,507 million attributable to U.S. federal operating losses which will begin to expire in 2034, and $516 million attributable to losses in various U.S. states which will begin to expire in 2022. The deferred tax asset attributable to foreign net operating losses, net of valuation allowances, is $166 million. A full valuation allowance is established against the deferred tax asset attributable to U.S. federal and state net operating losses, except for $12 million of U.S. federal and $3 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, 2021, we have U.S. state tax credit carryforwards of $18 million, which will begin to expire in 2034, $71 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, 2021, the Consolidated Balance Sheet reflects a $3,838 million (2020: $5,391 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 Malaysia, and other certain jurisdictions, and did so against its deferred tax assets in Denmark prior to its sale in 2021 (see Note 11, Dispositions). The reduction in valuation allowance year over year is primarily due to the sale of the Denmark asset with its deferred tax asset and related valuation allowance being derecognized as part of net basis of property sold and partially due to a reduction in deferred tax asset balances in jurisdictions where we continue to maintain a full valuation allowance. 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. The cumulative loss incurred over the three-year period ending December 31, 2021 constitutes significant objective negative evidence. Such objective negative evidence limits our ability to consider subjective positive evidence, such as our projections of future taxable income, resulting in the recognition of a valuation allowance against the net deferred tax assets for these jurisdictions. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income change or if objective negative evidence in the form of cumulative losses is no longer present and additional weight can be given to subjective evidence.

Below is a reconciliation of the gross beginning and ending amounts of unrecognized tax benefits:


	2021		2020		2019

	(In millions)
Balance at January 1	$	166	$	168	$	168
Additions based on tax positions taken in the current year	12		2		2
Additions based on tax positions of prior years	3		1		1
Reductions based on tax positions of prior years	(48)		(2)		(1)
Reductions due to settlements with taxing authorities	—		(1)		—
Reductions due to lapses in statutes of limitation	—		(2)		(2)
Balance at December 31	$	133	$	166	$	168

The December 31, 2021 balance of unrecognized tax benefits includes $15 million that, if recognized, would impact our effective income tax rate. Over the next 12 months, it is reasonably possible that the total amount of unrecognized tax benefits could decrease between zero and $15 million due to settlements with taxing authorities or other resolutions, as well as lapses in statutes of limitation. At December 31, 2021, our accrued interest and penalties related to unrecognized tax benefits is $6 million (2020: $6 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.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
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-URI http://asc.fasb.org/extlink&oid=121826272&loc=d3e32857-109319

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Outstanding and Weighted Average Common Shares

12 Months Ended

Dec. 31, 2021

Earnings Per Share [Abstract]

Outstanding and Weighted Average Common Shares

16. Outstanding and Weighted Average Common Shares

The Net income (loss) and weighted average number of common shares used in basic and diluted earnings per share computation were as follows:


	2021		2020		2019

	(In millions except per share amounts)
Net Income (Loss) Attributable to Hess Corporation Common Stockholders:
Net income (loss)	$	890	$	(2,839)	$	(240)
Less: Net income (loss) attributable to noncontrolling interests	331		254		168
Less: Preferred stock dividends	—		—		4
Net income (loss) attributable to Hess Corporation Common Stockholders	$	559	$	(3,093)	$	(412)

Weighted Average Number of Common Shares Outstanding:
Basic	307.4		304.8		301.2
Effect of dilutive securities
Restricted common stock	0.7		—		—
Stock options	0.4		—		—
Performance share units	0.8		—		—
Diluted	309.3		304.8		301.2

Net Income (Loss) Attributable to Hess Corporation per Common Share:
Basic	$	1.82	$	(10.15)	$	(1.37)
Diluted	$	1.81	$	(10.15)	$	(1.37)

Antidilutive shares excluded from the computation of diluted shares:
Restricted common stock	—		2.1		2.2
Stock options	0.7		4.3		4.7
Performance share units	—		1.1		1.7

The following table provides the changes in our outstanding common shares:


	2021	2020	2019

	(In millions)
Balance at January 1	307.0	304.9	291.4
Conversion of preferred stock	—	—	11.6
Activity related to restricted stock awards, net	0.7	1.0	0.9
Stock options exercised	1.5	0.3	0.7
PSUs vested	0.5	0.8	0.3

Balance at December 31	309.7	307.0	304.9

Preferred Stock:

In February 2016, we issued depository shares representing 575,000 shares of 8% Series A Mandatory Convertible Preferred Stock (Preferred Stock), par value $1 per share, with a liquidation preference of $1,000 per share. On January 31, 2019, the Preferred Stock automatically converted into shares of common stock and the net number of common shares issued by the Corporation was approximately 11.6 million shares.

Common Stock Repurchase Plan:

At December 31, 2021, we are authorized, but not required, to purchase additional common stock up to a value of $650 million.

Common Stock Dividends:

Cash dividends declared on common stock totaled $1.00 per share in 2021, 2020 and 2019.

Supplementary Cash Flow Information

12 Months Ended

Dec. 31, 2021

Supplemental Cash Flow Elements [Abstract]

Supplementary Cash Flow Information

17. Supplementary Cash Flow Information

The following information supplements the Statement of Consolidated Cash Flows:


	2021		2020		2019

	(In millions)
Cash Flows From Operating Activities
Interest paid	$	(459)	$	(460)	$	(380)
Net income taxes (paid) refunded	(16)		(64)		(417)

Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P:
Capital expenditures incurred - E&P	$	(1,698)	$	(1,678)	$	(2,576)
Increase (decrease) in related liabilities	114		(218)		143
Additions to property, plant and equipment - E&P	$	(1,584)	$	(1,896)	$	(2,433)

Additions to property, plant and equipment - Midstream:
Capital expenditures incurred - Midstream	$	(183)	$	(253)	$	(416)
Increase (decrease) in related liabilities	20		(48)		20
Additions to property, plant and equipment - Midstream	$	(163)	$	(301)	$	(396)

In December 2019, as part of HESM Opco’s acquisition of HIP (see Note 4, Hess Midstream LP), HESM Opco assumed $800 million of outstanding HIP notes (see Note 7, Debt).

Guarantees, Contingencies and Commitments

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Guarantees, Contingencies and Commitments

18. 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 U.S. against producers of MTBE and petroleum refiners who produced gasoline containing MTBE, including us. The principal allegation in all cases was that gasoline containing MTBE was a defective product and that these producers and refiners are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE. The majority of the cases asserted against us have been settled. There are 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 September 2003, we received a directive from the NJDEP to remediate contamination in the sediments of the Lower Passaic River. The NJDEP is also seeking natural resource damages. The directive, insofar as it affects us, relates to alleged releases from a petroleum bulk storage terminal in Newark, New Jersey we previously owned. We and over 70 companies entered into an Administrative Order on Consent with the EPA to study the same contamination; this work remains ongoing. We and other parties settled a cost recovery claim by the State of New Jersey and agreed with the EPA to fund remediation of a portion of the site. On March 4, 2016, the EPA issued a ROD in respect of the lower eight miles of the Lower Passaic River, selecting a remedy that includes bank-to-bank dredging at an estimated cost of $1.38 billion. The ROD does not address the upper nine miles of the Lower Passaic River or the Newark Bay, which may require additional remedial action. In addition, the federal trustees for natural resources have begun a separate assessment of damages to natural resources in the Passaic River. Given that the EPA has not selected a final remedy for the entirety of the Lower Passaic River or the Newark Bay, total remedial costs cannot be reliably estimated at this time. Based on currently known facts and circumstances, we do not believe that this matter will result in a significant liability to us because our former terminal did not store or use contaminants which are of concern in the river sediments and could not have contributed

contamination along the river’s length. Further, there are numerous other parties who we expect will bear the cost of remediation and damages.

In March 2014, we received an Administrative Order from the EPA requiring us and 26 other parties to undertake the Remedial Design for the remedy selected by the EPA for the Gowanus Canal Superfund Site in Brooklyn, New York. Our alleged liability derives from our former ownership and operation of a fuel oil terminal and connected shipbuilding and repair facility adjacent to the Canal. The remedy selected by the EPA includes dredging of surface sediments and the placement of a cap over the deeper sediments throughout the Canal and in-situ stabilization of certain contaminated sediments that will remain in place below the cap. The EPA’s original estimate was that this remedy would cost $506 million; however, the ultimate costs that will be incurred in connection with the design and implementation of the remedy remain uncertain. We have complied with the EPA’s March 2014 Administrative Order and contributed funding for the Remedial Design based on an allocation of costs among the parties determined by a third-party expert. In January 2020, we received an additional Administrative Order from the EPA requiring us and several other parties to begin Remedial Action along the uppermost portion of the Canal. We intend to comply with this Administrative Order. The remediation work 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.

We are also involved in other judicial and administrative proceedings from time to time in addition to the matters described above, including claims related to post-production deductions from royalty payments. 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, 2021, which are not included elsewhere within these Consolidated Financial Statements:


			Payments Due by Period
	Total		2022		2023 and 2024		2025 and 2026		Thereafter

	(In millions)
Capital expenditures	$	3,263	$	1,028	$	1,458	$	777	$	—
Operating expenses	180		132		42		6		—
Transportation and related contracts	2,574		390		639		453		1,092

Segment Information

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Segment Information

19. 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, 2021 were in the U.S., Malaysia and the JDA, Denmark (sold in August 2021), Libya, and Guyana commencing December 2019. The Midstream operating segment provides fee-based services including crude oil and natural gas gathering, processing of natural gas and the fractionation of NGL, transportation of crude oil by rail car, terminaling and loading 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
2021
Sales and Other Operating Revenues - Third parties	$	7,473	$	—	$	—	$	—	$	7,473
Intersegment Revenues	—		1,204		—		(1,204)		—
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 (Benefit) for Income Taxes	585		15		—		—		600
Investment in Affiliates	94		102		1		—		197
Identifiable Assets	14,173		3,671		2,671		—		20,515
Capital Expenditures	1,698		183		—		—		1,881

2020
Sales and Other Operating Revenues - Third parties	$	4,667	$	—	$	—	$	—	$	4,667
Intersegment Revenues	—		1,092		—		(1,092)		—
Sales and Other Operating Revenues	$	4,667	$	1,092	$	—	$	(1,092)	$	4,667
Net Income (Loss) Attributable to Hess Corporation	$	(2,841)	$	230	$	(482)	$	—	$	(3,093)
Interest Expense	—		95		373		—		468
Depreciation, Depletion and Amortization	1,915		157		2		—		2,074
Impairment and Other	2,126		—		—		—		2,126
Provision (Benefit) for Income Taxes	(12)		7		(6)		—		(11)
Investment in Affiliates	104		108		—		—		212
Identifiable Assets	13,688		3,599		1,534		—		18,821
Capital Expenditures	1,678		253		—		—		1,931

2019
Sales and Other Operating Revenues - Third parties	$	6,495	$	—	$	—	$	—	$	6,495
Intersegment Revenues	—		848		—		(848)		—
Sales and Other Operating Revenues	$	6,495	$	848	$	—	$	(848)	$	6,495
Net Income (Loss) Attributable to Hess Corporation	$	53	$	144	$	(605)	$	—	$	(408)
Interest Expense	—		63		317		—		380
Depreciation, Depletion and Amortization	1,977		142		3		—		2,122
Provision (Benefit) for Income Taxes	375		—		86		—		461
Capital Expenditures	2,576		416		—		—		2,992

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)
2021
Sales and Other Operating Revenues	$	5,378	$	754	$	738	$	603	$	—	$	7,473
Property, Plant and Equipment (Net) (b)	9,721		3,064		1,035		352		10		14,182
2020
Sales and Other Operating Revenues	$	3,604	$	350	$	511	$	202	$	—	$	4,667
Property, Plant and Equipment (Net) (b)	10,384		2,114		1,067		539		11		14,115
2019
Sales and Other Operating Revenues	$	5,043	$	—	$	762	$	690	$	—	$	6,495

(a)Other includes our interests in Denmark (sold in August 2021), Libya, Suriname and Canada.

(b)Property, plant and equipment in the United States in 2021 includes $6,596 million (2020: $7,273 million) attributable to the E&P segment and $3,125 million (2020: $3,111 million) attributable to the Midstream segment.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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-Section 50
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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-Subparagraph (e)
-URI http://asc.fasb.org/extlink&oid=123359005&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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-URI http://asc.fasb.org/topic&trid=2134510

+ Details

Financial Risk Management Activities

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Financial Risk Management Activities

20. 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 by reducing our exposure to foreign currency or interest rate movements. Generally, futures, swaps or option strategies may be used to fix the forward selling price, 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 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, 2021, these forward contracts relate to the British Pound, Canadian Dollar 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, 2021		December 31, 2020

	(In millions)
Commodity - crude oil hedge contracts (millions of barrels)	54.8		27.4
Foreign exchange forwards	$	145	$	163
Interest rate swaps	$	100	$	100

For calendar year 2022, we have hedged 90,000 bopd with WTI collars with an average monthly floor price of $60 per barrel and an average monthly ceiling price of $100 per barrel, and 60,000 bopd with Brent collars with an average monthly floor price of $65 per barrel and an average monthly ceiling price of $105 per barrel.

The table below reflects the gross and net fair values of risk management derivative instruments:


	Assets		Liabilities

	(In millions)
December 31, 2021
Derivative Contracts Designated as Hedging Instruments:
Crude oil collars	$	155	$	—
Interest rate swaps	2		—
Total derivative contracts designated as hedging instruments	157		—
Derivative Contracts Not Designated as Hedging Instruments:
Foreign exchange forwards	—		(1)
Total derivative contracts not designated as hedging instruments	—		(1)
Gross fair value of derivative contracts	157		(1)
Gross amount offset in the Consolidated Balance Sheet	—		—
Net Amounts Presented in the Consolidated Balance Sheet	$	157	$	(1)

December 31, 2020
Derivative Contracts Designated as Hedging Instruments:
Crude oil put options	$	64	$	—
Crude oil swaps	—		(54)
Interest rate swaps	5		—
Total derivative contracts designated as hedging instruments	69		(54)
Derivative Contracts Not Designated as Hedging Instruments:
Foreign exchange forwards	—		(1)
Total derivative contracts not designated as hedging instruments	—		(1)
Gross fair value of derivative contracts	69		(55)
Gross amount offset in the Consolidated Balance Sheet	(13)		13
Net Amounts Presented in the Consolidated Balance Sheet	$	56	$	(42)

At December 31, 2021, the fair value of our crude oil collars is presented within Other current assets in our Consolidated Balance Sheet. At December 31, 2020, the fair value of our crude oil put options and crude oil swaps is presented within Other current assets and Accrued liabilities, respectively, in our Consolidated Balance Sheet. The fair value of our interest rate swaps is presented within Other assets in our Consolidated Balance Sheet. The fair value of our foreign exchange forwards is presented within Accrued liabilities in our Consolidated Balance Sheet. All fair values in the table above are based on Level 2 inputs.

Derivative contracts designated as hedging instruments:

Crude oil hedge contracts: In 2021, crude oil price hedging contracts decreased Sales and other operating revenues by $243 million (2020: increase of $547 million; 2019: increase of $1 million). At December 31, 2021, pre-tax deferred losses in Accumulated other comprehensive income (loss) related to outstanding crude oil price hedging contracts were $68 million ($68 million after income taxes), all of which will be reclassified into earnings during the next 12 months as the hedged crude oil sales are recognized in earnings.

Interest rate swaps designated as fair value hedges: At December 31, 2021, we had interest rate swaps with gross notional amounts of $100 million (2020: $100 million), which were designated as fair value hedges and relate to long-term debt where we have converted interest payments from fixed to floating rates. Changes in the fair value of interest rate swaps and the hedged fixed‑rate debt are recorded in Interest expense in the Statement of Consolidated Income. In 2021, the change in fair value of interest rate swaps was a decrease of $3 million (2020: $4 million increase; 2019: $3 million increase) with a corresponding adjustment in the carrying value of the hedged fixed‑rate debt.

Derivative contracts not designated as hedging instruments:

Foreign exchange: Total foreign exchange gains and losses were losses of $2 million in 2021 (2020: loss of $6 million; 2019: gain of $3 million) and are reported in Other, net in Revenues and non-operating income in the Statement of Consolidated Income. A component of foreign exchange gains or losses is the result of foreign exchange derivative contracts that are not designated as hedges, which amounted to a net gain of $1 million in 2021 (2020: net gain of $2 million; 2019: net loss of $2 million).

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, 2021, our Accounts receivable were concentrated with the following counterparty industry segments: Integrated companies — 50%, Independent E&P companies — 31%, Refining and marketing companies — 9%, National oil companies — 3%,

Storage and transportation companies — 3%, and Others — 4%. 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, 2021, we had outstanding letters of credit totaling $259 million (2020: $269 million).

Fair Value Measurement: At December 31, 2021, our total long-term debt, which was substantially comprised of fixed rate debt instruments, had a carrying value of $8,458 million and a fair value of $9,897 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, 2021 and December 31, 2020.

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2021
Subsequent Events [Abstract]
Subsequent Event	21. Subsequent Events Following the startup of the Liza Phase 2 project in February 2022, we repaid the remaining $500 million outstanding under our $1 billion term loan and we announced a 50 percent increase in our quarterly dividend on common stock. In January 2022, we paid accrued Libyan income tax and royalties of approximately $470 million related to operations for the period December 2020 through November 2021.

Nature of Operations, Basis of Presentation and Summary of Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
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. Commencing December 16, 2019, we consolidate Hess Midstream LP, a variable interest entity that acquired Hess Infrastructure Partners LP (HIP), based on our conclusion that we have the power through Hess Corporation’s approximate 43.5% consolidated ownership interest in Hess Midstream LP to direct those activities that most significantly impact the economic performance of Hess Midstream LP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to Hess Midstream LP. Prior to December 16, 2019, we consolidated HIP, also a variable interest entity based on the conclusion that we had the power to direct the activities that most significantly impacted the economic performance of HIP, and were obligated to absorb losses or had the right to receive benefits that could potentially be significant to HIP. This conclusion was based on a qualitative analysis that considered Hess Midstream LP’s governance structure, the commercial agreements between Hess Midstream LP and us, and the voting rights established between the members, which provide us the ability to control the operations of Hess Midstream LP. 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, pension 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 Statement 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 to eleven years. 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 is 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. 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. Midstream Our Midstream segment provides gathering, compression, processing, fractionation, storage, terminaling, loading and transportation, and water handling services. The Midstream segment has multiple long-term, fee-based commercial agreements with certain subsidiaries of Hess, each generally with an initial ten-year term that can be extended for an additional ten-year term at the unilateral right of Hess Midstream. These contracts have minimum volumes the customer is obligated to provide each calendar quarter. The minimum volume commitments are subject to fluctuation based on nominations covering substantially all of our E&P segment’s production and projected third-party volumes that will be purchased in the Bakken. As the minimum volume commitments are subject to fluctuation, and as these contracts contain fee inflation escalators and fee recalculation mechanisms, substantially all of the transaction price at contract inception is variable. The midstream segment also has long-term, fee based commercial agreements for water handling services with a subsidiary of Hess with an initial 14 year term that can be extended for an additional ten-year term at the unilateral right of Hess Midstream. Water handling services are provided for an agreed-upon fee per barrel or the reimbursement of third-party fees. The Midstream segment’s responsibilities to provide each of the above services for each year under each of the commercial agreements are considered separate, distinct performance obligations. Revenue is recognized for each performance obligation under these commercial agreements over-time as services are rendered using the output method, measured using the amount of volumes serviced during the period. The Midstream segment has elected the practical expedient under the provisions of ASC 606, Revenue from Contracts with Customers to recognize revenue in the amount it is entitled to invoice. If the commercial agreements have ship-or-pay provisions, the Midstream segment’s responsibility to stand-ready to service a minimum volume over each quarterly commitment period represent separate, distinct performance obligations. Shortfall payments received under ship-or-pay provisions are recognized as revenue in the calendar quarter the shortfall occurs as the customer does not have make-up rights beyond the calendar quarter end of the quarterly commitment period. 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. On December 30, 2020, Hess Midstream exercised its renewal options to extend the terms of certain gas gathering, crude oil gathering, gas processing and fractionation, storage, and terminal and export commercial agreements for the secondary term through December 31, 2033. There were no changes to any provisions of the existing commercial agreements as a result of the exercise of the renewal options.
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 1st or when events or circumstances indicate that the carrying amount of the goodwill may not be recoverable. To determine whether goodwill is impaired, the fair value of a reporting unit is compared with 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 charge 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, 2021, 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. Right-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 on a straight-line basis based on the nature of operation for which the ROU asset is utilized. Leases with an initial term of 12 months or less are not recorded on the balance sheet as permitted under ASC 842, Leases. We recognize lease cost for short-term leases on a straight-line basis over the term of the lease. Some of our leases include one or more options to renew. The renewal option is at our sole discretion and is not included in the lease term for measurement of the lease obligation unless we are reasonably certain at the commencement date of the lease, to renew the lease.
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 recorded deferred tax assets for those losses and credits. Additionally, we have deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If, when tested under the relevant accounting standards, it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount that is expected to be realized. The accounting standards require the evaluation of all available positive and negative evidence giving weight based on the evidence’s relative objectivity. In evaluating potential sources of positive evidence, we consider the reversal of taxable temporary differences, taxable income in carryback and carryforward periods, the availability of tax planning strategies, the existence of appreciated assets, estimates of future taxable income, and other factors. 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 no longer 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 material 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, and the asset is depreciated over 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 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 or goodwill. We determine fair value in accordance with the fair value measurements accounting standard which established a hierarchy for the inputs used to measure fair value based on the source of the inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3), including discounted cash flows and other unobservable data. Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market. Multiple inputs 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 Translation: 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: We accrue and expense the undiscounted environmental costs necessary to remediate existing conditions related to past operations when the future costs are probable and reasonably estimable. At year‑end 2021, our reserve for estimated remediation liabilities was approximately $60 million. Environmental expenditures that increase the life or efficiency of property or reduce or prevent future adverse impacts to the environment are capitalized.

Inventories (Tables)

12 Months Ended

Dec. 31, 2021

Inventory Disclosure [Abstract]

Schedule of Inventories

Inventories at December 31 were as follows:


	2021		2020

	(In millions)
Crude oil and natural gas liquids	$	52	$	226
Materials and supplies	171		152
Total Inventories	$	223	$	378

Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2021

Property, Plant and Equipment [Abstract]

Components of Property, Plant and Equipment

Property, plant and equipment at December 31 were as follows:


	2021		2020

	(In millions)
Exploration and Production
Unproved properties	$	184	$	164
Proved properties	2,877		2,930
Wells, equipment and related facilities	23,745		23,224
	26,806		26,318
Midstream	4,342		4,163
Corporate and Other	30		38
Total — at cost	31,178		30,519
Less: Reserves for depreciation, depletion, amortization and lease impairment	16,996		16,404
Property, Plant and Equipment — Net	$	14,182	$	14,115

Net Changes in Capitalized Exploratory Well Costs


	2021		2020		2019

	(In millions)
Balance at January 1	$	459	$	584	$	418
Additions to capitalized exploratory well costs pending the determination of proved reserves	222		111		224
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	—		(111)		(58)
Capitalized exploratory well costs charged to expense	—		(125)		—

Balance at December 31	$	681	$	459	$	584
Number of Wells at December 31	35		22		31

Exploratory Drilling Costs Capitalized

Exploratory well costs capitalized for greater than one year following completion of drilling were $459 million at December 31, 2021, separated by year of completion as follows (in millions):


2020	$	117
2019	173
2018	105
2017	27
2016 and prior	37
	$	459

Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2021

Payables and Accruals [Abstract]

Schedule of Accrued Liabilities

The following table provides detail of our accrued liabilities at December 31:


	2021		2020

	(In millions)
Accrued capital expenditures	$	479	$	345
Accrued operating and marketing expenditures	462		325
Accrued payments to royalty and working interest owners	253		170
Current portion of asset retirement obligations	185		105
Accrued interest on debt	138		126
Accrued compensation and benefits	124		117
Other accruals	69		63
Total Accrued Liabilities	$	1,710	$	1,251

Leases (Tables)

12 Months Ended

Dec. 31, 2021

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

	2021		2020		2021		2020

	(In millions)
Right-of-use assets — net (a)	$	352	$	426	$	144	$	168
Lease obligations:
Current	$	70	$	63	$	19	$	18
Long-term	394		478		200		220
Total lease obligations	$	464	$	541	$	219	$	238

(a)At December 31, 2021, finance lease ROU assets had a cost of $212 million (2020: $212 million) and accumulated amortization of $68 million (2020: $44 million).

Maturity Profile of Lease Obligations

Maturities of lease obligations at December 31, 2021 were as follows:


	Operating Leases		Finance Leases

	(In millions)
2022	$	87	$	36
2023	75		36
2024	69		36
2025	64		36
2026	49		31
Remaining years	219		145
Total lease payments	563		320
Less: Imputed interest	(99)		(101)
Total lease obligations	$	464	$	219

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

2021

2020

2021

2020

Weighted average remaining lease term

9.9 years

10.3 years

11.8 years

12.8 years

Range of remaining lease terms

0.1 - 14.5 years

0.1 - 15.5 years

11.8 years

12.8 years

Weighted average discount rate

4.1%

4.0%

7.9%

Components of Lease Costs

The components of lease costs for the years ended December 31, 2021 and 2020 were as follows:


	2021		2020

	(In millions)
Operating lease cost	$	88	$	200
Finance lease cost:
Amortization of leased assets	24		31
Interest on lease obligations	18		20
Short-term lease cost (a)	137		199
Variable lease cost (b)	21		38
Sublease income (c)	(17)		(15)
Total lease cost	$	271	$	473

(c)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 for the years ended December 31, 2021 and 2020 were as follows:


	Operating Leases				Finance Leases

	2021		2020		2021		2020

	(In millions)
Cash paid for amounts included in the measurement of lease obligations:
Operating cash flows (a)	$	87	$	218	$	18	$	20
Financing cash flows (a)	—		—		18		17
Noncash transactions:
Leased assets recognized for new lease obligations incurred	12		51		—		—
Changes in leased assets and lease obligations due to lease modifications (b)	29		123		—		—

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

(b)In 2020, primarily related to negotiated extensions of an office lease and offshore drilling rig leases.

Debt (Tables)

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Components of Debt

Total debt at December 31 consisted of the following:


	2021		2020

	(In millions)
Debt - Hess Corporation:
Senior unsecured fixed-rate public notes:
3.500% due 2024	$	299	$	299
4.300% due 2027	995		994
7.875% due 2029	464		464
7.300% due 2031	628		628
7.125% due 2033	537		537
6.000% due 2040	742		741
5.600% due 2041	1,236		1,236
5.800% due 2047	494		494
Total senior unsecured fixed-rate public notes	5,395		5,393
Term loan facility	497		988
Fair value adjustments - interest rate hedging	2		5
Total Debt - Hess Corporation	$	5,894	$	6,386

Debt - Midstream (Hess Midstream Operations LP):
Senior unsecured fixed-rate public notes:
5.625% due 2026	$	791	$	789
5.125% due 2028	543		542
4.250% due 2030	739		—
Total senior unsecured fixed-rate public notes	2,073		1,331
Term loan A facility	387		395
Revolving credit facility	104		184
Total Debt - Midstream	$	2,564	$	1,910

Total Debt:
Current portion of long-term debt	$	517	$	10
Long-term debt	7,941		8,286
Total Debt	$	8,458	$	8,296

Maturity Profile of Debt

At December 31, 2021, the maturity profile of total debt was as follows:


	Total		Hess Corporation		Midstream

	(In millions)
2022	$	520	$	500	$	20
2023	30		—		30
2024	744		300		444
2025	—		—		—
2026	800		—		800
Thereafter	6,438		5,138		1,300
Total Borrowings	8,532		5,938		2,594
Less: Deferred financing costs and discounts	(74)		(44)		(30)
Total Debt (excluding interest)	$	8,458	$	5,894	$	2,564

Other Outstanding Letters of Credit

Other outstanding letters of credit at December 31 were as follows:


	2021		2020

	(In millions)
Committed lines (a)	$	29	$	54
Uncommitted lines (a)	230		215
Total	$	259	$	269

(a)At December 31, 2021, committed and uncommitted lines have expiration dates through 2022.

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2021

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:


	2021		2020

	(In millions)
Balance at January 1	$	999	$	1,024
Liabilities incurred	229		36
Liabilities settled or disposed of	(207)		(161)
Accretion expense	44		46
Revisions of estimated liabilities	126		52
Foreign currency remeasurement	(1)		2
Balance at December 31	$	1,190	$	999

Total Asset Retirement Obligations at December 31:
Current portion of asset retirement obligations	$	185	$	105
Long-term asset retirement obligations	1,005		894
Total at December 31	$	1,190	$	999

Retirement Plans (Tables)

12 Months Ended

Dec. 31, 2021

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 Pension Plans				Unfunded Pension Plan				Postretirement Medical Plan
	2021		2020		2021		2020		2021		2020

	(In millions)
Change in Benefit Obligation
Balance at January 1,	$	3,085	$	2,667	$	269	$	242	$	65	$	75
Service cost	41		37		10		13		3		3
Interest cost	52		68		3		5		1		1
Actuarial (gains) loss (a)	(126)		385		(8)		26		(3)		(8)
Benefit payments (b)	(100)		(93)		(26)		(17)		(7)		(6)

Plan amendments	2		—		—		—		—		—

Foreign currency exchange rate changes	(6)		21		—		—		—		—
Balance at December 31, (c)	2,948		3,085		248		269		59		65
Change in Fair Value of Plan Assets
Balance at January 1,	$	3,043	$	2,732	$	—	$	—	$	—	$	—
Actual return on plan assets	417		378		—		—		—		—
Employer contributions	6		4		26		17		7		6
Benefit payments (b)	(100)		(93)		(26)		(17)		(7)		(6)
Foreign currency exchange rate changes	(9)		22		—		—		—		—
Balance at December 31,	3,357		3,043		—		—		—		—

Funded Status (Plan assets greater (less) than benefit obligations) at December 31,	$	409	$	(42)	$	(248)	$	(269)	$	(59)	$	(65)

Unrecognized Net Actuarial (Gains) Losses	$	501	$	900	$	66	$	86	$	(21)	$	(19)

(b)Benefit payments include lump-sum settlement payments of $34 million in 2021 (2020: $23 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 Pension Plans				Unfunded Pension Plan				Postretirement Medical Plan
	2021		2020		2021		2020		2021		2020

	(In millions)
Noncurrent assets	$	409	$	45	$	—	$	—	$	—	$	—
Current liabilities	—		—		(34)		(49)		(6)		(7)
Noncurrent liabilities	—		(87)		(214)		(220)		(53)		(58)
Pension assets / (accrued benefit liability)	$	409	$	(42)	$	(248)	$	(269)	$	(59)	$	(65)

Accumulated other comprehensive (income) loss, pre-tax (a)	$	501	$	900	$	66	$	86	$	(21)	$	(19)

(a)The after‑tax deficit reflected in Accumulated other comprehensive income (loss) was $338 million at December 31, 2021 (2020: $759 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
	2021		2020		2019		2021		2020		2019

	(In millions)
Service cost	$	51	$	50	$	44	$	3	$	3	$	2
Interest cost	55		73		89		1		1		2
Expected return on plan assets	(197)		(180)		(180)		—		—		—
Amortization of unrecognized net actuarial losses (gains)	58		48		52		(1)		(1)		(1)
Settlement loss	9		—		93		—		—		—
Curtailment gain	—		—		—		—		—		—

Net Periodic Benefit Cost / (Income) (a)	$	(24)	$	(9)	$	98	$	3	$	3	$	3

(a)Net non-service cost, which is included in Other, net in the Statement of Consolidated Income, was income of $75 million in 2021 (2020: $59 million of income; 2019: $55 million of expense).

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:


	2021	2020	2019
Benefit Obligations:
Discount rate	2.5%	2.2%	2.9%
Rate of compensation increase	3.8%	3.8%	3.8%

Net Periodic Benefit Cost:
Discount rate
Service cost	2.6%	3.2%	3.9%
Interest cost	1.7%	2.6%	3.4%
Expected return on plan assets	6.6%	6.7%	7.1%
Rate of compensation increase	3.8%	3.8%	3.8%

The actuarial assumptions used to determine benefit obligations at December 31 for the postretirement medical plan were as follows:


	2021	2020	2019
Discount rate	2.4%	1.9%	2.8%
Initial health care trend rate	5.5%	6.0%	6.5%
Ultimate trend rate	4.0%	4.5%	4.5%
Year in which ultimate trend rate is reached	2046	2038	2038

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, 2021 and 2020 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 Value (c)		Total

	(In millions)
December 31, 2021
Cash and Short-Term Investment Funds	$	19	$	—	$	—	$	—	$	19
Equities:
U.S. equities (domestic)	601		—		—		87		688
International equities (non-U.S.)	73		56		—		375		504
Global equities (domestic and non-U.S.)	—		7		—		224		231
Fixed Income:
Treasury and government related (a)	—		361		—		41		402
Mortgage-backed securities (b)	—		128		—		63		191
Corporate	128		452		—		55		635
Other:
Hedge funds	—		—		—		81		81
Private equity funds	—		—		—		382		382
Real estate funds	29		—		—		195		224
Total investments	$	850	$	1,004	$	—	$	1,503	$	3,357
December 31, 2020
Cash and Short-Term Investment Funds	$	44	$	—	$	—	$	—	$	44
Equities:
U.S. equities (domestic)	585		—		—		164		749
International equities (non-U.S.)	94		43		—		352		489
Global equities (domestic and non-U.S.)	—		8		—		217		225
Fixed Income:
Treasury and government related (a)	—		350		—		49		399
Mortgage-backed securities (b)	—		116		—		70		186
Corporate	—		381		—		62		443
Other:
Hedge funds	—		—		—		73		73
Private equity funds	—		—		—		251		251
Real estate funds	23		—		—		161		184
Total investments	$	746	$	898	$	—	$	1,399	$	3,043

(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.

Estimated Future Benefit Payments for Pension Plans & Postretirement Medical Plan

Estimated future benefit payments by the funded and unfunded pension plans, and the postretirement medical plan, which reflect expected future service, are as follows (in millions):


2022	$	131
2023	132
2024	137
2025	125
2026	131
Years 2027 to 2031	662

Revenue (Tables)

12 Months Ended

Dec. 31, 2021

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
2021
Sales of our 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 revenues from contracts with customers	5,540		781		738		624		7,683		1,204		(1,204)		7,683
Other operating revenues (b)	(162)		(27)		—		(21)		(210)		—		—		(210)
Total sales and other operating revenues	$	5,378	$	754	$	738	$	603	$	7,473	$	1,204	$	(1,204)	$	7,473
2020
Sales of our net production volumes:
Crude oil revenue	$	1,898	$	278	$	34	$	153	$	2,363	$	—	$	—	$	2,363
Natural gas liquids revenue	253		—		—		—		253		—		—		253
Natural gas revenue	144		—		477		10		631		—		—		631
Sales of purchased oil and gas	831		5		—		11		847		—		—		847
Intercompany revenue	—		—		—		—		—		1,092		(1,092)		—
Total revenues from contracts with customers	3,126		283		511		174		4,094		1,092		(1,092)		4,094
Other operating revenues (b)	478		67		—		28		573		—		—		573
Total sales and other operating revenues	$	3,604	$	350	$	511	$	202	$	4,667	$	1,092	$	(1,092)	$	4,667
2019
Sales of our net production volumes:
Crude oil revenue	$	2,981	$	—	$	113	$	566	$	3,660	$	—	$	—	$	3,660
Natural gas liquids revenue	229		—		—		—		229		—		—		229
Natural gas revenue	150		—		646		33		829		—		—		829
Sales of purchased oil and gas	1,644		—		3		91		1,738		—		—		1,738
Intercompany revenue	—		—		—		—		—		848		(848)		—
Total revenues from contracts with customers	5,004		—		762		690		6,456		848		(848)		6,456
Other operating revenues (b)	39		—		—		—		39		—		—		39
Total sales and other operating revenues	$	5,043	$	—	$	762	$	690	$	6,495	$	848	$	(848)	$	6,495

(a)Other includes our interests in Denmark, which were sold in August 2021, and Libya.

(b)Includes gains (losses) on commodity derivatives of $(243) million in 2021, $547 million in 2020, and $1 million in 2019.

Share-based Compensation (Tables)

12 Months Ended

Dec. 31, 2021

Share-based Payment Arrangement [Abstract]

Share-based Compensation Cost by Award Type

Share‑based compensation expense consisted of the following:


	2021		2020		2019

	(In millions)
Restricted stock	$	49	$	51	$	53
Performance share units	18		18		22
Stock options	10		10		10
Share-based compensation expense before income taxes	$	77	$	79	$	85
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 2021:


	Shares of Restricted Common Stock	Weighted - Average Price on Date of Grant

	(In thousands, except per share amounts)
Outstanding at January 1, 2021	1,917	$	51.94
Granted	781	75.11
Vested (a)	(980)	52.72
Forfeited	(102)	57.16
Outstanding at December 31, 2021	1,616	$	62.33

(a)In 2021, restricted stock with a vesting date fair value of $72 million were vested (2020: $51 million; 2019: $102 million).

Summary of Performance Share Units Activity

The following is a summary of PSU activity in 2021:


	Performance Share Units	Weighted - Average Fair Value on Date of Grant

	(In thousands, except per share amounts)
Outstanding at January 1, 2021	806	$	62.36
Granted	205	86.70
Vested (a)	(274)	59.65
Forfeited	(4)	62.66
Outstanding at December 31, 2021	733	$	70.17

(a)In 2021, PSU’s with a vesting date fair value of $30 million were vested (2020: $48 million; 2019: $16 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:


	2021			2020			2019
Risk free interest rate	0.29		%	0.52		%	2.48		%
Stock price volatility	0.579			0.374			0.369
Contractual term in years	3.0			3.0			3.0
Grant date price of Hess common stock	$	75.04		$	49.72		$	56.74

Summary of Stock Options Activity

The following is a summary of stock options activity in 2021:


	Number of options (In thousands)	Weighted Average Exercise Price per Share		Weighted Average Remaining Contractual Term
Outstanding at January 1, 2021	4,382	$	61.57	5.1 years
Granted	319	75.04
Exercised	(1,538)	49.87
Cancelled	(1,049)	83.88
Forfeited	(27)	52.07
Outstanding at December 31, 2021	2,087	$	61.15	6.5 years

Assumptions to Estimate Fair Value of Stock Options

The following weighted average assumptions were utilized to estimate the fair value of stock options:


	2021			2020			2019
Risk free interest rate	0.95		%	0.64		%	2.55		%
Stock price volatility	0.470			0.372			0.359
Dividend yield	1.33		%	2.01		%	1.76		%
Expected life in years	6.0			6.0			6.0
Weighted average fair value per option granted	$	29.66		$	14.30		$	18.08

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Components of Income Tax Provision (Benefit)

The provision (benefit) for income taxes consisted of:


	2021		2020		2019

	(In millions)
United States
Federal
Current	$	—	$	(4)	$	(1)
Deferred taxes and other accruals	12		6		72
State	3		(1)		16
	15		1		87
Foreign
Current (a)	478		48		447
Deferred taxes and other accruals	107		(60)		(73)
	585		(12)		374
Provision (Benefit) For Income Taxes	$	600	$	(11)	$	461

(a)Primarily comprised of Libya in 2021, 2020 and 2019.

Components of Income (Loss) Before Income Taxes

Income (loss) before income taxes consisted of the following:


	2021		2020		2019

	(In millions)
United States (a)	$	143	$	(1,509)	$	(338)
Foreign	1,347		(1,341)		559
Income (Loss) Before Income Taxes	$	1,490	$	(2,850)	$	221

(a)Includes substantially all of our interest expense, corporate expense and the results of commodity hedging activities.

Reconciliation of Effective Income Tax Rate

The difference between our effective income tax rate and the U.S. statutory rate is reconciled below:


	2021		2020		2019
U.S. statutory rate	21.0	%	21.0	%	21.0	%
Effect of foreign operations (a)	28.0		12.1		142.9
State income taxes, net of federal income tax	0.2		0.1		5.8
Valuation allowance on current year operations	(5.3)		(36.5)		41.8
Release valuation allowance against previously unbenefited deferred tax assets	—		—		(24.5)
Noncontrolling interests in Midstream	(4.0)		1.7		(16.0)
Intraperiod allocation	—		—		33.7
Credits	—		2.0		—
Equity and executive compensation	0.4		(0.1)		2.2
Other	—		0.1		1.2
Total	40.3	%	0.4	%	208.1	%

(a)The variance in effective income tax rates attributable to the effect of foreign operations primarily resulted from the mix of income among high, primarily Libya, and low tax rate jurisdictions.

Components of Deferred Tax Assets & Liabilities

The components of deferred tax liabilities and deferred tax assets at December 31, were as follows:


	2021		2020

	(In millions)
Deferred Tax Liabilities
Property, plant and equipment and investments	$	(1,712)	$	(847)
Other	(38)		(45)
Total Deferred Tax Liabilities	(1,750)		(892)
Deferred Tax Assets
Net operating loss carryforwards	4,323		5,037
Tax credit carryforwards	89		135
Property, plant and equipment and investments	258		55
Accrued compensation, deferred credits and other liabilities	71		196
Asset retirement obligations	258		252
Other	277		325
Total Deferred Tax Assets	5,276		6,000
Valuation allowances (a)	(3,838)		(5,391)
Total deferred tax assets, net of valuation allowances	1,438		609
Net Deferred Tax Assets (Liabilities)	$	(312)	$	(283)

(a)In 2021, the valuation allowance decreased by $1,553 million (2020: increase of $657 million; 2019: decrease of $143 million).

In the Consolidated Balance Sheet, deferred tax assets and liabilities are netted by taxing jurisdiction and are recorded at December 31, as follows:


	2021		2020

	(In millions)
Deferred income taxes (long-term asset)	$	71	$	59
Deferred income taxes (long-term liability)	(383)		(342)
Net Deferred Tax Assets (Liabilities)	$	(312)	$	(283)

Reconciliation of Unrecognized Tax Benefits

Below is a reconciliation of the gross beginning and ending amounts of unrecognized tax benefits:


	2021		2020		2019

	(In millions)
Balance at January 1	$	166	$	168	$	168
Additions based on tax positions taken in the current year	12		2		2
Additions based on tax positions of prior years	3		1		1
Reductions based on tax positions of prior years	(48)		(2)		(1)
Reductions due to settlements with taxing authorities	—		(1)		—
Reductions due to lapses in statutes of limitation	—		(2)		(2)
Balance at December 31	$	133	$	166	$	168

Outstanding and Weighted Average Common Shares (Tables)

12 Months Ended

Dec. 31, 2021

Earnings Per Share [Abstract]

Net Income (Loss) & Weighted Average Number of Common Shares Used in Computation of Basic & Diluted Earnings Per Share

The Net income (loss) and weighted average number of common shares used in basic and diluted earnings per share computation were as follows:


	2021		2020		2019

	(In millions except per share amounts)
Net Income (Loss) Attributable to Hess Corporation Common Stockholders:
Net income (loss)	$	890	$	(2,839)	$	(240)
Less: Net income (loss) attributable to noncontrolling interests	331		254		168
Less: Preferred stock dividends	—		—		4
Net income (loss) attributable to Hess Corporation Common Stockholders	$	559	$	(3,093)	$	(412)

Weighted Average Number of Common Shares Outstanding:
Basic	307.4		304.8		301.2
Effect of dilutive securities
Restricted common stock	0.7		—		—
Stock options	0.4		—		—
Performance share units	0.8		—		—
Diluted	309.3		304.8		301.2

Net Income (Loss) Attributable to Hess Corporation per Common Share:
Basic	$	1.82	$	(10.15)	$	(1.37)
Diluted	$	1.81	$	(10.15)	$	(1.37)

Antidilutive shares excluded from the computation of diluted shares:
Restricted common stock	—		2.1		2.2
Stock options	0.7		4.3		4.7
Performance share units	—		1.1		1.7

Changes in Outstanding Common Shares

The following table provides the changes in our outstanding common shares:


	2021	2020	2019

	(In millions)
Balance at January 1	307.0	304.9	291.4
Conversion of preferred stock	—	—	11.6
Activity related to restricted stock awards, net	0.7	1.0	0.9
Stock options exercised	1.5	0.3	0.7
PSUs vested	0.5	0.8	0.3

Balance at December 31	309.7	307.0	304.9

Supplementary Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2021

Supplemental Cash Flow Elements [Abstract]

Schedule of Cash Flow Supplemental Disclosures

The following information supplements the Statement of Consolidated Cash Flows:


	2021		2020		2019

	(In millions)
Cash Flows From Operating Activities
Interest paid	$	(459)	$	(460)	$	(380)
Net income taxes (paid) refunded	(16)		(64)		(417)

Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P:
Capital expenditures incurred - E&P	$	(1,698)	$	(1,678)	$	(2,576)
Increase (decrease) in related liabilities	114		(218)		143
Additions to property, plant and equipment - E&P	$	(1,584)	$	(1,896)	$	(2,433)

Additions to property, plant and equipment - Midstream:
Capital expenditures incurred - Midstream	$	(183)	$	(253)	$	(416)
Increase (decrease) in related liabilities	20		(48)		20
Additions to property, plant and equipment - Midstream	$	(163)	$	(301)	$	(396)

Guarantees, Contingencies and Commitments (Tables)

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Schedule of Unconditional Purchase Obligations & Commitments


			Payments Due by Period
	Total		2022		2023 and 2024		2025 and 2026		Thereafter

	(In millions)
Capital expenditures	$	3,263	$	1,028	$	1,458	$	777	$	—
Operating expenses	180		132		42		6		—
Transportation and related contracts	2,574		390		639		453		1,092

Segment Information (Tables)

12 Months Ended

Dec. 31, 2021

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
2021
Sales and Other Operating Revenues - Third parties	$	7,473	$	—	$	—	$	—	$	7,473
Intersegment Revenues	—		1,204		—		(1,204)		—
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 (Benefit) for Income Taxes	585		15		—		—		600
Investment in Affiliates	94		102		1		—		197
Identifiable Assets	14,173		3,671		2,671		—		20,515
Capital Expenditures	1,698		183		—		—		1,881

2020
Sales and Other Operating Revenues - Third parties	$	4,667	$	—	$	—	$	—	$	4,667
Intersegment Revenues	—		1,092		—		(1,092)		—
Sales and Other Operating Revenues	$	4,667	$	1,092	$	—	$	(1,092)	$	4,667
Net Income (Loss) Attributable to Hess Corporation	$	(2,841)	$	230	$	(482)	$	—	$	(3,093)
Interest Expense	—		95		373		—		468
Depreciation, Depletion and Amortization	1,915		157		2		—		2,074
Impairment and Other	2,126		—		—		—		2,126
Provision (Benefit) for Income Taxes	(12)		7		(6)		—		(11)
Investment in Affiliates	104		108		—		—		212
Identifiable Assets	13,688		3,599		1,534		—		18,821
Capital Expenditures	1,678		253		—		—		1,931

2019
Sales and Other Operating Revenues - Third parties	$	6,495	$	—	$	—	$	—	$	6,495
Intersegment Revenues	—		848		—		(848)		—
Sales and Other Operating Revenues	$	6,495	$	848	$	—	$	(848)	$	6,495
Net Income (Loss) Attributable to Hess Corporation	$	53	$	144	$	(605)	$	—	$	(408)
Interest Expense	—		63		317		—		380
Depreciation, Depletion and Amortization	1,977		142		3		—		2,122
Provision (Benefit) for Income Taxes	375		—		86		—		461
Capital Expenditures	2,576		416		—		—		2,992

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)
2021
Sales and Other Operating Revenues	$	5,378	$	754	$	738	$	603	$	—	$	7,473
Property, Plant and Equipment (Net) (b)	9,721		3,064		1,035		352		10		14,182
2020
Sales and Other Operating Revenues	$	3,604	$	350	$	511	$	202	$	—	$	4,667
Property, Plant and Equipment (Net) (b)	10,384		2,114		1,067		539		11		14,115
2019
Sales and Other Operating Revenues	$	5,043	$	—	$	762	$	690	$	—	$	6,495

(a)Other includes our interests in Denmark (sold in August 2021), Libya, Suriname and Canada.

Financial Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2021

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, 2021		December 31, 2020

	(In millions)
Commodity - crude oil hedge contracts (millions of barrels)	54.8		27.4
Foreign exchange forwards	$	145	$	163
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, 2021
Derivative Contracts Designated as Hedging Instruments:
Crude oil collars	$	155	$	—
Interest rate swaps	2		—
Total derivative contracts designated as hedging instruments	157		—
Derivative Contracts Not Designated as Hedging Instruments:
Foreign exchange forwards	—		(1)
Total derivative contracts not designated as hedging instruments	—		(1)
Gross fair value of derivative contracts	157		(1)
Gross amount offset in the Consolidated Balance Sheet	—		—
Net Amounts Presented in the Consolidated Balance Sheet	$	157	$	(1)

December 31, 2020
Derivative Contracts Designated as Hedging Instruments:
Crude oil put options	$	64	$	—
Crude oil swaps	—		(54)
Interest rate swaps	5		—
Total derivative contracts designated as hedging instruments	69		(54)
Derivative Contracts Not Designated as Hedging Instruments:
Foreign exchange forwards	—		(1)
Total derivative contracts not designated as hedging instruments	—		(1)
Gross fair value of derivative contracts	69		(55)
Gross amount offset in the Consolidated Balance Sheet	(13)		13
Net Amounts Presented in the Consolidated Balance Sheet	$	56	$	(42)

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=125515794&loc=SL5624163-113959

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=125515794&loc=SL5580258-113959

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=125515794&loc=d3e41620-113959

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=125515794&loc=SL5579245-113959

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=125515794&loc=d3e41638-113959

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=125515794&loc=d3e41678-113959

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=125515794&loc=d3e41641-113959

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
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-URI http://asc.fasb.org/extlink&oid=125515794&loc=SL5624171-113959

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=125515794&loc=SL5579240-113959

+ Details

Nature of Operations, Basis of Presentation and Summary of Accounting Policies (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2021	Dec. 31, 2020
Nature of Operations, Basis of Presentation and Summary of Accounting Policies [Line Items]
Goodwill	$ 360	$ 360	$ 360
Reserve for estimated remediation liabilities	$ 60	$ 60
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	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	11 years	11 years
Midstream
Nature of Operations, Basis of Presentation and Summary of Accounting Policies [Line Items]
Initial revenue contract period		10 years
Additional revenue contract period		10 years
Goodwill	$ 360	$ 360
Midstream \| Water Handling Services
Nature of Operations, Basis of Presentation and Summary of Accounting Policies [Line Items]
Initial revenue contract period		14 years
Additional revenue contract period		10 years
Hess Midstream LP
Nature of Operations, Basis of Presentation and Summary of Accounting Policies [Line Items]
Percent interest in consolidated entity	43.50%

Inventories - Schedule of Inventories (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Inventory Disclosure [Abstract]
Crude oil and natural gas liquids	$ 52	$ 226
Materials and supplies	171	152
Total Inventories	$ 223	$ 378

Inventories - Additional Information (Details) bbl in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2021 vlcc	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($) vlcc bbl
Inventory [Line Items]
Cost of crude oil \| $		$ 52	$ 226
Very Large Crude Carriers (VLCCs)
Inventory [Line Items]
Cost of crude oil \| $			$ 164
Crude oil loaded in very large crude carriers (in barrels of oil) \| bbl			4.2
Number of very large crude carriers \| vlcc			2
Number of VLCCs cargos sold \| vlcc	2

Property, Plant and Equipment - Components of Property, Plant and Equipment (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Total — at cost	$ 31,178	$ 30,519
Less: Reserves for depreciation, depletion, amortization and lease impairment	16,996	16,404
Property, Plant and Equipment— Net	14,182	14,115
Exploration and Production
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment— Net	6,596	7,273
Midstream
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment— Net	3,125	3,111
Operating Segments \| Exploration and Production
Property, Plant and Equipment [Line Items]
Unproved properties	184	164
Proved properties	2,877	2,930
Wells, equipment and related facilities	23,745	23,224
Total — at cost	26,806	26,318
Operating Segments \| Midstream
Property, Plant and Equipment [Line Items]
Total — at cost	4,342	4,163
Corporate, Interest and Other
Property, Plant and Equipment [Line Items]
Total — at cost	30	38
Property, Plant and Equipment— Net	$ 10	$ 11

Property, Plant and Equipment - Net Changes in Capitalized Exploratory Well Costs (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) well	Dec. 31, 2020 USD ($) well	Dec. 31, 2019 USD ($) well
Property, Plant and Equipment [Abstract]
Beginning balance	$ 459	$ 584	$ 418
Additions to capitalized exploratory well costs pending the determination of proved reserves	222	111	224
Reclassifications to wells, facilities and equipment based on the determination of proved reserves	0	(111)	(58)
Capitalized exploratory well costs charged to expense	0	(125)	0
Ending balance	$ 681	$ 459	$ 584
Number of Wells at December 31 \| well	35	22	31

Property, Plant and Equipment - Exploratory Drilling Costs Capitalized (Detail) $ in Millions	Dec. 31, 2021 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	$ 459
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	117
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	173
2018
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	105
2017
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	27
2016 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	$ 37

Property, Plant and Equipment - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) well	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Capitalized Exploratory Well Costs [Line Items]
Charge to write-off previously capitalized exploratory wells	$ 0	$ 125	$ 0
Well costs incurred and expensed	11	$ 67	$ 49
Shenzi Field, Gulf of Mexico
Capitalized Exploratory Well Costs [Line Items]
Charge to write-off previously capitalized exploratory wells	$ 125
Participation interest percentage	28.00%	28.00%
Stabroek Block, Offshore Guyana
Capitalized Exploratory Well Costs [Line Items]
Participation interest percentage	30.00%
Capitalized well costs percentage	90.00%
JDA, Gulf of Thailand
Capitalized Exploratory Well Costs [Line Items]
Participation interest percentage	50.00%
Capitalized well costs percentage	8.00%
Successful exploration wells \| well	3
North Malay Basin, Offshore Peninsular Malaysia
Capitalized Exploratory Well Costs [Line Items]
Participation interest percentage	50.00%
Capitalized well costs percentage	2.00%
Successful exploration wells \| well	1

Hess Midstream LP (Detail) bbl in Millions, $ in Millions				1 Months Ended			3 Months Ended	12 Months Ended
Hess Midstream LP (Detail) bbl in Millions, $ in Millions	Dec. 16, 2019 USD ($) shares	Apr. 10, 2017 USD ($) shares	Jul. 01, 2015 USD ($)	Oct. 31, 2021 USD ($) shares	Aug. 31, 2021 USD ($) shares	Mar. 31, 2021 USD ($) shares	Dec. 31, 2021 USD ($)	Dec. 31, 2021 USD ($) bbl	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	May 21, 2015
Up-C Formation [Abstract]
Percentage of Class A Shares owned by public shareholders							13.00%
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Proceeds from sale of Class A shares of Hess Midstream LP				$ 108.0		$ 70.0		$ 178.0	$ 0.0	$ 0.0
Sale of Class A shares of Hess Midstream LP								255.0
Number of Class B units repurchased by Hess Midstream LP (in shares) \| shares					31,250,000
Proceeds from repurchase of units held by Hess Corporation and Global Infrastructure Partners, by Hess Midstream Operations LP					$ 750.0
Proceeds from repurchase of units held by Hess Corporation by Hess Midstream Operations LP					375.0
Senior unsecured fixed-rate note issued by Hess Midstream Operations LP					$ 750.0
Interest rate of senior unsecured fixed-rate note issued by Hess Midstream Operations LP					4.25%
Repurchase of Class B units of Hess Midstream Operations LP								362.0
Deferred tax impact to noncontrolling interests from repurchase of units held by parent by consolidated subsidiary					$ 15.0
Proceeds to noncontrolling interests from repurchase of units held by parent by consolidated subsidiary					375.0
Percentage of Class A Shares owned by public shareholders							13.00%
Variable Interest Entity, Measure of Activity [Abstract]
Liabilities							$ 13,489.0	13,489.0	12,486.0
Cash and cash equivalents							2,713.0	2,713.0	1,739.0
Property, plant and equipment — net							$ 14,182.0	$ 14,182.0	14,115.0
Gas processing capacity of LM4 \| bbl								200
Joint venture percentage owned by Targa Resources Corp							50.00%	50.00%
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				96.0		56.0		$ 152.0
Repurchase of Class B units of Hess Midstream Operations LP					28.0			28.0
Noncontrolling Interests
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Sale of Class A shares of Hess Midstream LP				62.0		41.0		103.0
Repurchase of Class B units of Hess Midstream Operations LP					$ 28.0			$ 390.0
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				12.0		14.0
Noncontrolling Interests \| Recognition Of Deferred Tax Asset
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Sale of Class A shares of Hess Midstream LP				$ 50.0		$ 27.0
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				8,600,000		6,900,000
Hess Midstream Partners LP (Hess Midstream Partners)
Initial Formation [Abstract]
Initial public offering common units sold (in shares) \| shares		16,997,000
Percentage of limited partnership interests		30.50%
Net proceeds from initial public offering		$ 365.5
Percentage of general partnership interest		2.00%
Up-C Formation [Abstract]
Acquired ownership interest percentage	80.00%
Hess Midstream Partners LP (Hess Midstream Partners) \| Noncontrolling Interests
Initial Formation [Abstract]
Percentage of limited partnership interests		33.75%
Indirect ownership interest percentage		50.00%
Hess North Dakota Export Logistics Operations LP
Initial Formation [Abstract]
Controlling economic interest, percentage		20.00%
Hess Mentor Storage Holdings LLC
Initial Formation [Abstract]
Controlling economic interest, percentage		100.00%
Hess Midstream Operations LP
Up-C Formation [Abstract]
Percentage of Class A Shares owned by public shareholders	6.00%
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Percentage of Class A Shares owned by public shareholders	6.00%
Hess Midstream Operations LP \| Noncontrolling Interests
Up-C Formation [Abstract]
Noncontrolling interest ownership percentage	47.00%
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Noncontrolling interest ownership percentage	47.00%
Hess Midstream Operations LP \| Class A Shares
Up-C Formation [Abstract]
Common stock exchange ratio	100.00%
Hess Midstream Operations LP \| Class B Shares
Up-C Formation [Abstract]
Common stock exchange ratio								100.00%
Hess Midstream LP
Up-C Formation [Abstract]
Percent interest in consolidated entity							43.50%
Noncontrolling interest ownership percentage							43.50%	43.50%
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Percent interest in consolidated entity							43.50%
Noncontrolling interest ownership percentage							43.50%	43.50%
Variable Interest Entity, Measure of Activity [Abstract]
Equity method investment, ownership percentage							50.00%	50.00%
Hess Corporation \| Hess Infrastructure Partners LP (HIP)
Initial Formation [Abstract]
Percentage of interest sold											50.00%
Proceeds from sale of interest			$ 2,600.0
Hess Corporation \| Hess Midstream Partners LP (Hess Midstream Partners)
Initial Formation [Abstract]
Percentage of limited partnership interests		33.75%
Indirect ownership interest percentage		50.00%
Hess Corporation \| Hess Midstream Operations LP
Up-C Formation [Abstract]
Cash received	$ 301.0
Class B units issued to Hess Corporation (in shares) \| shares	115,000,000
Percent interest in consolidated entity	47.00%
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Percent interest in consolidated entity	47.00%
Variable Interest Entity \| Hess Midstream LP
Variable Interest Entity, Measure of Activity [Abstract]
Cash and cash equivalents							$ 2.0	$ 2.0	3.0
Processing fees incurred								28.0	26.0	$ 6.0
Variable Interest Entity \| Hess Midstream LP \| Nonrecourse
Variable Interest Entity, Measure of Activity [Abstract]
Liabilities							2,694.0	2,694.0	2,026.0
Variable Interest Entity \| Hess Midstream LP \| Little Missouri Four
Variable Interest Entity, Measure of Activity [Abstract]
Equity method investment							102.0	102.0	108.0
Midstream
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net [Abstract]
Senior unsecured fixed-rate note issued by Hess Midstream Operations LP							2,073.0	2,073.0	1,331.0
Variable Interest Entity, Measure of Activity [Abstract]
Property, plant and equipment — net							$ 3,125.0	$ 3,125.0	$ 3,111.0
Midstream \| Hess Midstream Operations LP
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					31,250,000

Accrued Liabilities - Schedule of Accrued Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Payables and Accruals [Abstract]
Accrued capital expenditures	$ 479	$ 345
Accrued operating and marketing expenditures	462	325
Accrued payments to royalty and working interest owners	253	170
Current portion of asset retirement obligations	185	105
Accrued interest on debt	138	126
Accrued compensation and benefits	124	117
Other accruals	69	63
Accrued liabilities	$ 1,710	$ 1,251

Leases - Balance Sheet Information Related to Operating & Finance Leases (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Operating lease right-of-use assets — net	$ 352	$ 426
Finance lease right-of-use assets — net	$ 144	$ 168
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	$ 70	$ 63
Long-term operating lease obligations	394	478
Total lease obligations	464	541
Finance Lease Obligations:
Current finance lease obligations	19	18
Long-term finance lease obligations	200	220
Total lease obligations	219	238
Finance lease ROU assets cost	212	212
Finance lease ROU assets accumulated amortization	$ 68	$ 44

Leases - Maturity Profile of Lease Obligations (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Operating Leases
2022	$ 87
2023	75
2024	69
2025	64
2026	49
Remaining years	219
Total lease payments	563
Less: Imputed interest	(99)
Total lease obligations	464	$ 541
Finance Leases
2022	36
2023	36
2024	36
2025	36
2026	31
Remaining years	145
Total lease payments	320
Less: Imputed interest	(101)
Total lease obligations	$ 219	$ 238

Leases - Term & Rate Information Related to Operating & Finance Leases (Detail)	Dec. 31, 2021	Dec. 31, 2020
Operating Leases
Weighted average remaining lease term	9 years 10 months 24 days	10 years 3 months 18 days
Weighted average discount rate	4.10%	4.00%
Finance Leases
Weighted average remaining lease term	11 years 9 months 18 days	12 years 9 months 18 days
Range of remaining lease terms	11 years 9 months 18 days	12 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	1 month 6 days
Maximum
Operating Leases
Range of remaining lease terms	14 years 6 months	15 years 6 months

Leases - Components of Lease Costs (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Operating lease cost	$ 88	$ 200
Finance lease cost: Amortization of leased assets	24	31
Finance lease cost: Interest on lease obligations	18	20
Short-term lease cost	137	199
Variable lease cost	21	38
Sublease income	(17)	(15)
Total lease cost	$ 271	$ 473

Leases - Supplemental Cash Flow Information Related to Leases (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Cash paid for amounts included in the measurement of lease obligations:
Cash paid for operating leases (operating cash flows)	$ 87	$ 218
Cash paid for finance leases (operating cash flows)	18	20
Cash paid for finance leases (financing cash flows)	18	17
Noncash transactions:
Operating Leases - Leased assets recognized for new lease obligations incurred	12	51
Finance Leases - Leased assets recognized for new lease obligations incurred	0	0
Operating Leases - Changes in leased assets and lease obligations due to lease modifications	29	123
Finance Leases - Changes in leased assets and lease obligations due to lease modifications	$ 0	$ 0

Leases - Additional Information (Detail)	12 Months Ended
Leases - Additional Information (Detail)	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Lease obligations - Represented percentage of present value of future minimum lease payments in lease arrangement	100.00%
Remaining lease term on Floating, Storage and Offloading Vessel (FSO)	11 years 9 months 18 days	12 years 9 months 18 days
Lease costs - Represented percentage of the lease payments due for the period	100.00%

Debt - Components of Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Aug. 31, 2021	Jun. 30, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes		$ 750
Term loan facility			$ 1,000
Current portion of long-term debt	$ 517			$ 10
Long-term debt	7,941			8,286
Total Debt	$ 8,458			8,296
Interest rate of senior unsecured fixed-rate note		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	6.00%
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%
5.125% 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%
Hess Corporation
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	$ 5,395			5,393
Term loan facility	497			988
Fair value adjustments - interest rate hedging	2			5
Total Debt	5,894			6,386
Hess Corporation \| 3.500% due 2024
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	299			299
Hess Corporation \| 4.300% due 2027
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	995			994
Hess Corporation \| 7.875% due 2029
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	464			464
Hess Corporation \| 7.300% due 2031
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	628			628
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	742			741
Hess Corporation \| 5.600% due 2041
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	1,236			1,236
Hess Corporation \| 5.800% due 2047
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	494			494
Midstream
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	2,073			1,331
Term loan facility	387			395
Revolving credit facility - outstanding amount	104			184
Total Debt	2,564			1,910
Midstream \| 5.625% due 2026
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	791			789
Midstream \| 5.125% due 2028
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	543			542
Midstream \| 4.250% due 2030
Debt Instrument [Line Items]
Senior unsecured fixed-rate public notes	$ 739			$ 0

Debt - Maturity Profile of Debt (Detail) $ in Millions	Dec. 31, 2021 USD ($)
Debt Instrument [Line Items]
2022	$ 520
2023	30
2024	744
2025	0
2026	800
Thereafter	6,438
Total Borrowings	8,532
Less: Deferred financing costs and discounts	(74)
Total Debt (excluding interest)	8,458
Hess Corporation
Debt Instrument [Line Items]
2022	500
2023	0
2024	300
2025	0
2026	0
Thereafter	5,138
Total Borrowings	5,938
Less: Deferred financing costs and discounts	(44)
Total Debt (excluding interest)	5,894
Midstream
Debt Instrument [Line Items]
2022	20
2023	30
2024	444
2025	0
2026	800
Thereafter	1,300
Total Borrowings	2,594
Less: Deferred financing costs and discounts	(30)
Total Debt (excluding interest)	$ 2,564

Debt - Other Outstanding Letters of Credit (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Line of Credit Facility [Line Items]
Other outstanding letters of credit	$ 259	$ 269
Committed Lines
Line of Credit Facility [Line Items]
Other outstanding letters of credit	29	54
Uncommitted Lines
Line of Credit Facility [Line Items]
Other outstanding letters of credit	$ 230	$ 215

Debt - Additional Information - Hess Corporation (Details) - USD ($)	1 Months Ended			12 Months Ended
	Feb. 28, 2022	Feb. 25, 2022	Jul. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jun. 30, 2021
Debt Instrument [Line Items]
Capitalized interest				$ 0	$ 0	$ 38,000,000
Term loan facility							$ 1,000,000,000
Current portion of long-term debt				517,000,000	10,000,000
Remaining term loan to be repaid within next twelve months				520,000,000
Letters of credit - outstanding amount				259,000,000	269,000,000
Maximum additional amount allowed to borrow under financial covenants				1,843,000,000
Subsequent Event
Debt Instrument [Line Items]
Partial repayment of principal amount of term loan	$ 500,000,000
Hess Corporation
Debt Instrument [Line Items]
Term loan facility				497,000,000	988,000,000
Remaining term loan to be repaid within next twelve months				$ 500,000,000
Hess Corporation \| Revolving Credit Facility
Debt Instrument [Line Items]
Debt instrument covenant, secured debt to net tangible assets ratio				15.00%
Interest rate applicable margin				1.40%
Revolving credit facility - maximum borrowing capacity				$ 3,500,000,000
Revolving credit facility - outstanding amount				0
Letters of credit - outstanding amount				$ 0
Debt instrument covenant, debt to capital ratio				65.00%
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				15.00%
Hess Corporation \| 3-Year Term Loan Agreement
Debt Instrument [Line Items]
Debt instrument covenant, secured debt to net tangible assets ratio				15.00%
Term loan facility							$ 1,000,000,000
Term loan facility period				3 years
Partial repayment of principal amount of term loan			$ 500,000,000
Current portion of long-term debt				$ 500,000,000
Remaining term loan to be repaid within next twelve months				$ 500,000,000
Debt instrument covenant, debt to capital ratio				65.00%
Hess Corporation \| 3-Year Term Loan Agreement \| Subsequent Event
Debt Instrument [Line Items]
Partial repayment of principal amount of term loan		$ 500,000,000

Debt - Additional Information - Midstream (Detail) - USD ($) shares in Thousands	1 Months Ended	12 Months Ended
	Aug. 31, 2021	Dec. 31, 2021	Dec. 31, 2019	Jun. 30, 2021	Dec. 31, 2020	Nov. 30, 2017
Debt Instrument [Line Items]
Interest rate of senior unsecured fixed-rate note	4.25%
Principal amount of senior unsecured fixed-rate public note assumed by HESM Opco			$ 800,000,000
Number of Class B units repurchased by Hess Midstream LP (in shares)	31,250
Term loan facility				$ 1,000,000,000
Borrowings		$ 8,532,000,000
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%
Midstream
Debt Instrument [Line Items]
Term loan facility		$ 387,000,000			$ 395,000,000
Revolving credit facility - outstanding amount		104,000,000			$ 184,000,000
Borrowings		2,594,000,000
Midstream \| Hess Infrastructure Partners (HIP) \| 5.625% due 2026
Debt Instrument [Line Items]
Principal amount of senior unsecured fixed-rate public notes						$ 800,000,000
Interest rate of senior unsecured fixed-rate note						5.625%
Midstream \| Hess Midstream Operations LP
Debt Instrument [Line Items]
Number of Class B units repurchased by Hess Midstream LP (in shares)	31,250
Senior secured syndicated credit facilities		$ 1,400,000,000
Ratio of debt to EBITDA for prior four fiscal quarter - Maximum		500.00%
Ratio of debt to EBITDA for period after acquisitions - Maximum		550.00%
Secured leverage ratio - Maximum		400.00%
Midstream \| Hess Midstream Operations LP \| Revolving Credit Facility
Debt Instrument [Line Items]
Revolving credit facility - maximum borrowing capacity		$ 1,000,000,000
Term loan facility period		5 years
Revolving credit facility - outstanding amount		$ 104,000,000
Midstream \| Hess Midstream Operations LP \| Revolving Credit Facility \| Minimum
Debt Instrument [Line Items]
Interest rate applicable margin		1.275%
Midstream \| Hess Midstream Operations LP \| Revolving Credit Facility \| Maximum
Debt Instrument [Line Items]
Interest rate applicable margin		2.00%
Midstream \| Hess Midstream Operations LP \| 5.625% due 2026
Debt Instrument [Line Items]
Principal amount of senior unsecured fixed-rate public notes		$ 800,000,000
Interest rate of senior unsecured fixed-rate note		5.625%
Midstream \| Hess Midstream Operations LP \| 5.125% due 2028
Debt Instrument [Line Items]
Principal amount of senior unsecured fixed-rate public notes		$ 550,000,000
Interest rate of senior unsecured fixed-rate note		5.125%
Midstream \| Hess Midstream Operations LP \| 4.250% due 2030
Debt Instrument [Line Items]
Principal amount of senior unsecured fixed-rate public notes		$ 750,000,000
Interest rate of senior unsecured fixed-rate note		4.25%
Midstream \| Hess Midstream Operations LP \| 5-Year Term Loan Agreement
Debt Instrument [Line Items]
Term loan facility		$ 400,000,000
Term loan facility period		5 years
Borrowings		$ 390,000,000
Midstream \| Hess Midstream Operations LP \| 5-Year Term Loan Agreement \| Minimum
Debt Instrument [Line Items]
Interest rate applicable margin		1.55%
Midstream \| Hess Midstream Operations LP \| 5-Year Term Loan Agreement \| Maximum
Debt Instrument [Line Items]
Interest rate applicable margin		2.50%

Asset Retirement Obligations - Changes to Asset Retirement Obligations (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$ 999	$ 1,024
Liabilities incurred	229	36
Liabilities settled or disposed of	(207)	(161)
Accretion expense	44	46
Revisions of estimated liabilities	126	52
Foreign currency remeasurement	(1)	2
Asset retirement obligations at end of period	1,190	999
Current portion of asset retirement obligations	185	105
Long-term asset retirement obligations	1,005	894
Asset retirement obligations	$ 1,190	$ 999

Asset Retirement Obligations - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) u_hesLease	Dec. 31, 2020 USD ($)
Asset Retirement Obligations [Line Items]
Number of offshore Gulf of Mexico leases abandoned \| u_hesLease	7
Liabilities incurred \| $	$ 229	$ 36
Fair value of sinking fund deposits legally restricted for purposes of settling asset retirement obligations \| $	$ 233	$ 207
West Delta 79/86 Field
Asset Retirement Obligations [Line Items]
Number of offshore Gulf of Mexico leases abandoned \| u_hesLease	7
Number of leases received decommissioning orders \| u_hesLease	6
Liabilities incurred \| $	$ 147

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, 2021	Dec. 31, 2020
Change in Fair Value of Plan Assets
Beginning balance	$ 3,043
Ending balance	3,357	$ 3,043
Settlement payment included in Benefit payments	34	23
Changes in Discount Rate Assumptions
Change in Benefit Obligation
Actuarial (gains) loss	178	(387)
Change in Fair Value of Plan Assets
Actuarial gains or losses resulted from changes in assumptions	(178)	387
Changes In Inflation Assumptions
Change in Benefit Obligation
Actuarial (gains) loss	(36)	(24)
Change in Fair Value of Plan Assets
Actuarial gains or losses resulted from changes in assumptions	36	24
Changes in Mortality Assumptions
Change in Benefit Obligation
Actuarial (gains) loss	(7)	(18)
Change in Fair Value of Plan Assets
Actuarial gains or losses resulted from changes in assumptions	7	18
All Other Assumptions
Change in Benefit Obligation
Actuarial (gains) loss	(2)	(10)
Change in Fair Value of Plan Assets
Actuarial gains or losses resulted from changes in assumptions	2	10
Funded Pension Plans
Change in Benefit Obligation
Beginning balance	3,085	2,667
Service cost	41	37
Interest cost	52	68
Actuarial (gains) loss	(126)	385
Benefit payments	(100)	(93)
Plan amendments	2	0
Foreign currency exchange rate changes	(6)	21
Ending balance	2,948	3,085
Change in Fair Value of Plan Assets
Beginning balance	3,043	2,732
Actual return on plan assets	417	378
Employer contributions	6	4
Benefit payments	(100)	(93)
Foreign currency exchange rate changes	(9)	22
Ending balance	3,357	3,043
Funded Status (Plan assets greater (less) than benefit obligations) at December 31,	409	(42)
Unrecognized Net Actuarial (Gains) Losses	501	900
Actuarial gains or losses resulted from changes in assumptions	126	(385)
Accumulated benefit obligation	2,856	2,993
Unfunded Pension Plan
Change in Benefit Obligation
Beginning balance	269	242
Service cost	10	13
Interest cost	3	5
Actuarial (gains) loss	(8)	26
Benefit payments	(26)	(17)
Plan amendments	0	0
Foreign currency exchange rate changes	0	0
Ending balance	248	269
Change in Fair Value of Plan Assets
Beginning balance	0	0
Actual return on plan assets	0	0
Employer contributions	26	17
Benefit payments	(26)	(17)
Foreign currency exchange rate changes	0	0
Ending balance	0	0
Funded Status (Plan assets greater (less) than benefit obligations) at December 31,	(248)	(269)
Unrecognized Net Actuarial (Gains) Losses	66	86
Actuarial gains or losses resulted from changes in assumptions	8	(26)
Accumulated benefit obligation	208	228
Postretirement Medical Plan
Change in Benefit Obligation
Beginning balance	65	75
Service cost	3	3
Interest cost	1	1
Actuarial (gains) loss	(3)	(8)
Benefit payments	(7)	(6)
Plan amendments	0	0
Foreign currency exchange rate changes	0	0
Ending balance	59	65
Change in Fair Value of Plan Assets
Beginning balance	0	0
Actual return on plan assets	0	0
Employer contributions	7	6
Benefit payments	(7)	(6)
Foreign currency exchange rate changes	0	0
Ending balance	0	0
Funded Status (Plan assets greater (less) than benefit obligations) at December 31,	(59)	(65)
Unrecognized Net Actuarial (Gains) Losses	(21)	(19)
Actuarial gains or losses resulted from changes in assumptions	$ 3	$ 8

Retirement Plans - Amounts Recognized in Balance Sheet for Pension Plans & Postretirement Medical Plan (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Noncurrent assets	$ 409	$ 45
Accumulated other comprehensive (gain) loss related to retirement plans, after-tax - Deficit	338	759
Funded Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Noncurrent assets	409	45
Current liabilities	0	0
Noncurrent liabilities	0	(87)
Pension assets / (accrued benefit liability)	409	(42)
Accumulated other comprehensive loss, pre-tax	501	900
Unfunded Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Noncurrent assets	0	0
Current liabilities	(34)	(49)
Noncurrent liabilities	(214)	(220)
Pension assets / (accrued benefit liability)	(248)	(269)
Accumulated other comprehensive loss, pre-tax	66	86
Postretirement Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Noncurrent assets	0	0
Current liabilities	(6)	(7)
Noncurrent liabilities	(53)	(58)
Pension assets / (accrued benefit liability)	(59)	(65)
Accumulated other comprehensive loss, pre-tax	$ (21)	$ (19)

Retirement Plans - Components of Net Periodic Benefit Cost for Pension Plans & Postretirement Medical Plan (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Settlement loss	$ 9	$ 0	$ 93
Net non-service pension (income) costs included in Other, net	(75)	(59)	55
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Service cost	51	50	44
Interest cost	55	73	89
Expected return on plan assets	(197)	(180)	(180)
Amortization of unrecognized net actuarial losses (gains)	58	48	52
Settlement loss	9	0	93
Curtailment gain	0	0	0
Net Periodic Benefit Cost	(24)	(9)	98
Postretirement Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	3	3	2
Interest cost	1	1	2
Expected return on plan assets	0	0	0
Amortization of unrecognized net actuarial losses (gains)	(1)	(1)	(1)
Settlement loss	0	0	0
Curtailment gain	0	0	0
Net Periodic Benefit Cost	$ 3	$ 3	$ 3

Retirement Plans - Actuarial Assumptions Used for Pension Plans & Postretirement Medical Plan (Detail)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Plans
Benefit Obligations:
Discount rate	2.50%	2.20%	2.90%
Rate of compensation increase	3.80%	3.80%	3.80%
Net Periodic Benefit Cost:
Expected return on plan assets	6.60%	6.70%	7.10%
Rate of compensation increase	3.80%	3.80%	3.80%
Pension Plans \| Service Cost
Net Periodic Benefit Cost:
Discount rate, Service cost	2.60%	3.20%	3.90%
Pension Plans \| Interest Cost
Net Periodic Benefit Cost:
Discount rate, Service cost	1.70%	2.60%	3.40%
Postretirement Medical Plan
Benefit Obligations:
Discount rate	2.40%	1.90%	2.80%
Initial health care trend rate	5.50%	6.00%	6.50%
Ultimate trend rate	4.00%	4.50%	4.50%
Year in which ultimate trend rate is reached	2046	2038	2038

Retirement Plans - Estimated Future Benefit Payments for Pension Plans & Postretirement Medical Plan (Detail) $ in Millions	Dec. 31, 2021 USD ($)
Retirement Benefits [Abstract]
2022	$ 131
2023	132
2024	137
2025	125
2026	131
Years 2027 to 2031	$ 662

Retirement Plans - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Settlement loss		$ (9)	$ 0	$ (93)
Budgeted contributions to funded pension plans for next year		45
Expense for defined contribution plans		$ 18	22	20
Scenario Forecast
Defined Benefit Plan Disclosure [Line Items]
Service costs	$ 50
Net non-service pension costs	135
Interest costs	65
Amortization of unrecognized net actuarial losses	15
Expected return on plan assets	$ 215
Equity Securities
Defined Benefit Plan Disclosure [Line Items]
Current target allocations for plan assets		45.00%
Fixed Income Securities
Defined Benefit Plan Disclosure [Line Items]
Current target allocations for plan assets		35.00%
Other Types of Investments
Defined Benefit Plan Disclosure [Line Items]
Current target allocations for plan assets		20.00%
Funded Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Single premium annuity contract cost				249
Settlement loss				$ 88
Service costs		$ 41	37
Interest costs		$ 52	$ 68

Revenue - Summary of Revenue from Contracts with Customers on a Disaggregated Basis (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	$ 7,683	$ 4,094	$ 6,456
Other operating revenues	(210)	573	39
Total sales and other operating revenues	7,473	4,667	6,495
Gain (loss) on commodity derivatives	(243)	547	1
Crude Oil Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	4,325	2,363	3,660
Natural Gas Liquids Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	594	253	229
Natural Gas Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	1,015	631	829
Sales of Purchased Oil and Gas
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	1,749	847	1,738
Exploration and Production
Disaggregation of Revenue [Line Items]
Total sales and other operating revenues	7,473	4,667	6,495
Exploration and Production \| Crude Oil Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	4,325	2,363	3,660
Exploration and Production \| Natural Gas Liquids Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	594	253	229
Exploration and Production \| Natural Gas Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	1,015	631	829
Exploration and Production \| Sales of Purchased Oil and Gas
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	1,749	847	1,738
Exploration and Production \| United States \| Crude Oil Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	2,958	1,898	2,981
Exploration and Production \| United States \| Natural Gas Liquids Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	594	253	229
Exploration and Production \| United States \| Natural Gas Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	350	144	150
Exploration and Production \| United States \| Sales of Purchased Oil and Gas
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	1,638	831	1,644
Exploration and Production \| Guyana \| Crude Oil Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	765	278	0
Exploration and Production \| Guyana \| Natural Gas Liquids Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0	0
Exploration and Production \| Guyana \| Natural Gas Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0	0
Exploration and Production \| Guyana \| Sales of Purchased Oil and Gas
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	16	5	0
Exploration and Production \| Malaysia and JDA \| Crude Oil Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	83	34	113
Exploration and Production \| Malaysia and JDA \| Natural Gas Liquids Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0	0
Exploration and Production \| Malaysia and JDA \| Natural Gas Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	655	477	646
Exploration and Production \| Malaysia and JDA \| Sales of Purchased Oil and Gas
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0	3
Exploration and Production \| Other \| Crude Oil Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	519	153	566
Exploration and Production \| Other \| Natural Gas Liquids Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0	0
Exploration and Production \| Other \| Natural Gas Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	10	10	33
Exploration and Production \| Other \| Sales of Purchased Oil and Gas
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	95	11	91
Midstream
Disaggregation of Revenue [Line Items]
Total sales and other operating revenues	0	0	0
Midstream \| Crude Oil Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0	0
Midstream \| Natural Gas Liquids Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0	0
Midstream \| Natural Gas Revenue
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0	0
Midstream \| Sales of Purchased Oil and Gas
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0	0
Operating Segments \| United States
Disaggregation of Revenue [Line Items]
Total sales and other operating revenues	5,378	3,604	5,043
Operating Segments \| Guyana
Disaggregation of Revenue [Line Items]
Total sales and other operating revenues	754	350	0
Operating Segments \| Malaysia and JDA
Disaggregation of Revenue [Line Items]
Total sales and other operating revenues	738	511	762
Operating Segments \| Other
Disaggregation of Revenue [Line Items]
Total sales and other operating revenues	603	202	690
Operating Segments \| Exploration and Production
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	7,683	4,094	6,456
Other operating revenues	(210)	573	39
Total sales and other operating revenues	7,473	4,667	6,495
Operating Segments \| Exploration and Production \| United States
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	5,540	3,126	5,004
Other operating revenues	(162)	478	39
Total sales and other operating revenues	5,378	3,604	5,043
Operating Segments \| Exploration and Production \| Guyana
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	781	283	0
Other operating revenues	(27)	67	0
Total sales and other operating revenues	754	350	0
Operating Segments \| Exploration and Production \| Malaysia and JDA
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	738	511	762
Other operating revenues	0	0	0
Total sales and other operating revenues	738	511	762
Operating Segments \| Exploration and Production \| Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	624	174	690
Other operating revenues	(21)	28	0
Total sales and other operating revenues	603	202	690
Operating Segments \| Midstream
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	1,204	1,092	848
Other operating revenues	0	0	0
Total sales and other operating revenues	1,204	1,092	848
Eliminations
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	(1,204)	(1,092)	(848)
Other operating revenues	0	0	0
Total sales and other operating revenues	(1,204)	(1,092)	(848)
Eliminations \| Exploration and Production
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0	0
Total sales and other operating revenues	0	0	0
Eliminations \| Exploration and Production \| United States
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0	0
Eliminations \| Exploration and Production \| Guyana
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0	0
Eliminations \| Exploration and Production \| Malaysia and JDA
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0	0
Eliminations \| Exploration and Production \| Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	0	0	0
Eliminations \| Midstream
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers	1,204	1,092	848
Total sales and other operating revenues	$ 1,204	$ 1,092	$ 848

Revenue from Contract with Customer - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Contract asset	$ 0	$ 0
Contract liability	$ 24	$ 0

Dispositions (Detail) $ in Millions	12 Months Ended
Dispositions (Detail) $ in Millions	Dec. 31, 2021 USD ($) a	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales	$ 427	$ 493	$ 22
Gain (loss) on asset sales, pre-tax	29	87	22
Interests in Denmark
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales	130
Gain (loss) on asset sales, pre-tax	29
Gain (loss) on asset sale, after income taxes	29
Little Knife & Murphy Creek, Interests in Bakken
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales	$ 297
Developed and undeveloped acreage sold \| a	78,700
Shenzi Field, Gulf of Mexico
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales		482
Gain (loss) on asset sales, pre-tax		79
Gain (loss) on asset sale, after income taxes		$ 79
Participation interest percentage	28.00%	28.00%
Utica Shale Play, Eastern Ohio
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales			22
Gain (loss) on asset sales, pre-tax			22
Gain (loss) on asset sale, after income taxes			$ 22

Impairment and Other (Detail) $ in Millions	3 Months Ended	12 Months Ended
Impairment and Other (Detail) $ in Millions	Mar. 31, 2020 USD ($) $ / bbl	Dec. 31, 2021 USD ($) u_hesLease	Dec. 31, 2020 USD ($)
Impairments [Line Items]
Loss contingency charge, pre-tax		$ 147
Loss contingency charge, after tax		$ 147
Number of offshore Gulf of Mexico leases abandoned \| u_hesLease		7
Oil and Gas Properties
Impairments [Line Items]
Fair value of estimated impairment charges determined using internal projected discounted cash flows	$ 1,050
Weighted average crude oil benchmark price for impaired assets (US dollar per barrel) \| $ / bbl	48.82
Discount rate used in fair value measurements	10.00%
Oil and Gas Properties \| West Texas Intermediate
Impairments [Line Items]
Future strip crude oil price (US dollar per barrel) used in impairment \| $ / bbl	50
Oil and Gas Properties \| Brent
Impairments [Line Items]
Future strip crude oil price (US dollar per barrel) used in impairment \| $ / bbl	55
Oil and Gas Properties \| North Malay Basin in Malaysia
Impairments [Line Items]
Impairment charge, pre-tax			$ 755
Impairment charge, after income taxes			755
Oil and Gas Properties \| South Arne Field in Denmark
Impairments [Line Items]
Impairment charge, pre-tax			670
Impairment charge, after income taxes			594
Oil and Gas Properties \| Stampede Field in Gulf of Mexico
Impairments [Line Items]
Impairment charge, pre-tax			410
Impairment charge, after income taxes			410
Oil and Gas Properties \| Tubular Bells Field in Gulf of Mexico
Impairments [Line Items]
Impairment charge, pre-tax			270
Impairment charge, after income taxes			270
Other Assets
Impairments [Line Items]
Impairment charge, pre-tax			21
Impairment charge, after income taxes			$ 20

Severance Costs (Detail) - USD ($) $ in Millions	12 Months Ended
Severance Costs (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Restructuring and Related Activities [Abstract]
Severance expense		$ 27
Accrued severance costs paid	$ 7	$ 20	$ 4

Share-based Compensation - Share-based Compensation Cost by Award Type (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Share-based compensation expense before income taxes	$ 77	$ 79	$ 85
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	49	51	53
Performance Share Units
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Share-based compensation expense before income taxes	18	18	22
Stock Options
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Share-based compensation expense before income taxes	$ 10	$ 10	$ 10

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards - Outstanding at beginning of period (in shares)	1,917
Awards - Granted (in shares)	781
Awards - Vested (in shares)	(980)
Awards - Forfeited (in shares)	(102)
Awards - Outstanding at end of period (in shares)	1,616	1,917
Weighted average fair value on date of grant - Outstanding at beginning of period (in dollars per share)	$ 51.94
Weighted average fair value on date of grant - Granted (in dollars per share)	75.11
Weighted average fair value on date of grant - Vested (in dollars per share)	52.72
Weighted average fair value on date of grant - Forfeited (in dollars per share)	57.16
Weighted average fair value on date of grant - Outstanding at end of period (in dollars per share)	$ 62.33	$ 51.94
Fair value of vested shares	$ 72	$ 51	$ 102

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards - Outstanding at beginning of period (in shares)	806
Awards - Granted (in shares)	205
Awards - Vested (in shares)	(274)
Awards - Forfeited (in shares)	(4)
Awards - Outstanding at end of period (in shares)	733	806
Weighted average fair value on date of grant - Outstanding at beginning of period (in dollars per share)	$ 62.36
Weighted average fair value on date of grant - Granted (in dollars per share)	86.70
Weighted average fair value on date of grant - Vested (in dollars per share)	59.65
Weighted average fair value on date of grant - Forfeited (in dollars per share)	62.66
Weighted average fair value on date of grant - Outstanding at end of period (in dollars per share)	$ 70.17	$ 62.36
Fair value of vested shares	$ 30	$ 48	$ 16

Share-based Compensation - Assumptions to Estimate Fair Value of Performance Share Units (Detail) - Performance Share Units - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk free interest rate	0.29%	0.52%	2.48%
Stock price volatility	57.90%	37.40%	36.90%
Contractual term in years	3 years	3 years	3 years
Grant date price of Hess common stock (in dollars per share)	$ 75.04	$ 49.72	$ 56.74

Share-based Compensation - Summary of Stock Options Activity (Detail) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Options - Outstanding at beginning of period (in shares)	4,382
Options - Granted (in shares)	319
Options - Exercised (in shares)	(1,538)	(300)	(700)
Options - Cancelled (in shares)	(1,049)
Options - Forfeited (in shares)	(27)
Options - Outstanding at end of period (in shares)	2,087	4,382
Weighted average exercise price per share - Outstanding at beginning of period (in dollars per share)	$ 61.57
Weighted average exercise price per share - Granted (in dollars per share)	75.04
Weighted average exercise price per share - Exercised (in dollars per share)	49.87
Weighted average exercise price per share - Cancelled (in dollars per share)	83.88
Weighted average exercise price per share - Forfeited (in dollars per share)	52.07
Weighted average exercise price per share - Outstanding at end of period (in dollars per share)	$ 61.15	$ 61.57
Weighted average remaining contractual term - Outstanding	6 years 6 months	5 years 1 month 6 days

Share-based Compensation - Assumptions to Estimate Fair Value of Stock Options (Detail) - Stock Options - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk free interest rate	0.95%	0.64%	2.55%
Stock price volatility	47.00%	37.20%	35.90%
Dividend yield	1.33%	2.01%	1.76%
Expected life in years	6 years	6 years	6 years
Weighted average fair value per option granted (in dollars per share)	$ 29.66	$ 14.30	$ 18.08

Share-based Compensation - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of authorized common stock shares under LTIP (in shares)	63,500,000
Number of shares under LTIP, available for issuance of restricted common shares, performance share units and stock options	23,600,000
Unearned compensation expense, before income taxes	$ 79.0
Weighed average period of recognition for unearned compensation expense	1 year 9 months 18 days
Outstanding stock options (in shares)	2,087,000	4,382,000
Number of stock options, exercisable (in shares)	1,170,000
Weighted average exercise price per share - Outstanding at end of period (in dollars per share)	$ 61.15	$ 61.57
Weighted average exercise price per share - stock options exercisable (in dollars per share)	$ 62.27
Weighted average remaining contractual term - Outstanding	6 years 6 months	5 years 1 month 6 days
Weighted average remaining contractual life for options, exercisable	5 years
Aggregated intrinsic value	$ 28.0
Aggregated intrinsic value for exercisable options	15.0
Aggregated intrinsic value for options exercised	$ 45.0	$ 3.0	$ 10.0
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
Performance Share Units \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout percentage	0.00%
Performance Share Units \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout percentage	200.00%
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 Income Tax Provision (Benefit) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
United States - Federal, Current income tax expense (benefit)	$ 0	$ (4)	$ (1)
United States - Federal, Deferred income taxes and other accruals expense (benefit)	12	6	72
United States - State, Current & Deferred income taxes and other accruals expense (benefit)	3	(1)	16
United States - Current & Deferred income taxes, and other accruals expense (benefit)	15	1	87
Foreign - Current income tax expense (benefit)	478	48	447
Foreign - Deferred income taxes and other accruals expense (benefit)	107	(60)	(73)
Foreign - Current & Deferred income taxes and other accruals expense (benefit)	585	(12)	374
Provision (Benefit) For Income Taxes	$ 600	$ (11)	$ 461

- Definition

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

+ References + Details

Income Taxes - Components of Income (Loss) Before Income Taxes (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
United States - Income (Loss) Before Income Taxes	$ 143	$ (1,509)	$ (338)
Foreign - Income (Loss) Before Income Taxes	1,347	(1,341)	559
Income (Loss) Before Income Taxes	$ 1,490	$ (2,850)	$ 221

- Definition

Amount of income (loss) from continuing operations, including income (loss) from equity method investments, before deduction of income tax expense (benefit), and income (loss) attributable to noncontrolling interest.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Income Taxes - Reconciliation of Effective Income Tax Rate (Detail)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
U.S. statutory rate	21.00%	21.00%	21.00%
Effect of foreign operations	28.00%	12.10%	142.90%
State income taxes, net of federal income tax	0.20%	0.10%	5.80%
Valuation allowance on current year operations	(5.30%)	(36.50%)	41.80%
Release valuation allowance against previously unbenefited deferred tax assets	0.00%	0.00%	(24.50%)
Noncontrolling interests in Midstream	(4.00%)	1.70%	(16.00%)
Intraperiod allocation	0.00%	0.00%	33.70%
Credits	0.00%	2.00%	0.00%
Equity and executive compensation	0.40%	(0.10%)	2.20%
Other	0.00%	0.10%	1.20%
Total	40.30%	0.40%	208.10%

Income Taxes - Components of Deferred Tax Assets & Liabilities (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Deferred Tax Liabilities
Property, plant and equipment and investments	$ (1,712)	$ (847)
Other	(38)	(45)
Total Deferred Tax Liabilities	(1,750)	(892)
Deferred Tax Assets
Net operating loss carryforwards	4,323	5,037
Tax credit carryforwards	89	135
Property, plant and equipment and investments	258	55
Accrued compensation, deferred credits and other liabilities	71	196
Asset retirement obligations	258	252
Other	277	325
Total Deferred Tax Assets	5,276	6,000
Valuation allowances	(3,838)	(5,391)
Total deferred tax assets, net of valuation allowances	1,438	609
Net Deferred Tax Assets (Liabilities)	(312)	(283)
Valuation allowance increase (decrease) amount	(1,553)	657	$ (143)
Deferred Tax Liabilities, Net [Abstract]
Deferred income taxes (long-term asset)	71	59
Deferred income taxes (long-term liability)	(383)	(342)
Net Deferred Tax Assets (Liabilities)	$ (312)	$ (283)

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Beginning balance	$ 166	$ 168	$ 168
Additions based on tax positions taken in the current year	12	2	2
Additions based on tax positions of prior years	3	1	1
Reductions based on tax positions of prior years	(48)	(2)	(1)
Reductions due to settlements with taxing authorities	0	(1)	0
Reductions due to lapses in statutes of limitation	0	(2)	(2)
Ending balance	$ 133	$ 166	$ 168

Income Taxes - Additional Information (Detail) - USD ($)	Dec. 31, 2021	Dec. 31, 2020
Income Tax Examination [Line Items]
Gross deferred tax asset related to net operating loss carryforwards	$ 4,323,000,000	$ 5,037,000,000
Gross deferred tax asset related to foreign net operating loss carryforwards	300,000,000
Gross deferred tax asset related to net U.S. federal operating loss carryforwards	3,507,000,000
Gross deferred tax asset related to net operating loss carryforwards for various U.S. states	516,000,000
Deferred tax asset related to foreign net operating loss carryforwards, net of valuation allowance	166,000,000
Valuation allowance against net deferred tax assets	3,838,000,000	5,391,000,000
Alternative minimum tax credit carryforwards	18,000,000
Other business credit carryforwards	71,000,000
Foreign tax credit carryforwards - Before valuation allowance	1,000,000
Unrecognized tax benefits that would impact effective income tax rate	15,000,000
Accrued interest and penalties	6,000,000	$ 6,000,000
Minimum
Income Tax Examination [Line Items]
Unrecognized tax benefits decrease reasonably possible	0
Maximum
Income Tax Examination [Line Items]
Unrecognized tax benefits decrease reasonably possible	15,000,000
U.S. Federal \| Midstream
Income Tax Examination [Line Items]
Valuation allowance against net deferred tax assets	12,000,000
U.S. State \| Midstream
Income Tax Examination [Line Items]
Valuation allowance against net deferred tax assets	$ 3,000,000

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Net Income (Loss) Attributable to Hess Corporation Common Stockholders:
Net Income (Loss)	$ 890	$ (2,839)	$ (240)
Less: Net income (loss) attributable to noncontrolling interests	331	254	168
Less: Preferred stock dividends	0	0	4
Net Income (Loss) Attributable to Hess Corporation Common Stockholders	$ 559	$ (3,093)	$ (412)
Weighted Average Number of Common Shares Outstanding:
Shares outstanding – Basic (in shares)	307.4	304.8	301.2
Weighted Average Number of Common Shares Outstanding (Diluted) (in shares)	309.3	304.8	301.2
Basic (in dollars per share)	$ 1.82	$ (10.15)	$ (1.37)
Diluted (in dollars per share)	$ 1.81	$ (10.15)	$ (1.37)
Restricted Common Stock
Weighted Average Number of Common Shares Outstanding:
Antidilutive shares excluded from computation of diluted shares (in shares)	0.0	2.1	2.2
Stock Options
Weighted Average Number of Common Shares Outstanding:
Antidilutive shares excluded from computation of diluted shares (in shares)	0.7	4.3	4.7
Performance Share Units
Weighted Average Number of Common Shares Outstanding:
Antidilutive shares excluded from computation of diluted shares (in shares)	0.0	1.1	1.7
Restricted Common Stock
Weighted Average Number of Common Shares Outstanding:
Effect of dilutive securities (in shares)	0.7	0.0	0.0
Stock Options
Weighted Average Number of Common Shares Outstanding:
Effect of dilutive securities (in shares)	0.4	0.0	0.0
Performance Share Units
Weighted Average Number of Common Shares Outstanding:
Effect of dilutive securities (in shares)	0.8	0.0	0.0

Outstanding and Weighted Average Common Shares - Changes in Outstanding Common Shares (Detail) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Equity [Abstract]
Beginning balance (in shares)	307,000	304,900	291,400
Conversion of preferred stock (in shares)	0	0	11,600
Activity related to restricted stock awards, net (in shares)	700	1,000	900
Stock options exercised (in shares)	1,538	300	700
PSUs vested (in shares)	500	800	300
Ending balance (in shares)	309,700	307,000	304,900

Outstanding and Weighted Average Common Shares - Additional Information (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	1 Months Ended	12 Months Ended
	Feb. 29, 2016	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Equity [Abstract]
Number of series A mandatory convertible preferred stock issued (in shares)	575
Dividend rate of series A mandatory convertible preferred stock	8.00%
Par value of series A mandatory convertible preferred stock (in dollars per share)	$ 1
Liquidation preference of series A mandatory convertible preferred stock (in dollars per share)	$ 1,000
Conversion of preferred stock (in shares)		0	0	11,600
Additional amount of common stock that may be repurchased		$ 650
Cash dividends on common stock (in dollars per share)		$ 1.00	$ 1.00	$ 1.00

Supplementary Cash Flow Information - Schedule of Cash Flow Supplemental Disclosures (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash Flows From Operating Activities
Interest paid	$ (459)	$ (460)	$ (380)
Net income taxes (paid) refunded	(16)	(64)	(417)
Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P	(1,584)	(1,896)	(2,433)
Additions to property, plant and equipment - Midstream	(163)	(301)	(396)
Exploration and Production
Cash Flows From Investing Activities
Capital expenditures incurred	(1,698)	(1,678)	(2,576)
Increase (decrease) in related liabilities	114	(218)	143
Additions to property, plant and equipment - E&P	(1,584)	(1,896)	(2,433)
Midstream
Cash Flows From Investing Activities
Capital expenditures incurred	(183)	(253)	(416)
Increase (decrease) in related liabilities	20	(48)	20
Additions to property, plant and equipment - Midstream	$ (163)	$ (301)	$ (396)

Supplementary Cash Flow Information - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)
Supplemental Cash Flow Elements [Abstract]
Principal amount of senior unsecured fixed-rate public note assumed by HESM Opco	$ 800

Guarantees, Contingencies and Commitments - Schedule of Unconditional Purchase Obligations & Commitments (Detail) $ in Millions	Dec. 31, 2021 USD ($)
Capital Expenditures
Loss Contingencies [Line Items]
Total	$ 3,263
2022	1,028
2023 and 2024	1,458
2025 and 2026	777
Thereafter	0
Operating Expenses
Loss Contingencies [Line Items]
Total	180
2022	132
2023 and 2024	42
2025 and 2026	6
Thereafter	0
Transportation and Related Contracts
Loss Contingencies [Line Items]
Total	2,574
2022	390
2023 and 2024	639
2025 and 2026	453
Thereafter	$ 1,092

Guarantees, Contingencies and Commitments - Additional Information (Detail) $ in Millions		1 Months Ended	12 Months Ended
	Mar. 04, 2016 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2021 USD ($) u_hesLease case
Loss Contingencies [Line Items]
Number of offshore Gulf of Mexico leases abandoned \| u_hesLease			7
Loss contingency charge, pre-tax			$ 147
Loss contingency charge, after tax			$ 147
West Delta 79/86 Field
Loss Contingencies [Line Items]
Number of offshore Gulf of Mexico leases abandoned \| u_hesLease			7
Number of leases received decommissioning orders \| u_hesLease			6
MTBE Cases
Loss Contingencies [Line Items]
Total number of remaining active cases filed \| case			2
Lower Passaic River
Loss Contingencies [Line Items]
Estimated remediation cost	$ 1,380
Gowanus Canal Superfund Site
Loss Contingencies [Line Items]
Estimated remediation cost		$ 506

Segment Information - Financial Data by Operating Segments (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Sales and other operating revenues	$ 7,473	$ 4,667	$ 6,495
Net Income (Loss) Attributable to Hess Corporation	559	(3,093)	(408)
Interest Expense	481	468	380
Depreciation, Depletion and Amortization	1,528	2,074	2,122
Impairment and Other	147	2,126	0
Provision (Benefit) for Income Taxes	600	(11)	461
Investment in Affiliates	197	212
Identifiable Assets	20,515	18,821
Capital Expenditures	1,881	1,931	2,992
Corporate, Interest and Other
Segment Reporting Information [Line Items]
Sales and other operating revenues	0	0	0
Net Income (Loss) Attributable to Hess Corporation	(497)	(482)	(605)
Interest Expense	376	373	317
Depreciation, Depletion and Amortization	1	2	3
Impairment and Other	0	0
Provision (Benefit) for Income Taxes	0	(6)	86
Investment in Affiliates	1	0
Identifiable Assets	2,671	1,534
Capital Expenditures	0	0	0
Eliminations
Segment Reporting Information [Line Items]
Sales and other operating revenues	(1,204)	(1,092)	(848)
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
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	7,473	4,667	6,495
Exploration and Production \| Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues	7,473	4,667	6,495
Net Income (Loss) Attributable to Hess Corporation	770	(2,841)	53
Interest Expense	0	0	0
Depreciation, Depletion and Amortization	1,361	1,915	1,977
Impairment and Other	147	2,126
Provision (Benefit) for Income Taxes	585	(12)	375
Investment in Affiliates	94	104
Identifiable Assets	14,173	13,688
Capital Expenditures	1,698	1,678	2,576
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	0	0	0
Midstream \| Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues	1,204	1,092	848
Net Income (Loss) Attributable to Hess Corporation	286	230	144
Interest Expense	105	95	63
Depreciation, Depletion and Amortization	166	157	142
Impairment and Other	0	0
Provision (Benefit) for Income Taxes	15	7	0
Investment in Affiliates	102	108
Identifiable Assets	3,671	3,599
Capital Expenditures	183	253	416
Midstream \| Eliminations
Segment Reporting Information [Line Items]
Sales and other operating revenues	$ 1,204	$ 1,092	$ 848

Segment Information - Financial Information by Major Geographic Area (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Sales and other operating revenues	$ 7,473	$ 4,667	$ 6,495
Property, Plant and Equipment— Net	14,182	14,115
Exploration and Production
Segment Reporting Information [Line Items]
Sales and other operating revenues	7,473	4,667	6,495
Property, Plant and Equipment— Net	6,596	7,273
Midstream
Segment Reporting Information [Line Items]
Sales and other operating revenues	0	0	0
Property, Plant and Equipment— Net	3,125	3,111
Operating Segments \| Exploration and Production
Segment Reporting Information [Line Items]
Sales and other operating revenues	7,473	4,667	6,495
Operating Segments \| Midstream
Segment Reporting Information [Line Items]
Sales and other operating revenues	1,204	1,092	848
Corporate, Interest and Other
Segment Reporting Information [Line Items]
Sales and other operating revenues	0	0	0
Property, Plant and Equipment— Net	10	11
United States \| Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues	5,378	3,604	5,043
Property, Plant and Equipment— Net	9,721	10,384
United States \| Operating Segments \| Exploration and Production
Segment Reporting Information [Line Items]
Sales and other operating revenues	5,378	3,604	5,043
Guyana \| Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues	754	350	0
Property, Plant and Equipment— Net	3,064	2,114
Guyana \| Operating Segments \| Exploration and Production
Segment Reporting Information [Line Items]
Sales and other operating revenues	754	350	0
Malaysia and JDA \| Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues	738	511	762
Property, Plant and Equipment— Net	1,035	1,067
Malaysia and JDA \| Operating Segments \| Exploration and Production
Segment Reporting Information [Line Items]
Sales and other operating revenues	738	511	762
Other \| Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues	603	202	690
Property, Plant and Equipment— Net	352	539
Other \| Operating Segments \| Exploration and Production
Segment Reporting Information [Line Items]
Sales and other operating revenues	$ 603	$ 202	$ 690

Segment Information - Additional Information (Detail)	12 Months Ended
Segment Information - Additional Information (Detail)	Dec. 31, 2021 segment
Segment Reporting [Abstract]
Number of operating segments for the Corporation	2

Financial Risk Management Activities - Notional Amounts of Outstanding Financial Risk Management Derivative Contracts (Detail) MMBbls in Millions	Dec. 31, 2021 USD ($) MMBbls	Dec. 31, 2020 USD ($) MMBbls
Commodity Crude Oil Hedge Contracts
Derivative [Line Items]
Commodity - crude oil (millions of barrels) \| MMBbls	54.8	27.4
Foreign Exchange Forwards
Derivative [Line Items]
Outstanding gross notional amount \| $	$ 145,000,000	$ 163,000,000

Financial Risk Management Activities - Gross & Net Fair Values of Financial Risk Management Derivative Instruments (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	$ 157	$ 69
Liabilities - Gross fair value of derivative contracts	(1)	(55)
Gross amount offset in the Consolidate Balance Sheet, Assets	0	(13)
Gross amount offset in the Consolidate Balance Sheet, Liabilities	0	13
Derivative Asset	157	56
Derivative Liability	(1)	(42)
Derivative Contracts Designated as Hedging Instruments:
Derivatives, Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	157	69
Liabilities - Gross fair value of derivative contracts	0	(54)
Derivative Contracts Designated as Hedging Instruments: \| Commodity Options / Collars
Derivatives, Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	155	64
Liabilities - Gross fair value of derivative contracts	0	0
Derivative Contracts Designated as Hedging Instruments: \| Crude Oil Swaps
Derivatives, Fair Value [Line Items]
Assets - Gross fair value of derivative contracts		0
Liabilities - Gross fair value of derivative contracts		(54)
Derivative Contracts Designated as Hedging Instruments: \| Interest Rate Swaps
Derivatives, Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	2	5
Liabilities - Gross fair value of derivative contracts	0	0
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	(1)	(1)
Derivative Contracts Not Designated as Hedging Instruments: \| Foreign Exchange Forwards
Derivatives, Fair Value [Line Items]
Assets - Gross fair value of derivative contracts	0	0
Liabilities - Gross fair value of derivative contracts	$ (1)	$ (1)

Financial Risk Management Activities - Additional Information (Details) - Commodity Options / Collars bbl / d in Thousands, MMBbls in Millions	Dec. 31, 2021 MMBbls bbl / d $ / bbl	Dec. 31, 2020 MMBbls
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount of crude oil \| MMBbls	54.8	27.4
West Texas Intermediate
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount of crude oil \| bbl / d	90
Average monthly floor price (US dollar per barrel)	60
Average monthly ceiling price (US dollar per barrel)	100
Brent
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount of crude oil \| bbl / d	60
Average monthly floor price (US dollar per barrel)	65
Average monthly ceiling price (US dollar per barrel)	105

Financial Risk Management Activities - Derivative Contracts - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Interest Rate Swaps \| Designated as Fair Value Hedges
Derivative Instruments, Gain (Loss) [Line Items]
Outstanding gross notional amount	$ 100,000,000	$ 100,000,000
Foreign Exchange Forwards
Derivative Instruments, Gain (Loss) [Line Items]
Outstanding gross notional amount	145,000,000	163,000,000
Derivative Contracts Designated as Hedging Instruments: \| Commodity Crude Oil Hedge Contracts \| Designated as Cash Flow Hedges
Derivative Instruments, Gain (Loss) [Line Items]
Increase (decrease) in sales and other operating revenues due to hedging instruments	(243,000,000)	547,000,000	$ 1,000,000
Pre-tax deferred income (losses) in Accumulated other comprehensive income (loss) to be reclassified into earnings within the next twelve months	68,000,000
Deferred income (losses) in Accumulated other comprehensive income (loss), net of tax to be reclassified into earnings within the next twelve months	68,000,000
Derivative Contracts Designated as Hedging Instruments: \| Interest Rate Swaps \| Designated as Fair Value Hedges
Derivative Instruments, Gain (Loss) [Line Items]
Outstanding gross notional amount	100,000,000	100,000,000
Unrealized change in fair value of interest rate swaps - increase (decrease)	(3,000,000)	4,000,000	3,000,000
Derivative Contracts Not Designated as Hedging Instruments: \| Foreign Exchange Forwards
Derivative Instruments, Gain (Loss) [Line Items]
Foreign exchange gains (losses) reported in Other, net in the Statement of Consolidated Income	(2,000,000)	(6,000,000)	3,000,000
Net gains (losses) on foreign exchange contracts not designated as hedging instruments	$ 1,000,000	$ 2,000,000	$ (2,000,000)

Financial Risk Management Activities - Credit Risk - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Letters of credit - outstanding amount	$ 259	$ 269
Integrated Companies
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Concentration percentage of accounts receivable	50.00%
Independent E&P Companies
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Concentration percentage of accounts receivable	31.00%
Refining & Marketing Companies
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Concentration percentage of accounts receivable	3.00%
National Oil Companies
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Concentration percentage of accounts receivable	9.00%
Storage & Transportation Companies
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Concentration percentage of accounts receivable	3.00%
Others
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Concentration percentage of accounts receivable	4.00%

Financial Risk Management Activities - Fair Value Measurement - Additional Information (Detail) $ in Millions	Dec. 31, 2021 USD ($)
Fair Value Disclosures [Abstract]
Carrying value of total long-term debt	$ 8,458
Fair value of total long-term debt	$ 9,897

- Definition

Amount, after unamortized (discount) premium and debt issuance costs, of long-term debt. Includes, but not limited to, notes payable, bonds payable, debentures, mortgage loans and commercial paper. Excludes capital lease obligations.

+ References + Details

Subsequent Events (Details) - USD ($) $ in Millions	1 Months Ended
Subsequent Events (Details) - USD ($) $ in Millions	Feb. 28, 2022	Jan. 31, 2022	Jun. 30, 2021
Subsequent Event [Line Items]
Term loan facility			$ 1,000
Subsequent Event
Subsequent Event [Line Items]
Repayment of remaining principal amount of term loan	$ 500
Percentage Increase in Dividends	5000.00%
Subsequent Event \| Libya
Subsequent Event [Line Items]
Income taxes paid		$ 470

Retirement Plans - Fair Value of Financial Assets of Funded Pension Plans (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	$ 3,357	$ 3,043
Cash and Short-term Investment Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	19	44
U.S. Equities (domestic)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	688	749
International Equities (non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	504	489
Global Equities (domestic and non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	231	225
Treasury and Government Related - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	402	399
Mortgage-backed Securities - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	191	186
Corporate - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	635	443
Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	81	73
Private Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	382	251
Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	224	184
Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	850	746
Level 1 \| Cash and Short-term Investment Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	19	44
Level 1 \| U.S. Equities (domestic)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	601	585
Level 1 \| International Equities (non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	73	94
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	128	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	29	23
Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	1,004	898
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	56	43
Level 2 \| Global Equities (domestic and non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	7	8
Level 2 \| Treasury and Government Related - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	361	350
Level 2 \| Mortgage-backed Securities - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	128	116
Level 2 \| Corporate - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	452	381
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	1,503	1,399
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	87	164
Net Asset Value \| International Equities (non-U.S.)
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	375	352
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	224	217
Net Asset Value \| Treasury and Government Related - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	41	49
Net Asset Value \| Mortgage-backed Securities - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	63	70
Net Asset Value \| Corporate - Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	55	62
Net Asset Value \| Hedge Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	81	73
Net Asset Value \| Private Equity Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	382	251
Net Asset Value \| Real Estate Funds
Defined Benefit Plan Disclosure [Line Items]
Fair value of financial assets of funded pension plans	$ 195	$ 161