EDGAR 10-K Filing

Company CIK: 4447
Filing Year: 2025
Filename: 4447_10-K_2025_0001628280-25-008716.json

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ITEM 1. BUSINESS
Items 1 and 2. Business and Properties
Hess Corporation, incorporated in the State of Delaware in 1920, is a global E&P company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA) and Malaysia. We conduct exploration activities primarily offshore Guyana, in the U.S. Gulf of America, and offshore Suriname. At the Stabroek Block (Hess 30%), offshore Guyana, we and our partners have discovered a significant resource base and are executing a multi-phased development of the block. We currently have three FPSOs producing, and plan to have eight FPSOs producing by the end of 2030 with an aggregate expected production capacity of approximately 1.7 million gross bopd. The discovered resources to date on the block are expected to underpin the potential for up to ten FPSOs.
Our Midstream operating segment, which is comprised of Hess Corporation’s approximate 38% consolidated ownership interest in Hess Midstream LP at December 31, 2024, provides fee-based services, including gathering, compressing and processing natural gas and fractionating NGL; gathering, terminaling, loading and transporting crude oil and NGL; storing and terminaling propane, and water handling services primarily in the Bakken shale play in the Williston Basin area of North Dakota. See Midstream on page 13.
On October 22, 2023, we entered into an Agreement and Plan of Merger (the Merger Agreement) with Chevron Corporation (Chevron) and Yankee Merger Sub Inc. (Merger Subsidiary), a direct, wholly-owned subsidiary of Chevron. The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, Merger Subsidiary will be merged with and into Hess, and Hess will be the surviving corporation in the Merger as a direct, wholly-owned subsidiary of Chevron (such transaction, the Merger). Under the terms of the Merger Agreement, if the Merger is completed, our stockholders will receive at the effective time of the Merger consideration consisting of 1.025 shares of Chevron common stock for each share of our common stock. On May 28, 2024, holders of a majority of Hess’ outstanding common stock voted to approve the Merger. Hess Guyana Exploration Limited (HGEL), a wholly-owned subsidiary of Hess, is currently in arbitration relating to the applicability of a right of first refusal (the Stabroek ROFR) contained in the operating agreement (the Stabroek JOA) among HGEL and affiliates of Exxon Mobil Corporation (Exxon Mobil) and China National Offshore Oil Corporation (CNOOC). The arbitration merits hearing about the applicability of the Stabroek ROFR to the Merger has been scheduled for May 2025, with a decision expected in the third quarter. We cannot predict the date on which the Merger will be completed because it is subject to conditions beyond our control, including the outcome of the arbitration. See Item 1A. Risk Factors for a discussion of risks related to the Merger.
Exploration and Production
Proved Reserves
Proved reserves are calculated using the average price during the twelve-month period ending December 31 determined as an unweighted arithmetic average of the price on the first day of each month within the year, unless prices are defined by contractual agreements, and exclude escalations based on future conditions. Crude oil prices used in the determination of proved reserves at December 31, 2024 were $74.88 per barrel for West Texas Intermediate (WTI) (2023: $78.10) and $78.81 per barrel for Brent (2023: $82.51). Our total proved developed and undeveloped reserves at December 31 were as follows:
Crude Oil & Condensate Natural Gas Liquids Natural Gas Total
2024 2023 2024 2023 2024 2023 2024 2023
(Millions of bbls) (Millions of bbls) (Millions of mcf) (Millions of boe)
Developed
United States 258 265 191 173 727 656 570 547
Guyana 209 201 - - 88 71 224 213
Malaysia and JDA 2 3 - - 208 288 37 51
469 469 191 173 1,023 1,015 831 811
Undeveloped
United States 194 204 101 89 379 336 358 349
Guyana 228 186 - - 119 114 248 205
Malaysia and JDA - - - - 7 27 1 5
422 390 101 89 505 477 607 559
Total
United States 452 469 292 262 1,106 992 928 896
Guyana 437 387 - - 207 185 472 418
Malaysia and JDA 2 3 - - 215 315 38 56
891 859 292 262 1,528 1,492 1,438 1,370
Proved undeveloped reserves were 42% of our total proved reserves at December 31, 2024 on a boe basis (2023: 41%). Proved reserves held under PSCs totaled 49% of our crude oil reserves and 28% of our natural gas reserves at December 31, 2024 (2023: 45% and 34%, respectively).
For additional information regarding our proved oil and gas reserves, see the Supplementary Oil and Gas Data to the Consolidated Financial Statements presented on pages 93 through 102.
Production
Worldwide crude oil, NGL, and natural gas net production was as follows:
2024 2023 2022
Crude oil - Thousands of barrels
United States
North Dakota 33,414 30,271 27,238
Offshore 8,236 8,111 7,995
Total United States 41,650 38,382 35,233
Guyana 68,136 41,831 28,526
Malaysia and JDA 1,733 1,728 1,393
Other (a) - - 5,524
Total 111,519 81,941 70,676
Natural gas liquids - Thousands of barrels
United States
North Dakota 27,089 24,634 19,488
Offshore 909 550 681
Total United States 27,998 25,184 20,169
Natural gas - Thousands of mcf
United States
North Dakota 84,757 69,781 56,903
Offshore 12,922 15,565 16,024
Total United States 97,679 85,346 72,927
Malaysia and JDA 121,594 134,404 131,509
Other (a) - - 3,565
Total 219,273 219,750 208,001
Total Barrels of Oil Equivalent (in millions) (a) 176.1 143.8 125.5
(a)Other includes our interests in Libya (sold in November 2022). Net production from Libya was 6.1 million boe for 2022.
E&P Operations
At December 31, 2024, our significant E&P assets included the following:
United States
Our production in the U.S. was from the Bakken shale play in the Williston Basin of North Dakota (Bakken) and from offshore properties in the Gulf of America.
North Dakota:
Bakken: At December 31, 2024, we held approximately 463,000 net acres in the Bakken. Net production averaged 204,000 boepd in 2024. During 2024 we operated four rigs and drilled 136 wells and brought 131 new wells online, bringing the total operated production wells to 1,864 at December 31, 2024. During 2025, we plan to continue operating four drilling rigs.
Offshore:
Gulf of America: At December 31, 2024, we held approximately 46,000 net developed acres, with our production operations principally at the Baldpate (Hess 50%), Conger (Hess 38%), Llano (Hess 50%), Penn State (Hess 50%), Stampede (Hess 25%) and Tubular Bells (Hess 57%) Fields. At December 31, 2024, we held approximately 304,000 net undeveloped acres, of which leases covering approximately 75,000 net acres are due to expire in the next three years. In March 2024, we were awarded 20 leases in the U.S. Department of Interior’s Lease Sale 261. The Pickerel-1 oil discovery (Hess 100%) located in Mississippi Canyon Block 727 achieved first production in June 2024 as a tieback to the Tubular Bells production facilities. In late December 2024, we completed drilling at the Vancouver-1 exploration well (Hess 40%) located in Green Canyon Block 287 which did not encounter commercial
quantities of hydrocarbons. In the second quarter of 2025, we plan to bring online the Hess operated Black Pearl development well (Hess 25%) as a tieback to the Stampede production facilities. In 2025, we also plan to participate in three wells.
Guyana
Stabroek Block: The Stabroek Block (Hess 30%), offshore Guyana, covers approximately 6.6 million acres. The operator, ExxonMobil Guyana Ltd, has made more than 30 discoveries since 2015, with the discovered resources to date on the block expected to underpin the potential for up to ten FPSOs. We currently have three FPSOs producing, and plan to have eight FPSOs producing by the end of 2030 with an aggregate expected production capacity of approximately 1.7 million gross bopd.
The Liza Phase 1 development began producing oil in December 2019 utilizing the Liza Destiny FPSO, the Liza Phase 2 development began producing oil in February 2022 from the Liza Unity FPSO, and the third development, Payara, began producing oil in November 2023 from the Prosperity FPSO. Net production from Guyana averaged 186,000 bopd in 2024.
A fourth development, Yellowtail, was sanctioned in April 2022 and will utilize the ONE GUYANA FPSO with a production capacity of approximately 250,000 gross bopd, with first production expected in the fourth quarter of 2025. Six drill centers are planned with up to 26 production wells and 25 injection wells.
A fifth development, Uaru, was sanctioned in April 2023 and will utilize the Errea Wittu FPSO with a production capacity of approximately 250,000 gross bopd, with first production expected in 2026. Ten drill centers are planned with up to 21 production wells and 23 injection wells.
A sixth development, Whiptail, was sanctioned in April 2024 and will utilize the Jaguar FPSO with a production capacity of approximately 250,000 gross bopd, with first production expected in 2027. Ten drill centers are planned with up to 24 production wells and 24 injection wells.
The application for the environmental permit for the seventh development, Hammerhead, has been filed with Guyana’s Environmental Protection Agency. Pending government and regulatory approval and project sanctioning, the development is expected to have a production capacity of approximately 150,000 gross bopd, with first production anticipated in 2029.
In 2024, ExxonMobil Guyana Ltd. completed construction of a 130-mile pipeline in order to transport approximately 50 million standard cubic feet of natural gas per day from the Liza Field to a 300 megawatt onshore power plant (Gas to Energy Project), which will be constructed and operated by the Government of Guyana.
In 2024, the operator drilled a total of eight successful exploration and appraisal wells that encountered hydrocarbons and one unsuccessful exploration well for which the well costs were expensed. In 2025, the operator plans to utilize five drillships to continue to perform exploration, appraisal, and development activities.
Malaysia and JDA
Malaysia/Thailand Joint Development Area (JDA): Production comes from the Carigali Hess operated Block A-18 in the Malaysia/Thailand joint development area in the Gulf of Thailand (Hess 50%). In June 2024, the regulator provided notification that the current PSC for JDA Block A-18 will not be re-awarded to the existing PSC contractors upon its expiration in 2029. As a result, we recognized an after-tax charge of $52 million to expense capitalized well costs and material and supplies inventory. In 2025, the operator plans to drill two development wells.
Malaysia: Our production in Malaysia comes from our operated interests in Block PM302 (Hess 50%) and Block PM325 (Hess 50%) located in the North Malay Basin (NMB), offshore Peninsular Malaysia and Block PM301 (Hess 50%), which is adjacent to and is unitized with Block A-18 of the JDA. In 2025, we plan to continue development activities at NMB.
Other
Suriname: In offshore Suriname, we hold a 33% non-operated participating interest in Block 42 and a 100% participating interest in Block 59, where we assumed operatorship in 2024. Exploration and appraisal activities are ongoing.
Sales Commitments
We have certain long-term contracts with fixed minimum sales volume commitments for natural gas and NGL production. At the JDA in the Gulf of Thailand, we have annual minimum net sales commitments of approximately 70 billion cubic feet of natural gas per year in 2025 and approximately 30 billion cubic feet per year in 2026 and 2027. At the North Malay Basin development project, offshore Peninsular Malaysia, we have annual minimum net sales commitments of approximately 50 billion cubic feet of natural gas per year in 2025, approximately 40 billion cubic feet per year in 2026 and 2027, approximately 30 billion cubic feet per year in 2028 and approximately 15 billion cubic feet per year from 2029 through 2033. At the Liza Phase 1 and Phase 2 development projects at the Stabroek Block, offshore Guyana, we have annual minimum net sales commitments of approximately 2.6 billion cubic feet of natural gas per year following the commissioning period of the Gas to Energy Project. The estimated total volume of natural gas
subject to these sales commitments is approximately 420 billion cubic feet. We also have multiple minimum delivery commitments in the Bakken for natural gas and NGL with various end dates through 2037, with total commitments of approximately 115 million boe over the remaining life of the contracts.
We have not experienced any significant constraints in satisfying the committed quantities required by our sales commitments, and we anticipate being able to meet future requirements from available proved and probable reserves, as well as projected third-party supply in the case of NGL.
Selling Prices and Production Costs
The following table presents our average selling prices and average production costs:
2024 2023 2022
Average Selling Prices (a)
Crude Oil - Per Barrel (Including Hedging)
United States
North Dakota $ 72.11 $ 70.44 $ 81.06
Offshore 75.07 72.06 81.38
Total United States 72.70 70.80 81.14
Guyana 80.04 80.72 89.86
Malaysia and JDA 77.76 75.51 89.77
Other (b) - - 93.67
Worldwide 77.28 75.97 85.76
Crude Oil - Per Barrel (Excluding Hedging)
United States
North Dakota $ 72.11 $ 73.80 $ 91.26
Offshore 75.07 75.39 91.51
Total United States 72.70 74.15 91.32
Guyana 80.04 82.20 96.52
Malaysia and JDA 77.76 75.51 89.77
Other (b) - - 101.92
Worldwide 77.28 78.29 94.15
Natural Gas Liquids - Per Barrel
United States
North Dakota $ 21.75 $ 20.77 $ 35.09
Offshore 21.73 20.87 35.24
Worldwide 21.75 20.77 35.09
Natural Gas - Per Mcf
United States
North Dakota $ 1.17 $ 1.68 $ 5.50
Offshore 1.78 2.16 6.21
Total United States 1.25 1.76 5.66
Malaysia and JDA 6.57 5.95 5.62
Other (b) - - 5.93
Worldwide 4.20 4.32 5.64
Average production (lifting) costs per barrel of oil equivalent produced (c)
United States
North Dakota (d) $ 26.72 $ 27.16 $ 29.02
Offshore 25.88 26.98 22.19
Total United States 27.11 27.61 28.16
Guyana (e) 6.73 9.60 11.23
Malaysia and JDA 9.91 7.33 6.12
Other (b) - - 2.78
Worldwide 17.08 18.96 18.97
(a)Selling prices in the United States and Guyana are adjusted for certain processing and distribution fees included in Marketing expenses.
(b)Other includes our interests in Libya (sold in November 2022).
(c)Production (lifting) costs consist of amounts incurred to operate and maintain our producing oil and gas wells, related equipment and facilities and transportation costs, including Midstream tariff expense. Lifting costs do not include costs of finding and developing proved oil and gas reserves, production and severance taxes, or the costs of related general and administrative expenses, interest expense and income taxes.
(d)Includes Midstream tariff expense of $18.44 per boe in 2024 (2023: $18.73 per boe; 2022: $21.21 per boe).
(e)Includes pre-development costs from the operator for future phases of development and Hess internal costs totaling $1.13 per boe in 2024 (2023: $1.87 per boe; 2022: $2.76 per boe).
Gross and Net Undeveloped Acreage
At December 31, 2024, gross and net undeveloped acreage amounted to:
Undeveloped
Acreage (a)
Gross Net
(In thousands)
United States 396 305
Guyana (b) 6,459 1,938
Malaysia and JDA 243 122
Suriname 4,363 3,346
Total (c) 11,461 5,711
(a)Includes acreage held under PSCs.
(b)Includes acreage at the Stabroek Block relating to the end of the first renewal period of the exploration license in October 2024, which requires the relinquishment of 20% of the acreage not held by discoveries, which is pending approval by the Government of Guyana.
(c)At December 31, 2024, 94% of our net undeveloped acreage, primarily in Suriname and Guyana is scheduled to expire during the next three years pending results of exploration activities.
Gross and Net Developed Acreage, and Productive Wells
At December 31, 2024 gross and net developed acreage and productive wells amounted to:
Developed Acreage Applicable to Productive Wells Productive Wells (a)
Oil Gas
Gross Net Gross Net Gross Net
(In thousands)
United States 790 509 3,468 1,684 9 4
Guyana 164 49 40 12 - -
Malaysia and JDA 481 241 - - 147 72
Total 1,435 799 3,508 1,696 156 76
(a)Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 30 gross wells and 27 net wells.
Exploratory and Development Wells
Net exploratory and net development wells completed during the years ended December 31 were:
Net Exploratory Wells Net Development Wells
2024 2023 2022 2024 2023 2022
Productive wells
United States - 1 - 117 105 70
Guyana 2 1 3 4 5 2
Malaysia and JDA - - 1 4 8 6
2 2 4 125 118 78
Dry holes
Guyana (a) - 1 - - - -
Canada (b) - - - - - -
- 1 - - - -
Total 2 3 4 125 118 78
(a)Includes the Trumpetfish-1 well in 2024, Fish/Tarpon-1 and Kokwari-1 wells in 2023, and the Banjo-1 well in 2022 at the Stabroek Block.
(b)Includes the Ephesus well offshore Newfoundland in 2023.
Number of Wells in the Process of Being Drilled
At December 31, 2024, the number of wells in the process of drilling amounted to:
Gross
Wells Net
Wells
United States 155 52
Guyana (a) 31 9
Total 186 61
(a)Includes 22 gross (and 7 net) water injection and gas injection wells in process at December 31, 2024.
Midstream
Prior to December 16, 2019, the Midstream segment was primarily comprised of Hess Infrastructure Partners LP (HIP), a 50/50 joint venture between Hess Corporation and Global Infrastructure Partners (GIP), formed to own, operate, develop and acquire a diverse set of midstream assets to provide fee-based services to Hess and third-party customers. HIP was initially formed on May 21, 2015, with Hess selling 50% of HIP to GIP for approximately $2.6 billion on July 1, 2015.
On April 10, 2017, HIP completed an initial public offering (IPO) of 16,997,000 common units, representing 30.5% limited partnership interests in its subsidiary Hess Midstream Partners LP, 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 Corporation and GIP each received common and subordinated units representing a direct 33.75% limited partner interest in Hess Midstream Partners LP and a 50% indirect ownership interest through HIP in Hess Midstream Partners LP’s general partner, which had a 2% economic interest in Hess Midstream Partners LP plus incentive distribution rights.
On December 16, 2019, Hess Midstream Partners LP acquired HIP, including HIP’s 80% interest in Hess Midstream Partners LP’s 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 LP’s organizational structure converted from a master limited partnership into an “Up-C” structure in which Hess Midstream Partners LP’s public unitholders received newly issued Class A shares in a new public entity named Hess Midstream LP, which is taxed as a corporation for U.S. federal and state income tax purposes. Hess Midstream Partners LP changed its name to “Hess Midstream Operations LP” (HESM Opco) and became a consolidated subsidiary of Hess Midstream LP, the new publicly listed entity. As consideration for the acquisition, Hess Corporation 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 LP owned 6% of the consolidated entity on an as-exchanged basis and Hess Corporation 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 LP on a one-for-one basis.
In 2022, Hess Midstream LP completed a single underwritten public equity offering of 10.2 million Hess Midstream LP Class A shares held by affiliates of Hess Corporation and GIP. The Class A shares of Hess Midstream LP were obtained by Hess Corporation and GIP through the exchange of 10.2 million of their Class B units of HESM Opco. In 2022, HESM Opco repurchased 13.6 million HESM Opco Class B units held by affiliates of Hess Corporation and GIP for $400 million in a single transaction. HESM Opco issued $400 million in aggregate principal amount of 5.500% fixed-rate senior unsecured notes due 2030 in a private offering to repay borrowings under its revolving credit facility used to finance the repurchase.
In 2023, Hess Midstream LP completed two underwritten public equity offerings of an aggregate of 24.3 million Hess Midstream LP Class A shares held by affiliates of Hess Corporation and GIP. The Class A shares of Hess Midstream LP were obtained by Hess Corporation and GIP through the exchange of 24.3 million of their Class B units of HESM Opco. In 2023, HESM Opco repurchased an aggregate of 13.6 million HESM Opco Class B units in four transactions from affiliates of Hess Corporation and GIP for total proceeds of $400 million. The unit repurchases were financed by borrowings under HESM Opco’s revolving credit facility.
In 2024, Hess Midstream LP completed three underwritten public equity offerings of an aggregate of 35.7 million Hess Midstream LP Class A shares held by an affiliate of GIP. The Class A shares of Hess Midstream LP were obtained by GIP through the exchange of 35.7 million of its Class B units of HESM Opco. Hess Corporation did not receive any proceeds from the public equity offerings. In 2024, HESM Opco repurchased an aggregate of 8.4 million HESM Opco Class B units in three transactions from affiliates of Hess Corporation and GIP for total proceeds of $300 million. The unit repurchases were financed by borrowings under HESM Opco’s revolving credit facility and cash on hand.
After giving effect to the above transactions, public shareholders of Class A shares of Hess Midstream LP owned approximately 47%, GIP owned approximately 15%, and Hess Corporation owned approximately 38% of the consolidated entity on an as-exchanged basis at December 31, 2024.
At December 31, 2024, Midstream assets included the following:
•Natural Gas Gathering and Compression: A natural gas gathering and compression system located primarily in McKenzie, Williams and Mountrail Counties, North Dakota connecting Hess and third-party owned or operated wells to the Tioga Gas Plant, LM4, and third-party pipeline facilities. This gathering system consists of approximately 1,415 miles of high and low pressure natural gas and NGL gathering pipelines with a current capacity of up to approximately 675 mmcfd. The system has an aggregate compression capacity of approximately 530 mmcfd including approximately 50 mmcfd of net compression capacity added in 2024.
•Crude Oil Gathering: A crude oil gathering system located primarily in McKenzie, Williams and Mountrail Counties, North Dakota, connecting Hess and third-party owned or operated wells to the Ramberg Terminal Facility, the Tioga Rail Terminal and the Johnson’s Corner Header System. The crude oil gathering system consists of approximately 590 miles of crude oil gathering pipelines with a current capacity of up to approximately 290,000 bopd.
•Produced Water Gathering and Disposal: A produced water gathering system located primarily in Williams and Mountrail Counties, North Dakota, that transports produced water from the well site by approximately 330 miles of pipeline in gathering systems or by third-party trucking to water handling facilities for disposal.
•Tioga Gas Plant: A natural gas processing and fractionation plant located in Tioga, North Dakota, with a current total processing capacity of approximately 400 mmcfd, an NGL fractionation capacity of approximately 60,000 boepd and y-grade NGL stabilization capacity of approximately 25,000 boepd.
•LM4: A natural gas processing plant in McKenzie County, North Dakota, with processing capacity of approximately 200 mmcfd, which was placed in service during 2019 and is operated by Targa Resources Corp. Hess Midstream LP owns a 50% interest in LM4 through a joint venture with Targa Resources Corp. and is entitled to half of the plant’s processing capacity.
•Mentor Storage Terminal: A propane storage cavern and rail and truck loading and unloading facility located in Mentor, Minnesota, with approximately 330,000 boe of working storage capacity.
•Ramberg Terminal Facility: A crude oil pipeline and truck receipt terminal located in Williams County, North Dakota with a delivery capacity of up to approximately 285,000 bopd of crude oil into an interconnecting pipeline for transportation to the Tioga Rail Terminal, Dakota Access Pipeline (DAPL) and other third-party pipelines and storage facilities.
•Tioga Rail Terminal: A 140,000 bopd crude oil and 30,000 boepd NGL rail loading terminal in Tioga, North Dakota that is connected to the Tioga Gas Plant, the Ramberg Terminal Facility and our crude oil gathering system.
•Crude Oil Rail Cars: A total of 550 crude oil rail cars, which are operated as unit trains consisting of approximately 100 to 110 crude oil rail cars. These crude oil rail cars have been constructed to DOT-117 standards.
•Johnson’s Corner Header System: A crude oil pipeline header system located in McKenzie County, North Dakota that receives crude oil by pipeline from Hess and third parties and delivers crude oil to DAPL and other third-party interstate pipeline systems. The facility has a delivery capacity of approximately 100,000 bopd of crude oil.
•Other DAPL Connections: Various connections into DAPL, which are crude oil delivery points within the terminal system located in Williams and Mountrail Counties, North Dakota that receive crude oil by pipeline from the crude oil gathering system for delivery into DAPL. The facility has a delivery capacity of approximately 120,000 bopd of crude oil.
The Midstream segment earns substantially all of its revenues by charging fees for gathering, compressing and processing natural gas and fractionating NGLs; gathering, terminaling, loading and transporting crude oil and NGLs; storing and terminaling propane; and gathering and disposing produced water. Effective January 1, 2014, certain subsidiaries of Hess Midstream LP entered into (i) gas gathering, (ii) crude oil gathering, (iii) gas processing and fractionation, (iv) storage services and (v) terminaling and export services commercial agreements with certain subsidiaries of Hess Corporation, each generally with an initial ten-year term which could be extended for an additional ten-year term at the unilateral right of the Hess Midstream LP subsidiaries. The Hess Midstream LP subsidiaries exercised their right to extend the terms of each of these commercial agreements for the secondary term effective January 1, 2024 through December 31, 2033. Effective January 1, 2019, a subsidiary of Hess Midstream LP entered into water gathering and disposal services agreements with a subsidiary of Hess Corporation. These agreements also provide Hess Midstream LP the capacity to provide concurrent use of these services directly to third parties.
The commercial agreements contain minimum volume commitments which are based on nominations covering substantially all of the E&P segment’s existing and future owned or controlled production in the Bakken and projected third-party volumes owned or controlled by the E&P segment through dedicated third-party contracts. Minimum volume commitments are equal to 80% of the nominations and apply on a three-year rolling basis such that they are set for the three years following the most recent nomination. During the initial term of each commercial agreement, volume deficiencies are measured quarterly and any associated shortfall payments are not subject to future reduction or offset. During the secondary term of each commercial agreement, the applicable Hess Corporation subsidiary will be entitled to receive a credit with respect to the amount of any shortfall fee paid. Such Hess Corporation subsidiary may apply the credit against the fees payable for any volumes delivered under the applicable agreement in excess of the nominated volumes up to four quarters after the credit is earned. No credits will be provided with respect to crude oil terminaling
services under the terminaling and export services commercial agreement or water handling services under the water gathering and disposal services agreements.
Competition and Market Conditions
See Item 1A. Risk Factors for a discussion of competition and market conditions.
Emergency Preparedness and Response Plans and Procedures
We have in place a series of business and asset-specific emergency preparedness, response and business continuity plans that detail procedures for rapid and effective emergency response and environmental mitigation activities. These plans are maintained, reviewed and updated as necessary to confirm their accuracy and suitability. Where applicable, they are also reviewed and approved by the relevant host government authorities.
Responder training and drills are routinely held worldwide to assess and continually improve the effectiveness of our plans. Our contractors, service providers, representatives from government agencies and, where applicable, joint venture partners participate in the drills to help ensure that emergency procedures are comprehensive and can be effectively implemented.
To complement internal capabilities and to help ensure coverage for our global operations, we maintain membership contracts with a network of local, regional and global oil spill response and emergency response organizations. At the regional and global level, these organizations include CGA, MSRC, MWCC, WWC and OSRL. CGA and MSRC are domestic spill response organizations and MWCC provides the equipment and personnel to contain underwater well control incidents in the Gulf of America. WWC provides firefighting, well control and engineering services globally. OSRL is a global response organization and is available, when needed, to assist us with any of our assets. In addition to owning response assets in their own right, the organization maintains business relationships that provide immediate access to additional critical response support services if required. OSRL’s response assets include nearly 300 recovery and storage vessels and barges, more than 250 skimmers, over 600,000 feet of boom, nine capping stacks and significant quantities of dispersants and other ancillary equipment, including aircraft. In addition to external well control and oil spill response support, we have contracts with wildlife, environmental, meteorology, incident management, medical and security resources. If we were to engage these organizations to obtain additional critical response support services, we would fund such services and, where appropriate, seek reimbursement under our insurance coverage, as described below. In certain circumstances, we pursue and enter into mutual aid agreements with other companies and government cooperatives to receive and provide oil spill response equipment and personnel support. We maintain close associations with emergency response organizations through our representation on the Executive Committee and Response Network Committee of MWCC, the Technical Operations Committee of CGA and the Emergency Preparedness and Response Committee of API. We also maintain regular voting membership in CGA, MSRC and OSRL.
We continue to participate in several industry-wide task forces that are studying better ways to assess the risk of and prevent onshore and offshore incidents, access and control blowouts in subsea environments, and improve containment and recovery methods. The task forces are working closely with the oil and gas industry and international government agencies to implement improvements and increase the effectiveness of oil spill prevention, preparedness, response and recovery processes.
Insurance Coverage and Indemnification
We maintain insurance coverage that includes coverage for physical damage to our property, third-party liability, workers’ compensation and employers’ liability, general liability, sudden and accidental pollution and other coverage. This insurance coverage is subject to deductibles, exclusions and limitations and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.
The amount of insurance covering physical damage to our property and liability related to negative environmental effects resulting from a sudden and accidental pollution event, excluding windstorm coverage for which we are self-insured, varies by asset, based on the asset’s estimated replacement value or the estimated maximum loss. In the case of a catastrophic event, first party coverage consists of two tiers of insurance. The first $450 million of coverage is provided through an industry mutual insurance group. Above this $450 million threshold, additional insurance is carried which ranges in value up to $800 million in total at December 31, 2024, depending on the asset coverage level, as described above. The insurance programs covering physical damage to our property exclude business interruption protection for our E&P operations. Additionally, we carry insurance that provides third-party coverage for general liability, and sudden and accidental pollution, up to $850 million, which coverage under a standard JOA would be reduced to our participating interest. Our insurance policies renew at various dates each year. Future insurance coverage could increase in cost and may include higher deductibles or retentions, or additional exclusions or limitations. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are deemed economically acceptable.
Generally, our drilling contracts (and most of our other offshore services contracts) provide for a mutual hold harmless indemnity structure whereby each party to the contract (the Corporation and contractor) indemnifies the other party for injuries or damages to their personnel and property (and, often, those of its contractors/subcontractors) regardless of fault. Variations may include indemnity
exclusions to the extent a claim is attributable to the gross negligence and/or willful misconduct of a party. Third-party claims, on the other hand, are generally allocated on a fault basis.
We are customarily responsible for, and indemnify the contractor against, all claims including those from third parties, to the extent attributable to pollution or contamination by substances originating from our reservoirs or other property and the contractor is responsible for and indemnifies us for all claims attributable to pollution emanating from the contractor’s property. Variations may include indemnity exclusions to the extent a claim is attributable to the gross negligence and/or willful misconduct of a party. Additionally, we are generally liable for all of our own losses and most third-party claims associated with catastrophic losses such as damage to reservoirs, blowouts, cratering and loss of hole, regardless of cause, although exceptions for losses attributable to gross negligence and/or willful misconduct do exist. Lastly, some offshore services contracts include overall limitations of the contractor’s liability equal to a fixed negotiated amount. Variations may include exclusions of all contractual indemnities from the liability cap.
Under a standard JOA, each party is liable for all claims arising under the JOA, to the extent of its participating interest (operator or non-operator). Variations include indemnity exclusions when the claim is based upon the gross negligence and/or willful misconduct of the operator, in which case the operator is solely liable. The parties to the JOA may continue to be jointly and severally liable for claims made by third parties in some jurisdictions. Further, under some PSCs between a governmental entity and commercial parties, liability of the commercial parties to the government entity is joint and several.
Government Regulations
The crude oil and natural gas industry is regulated at federal, state, local and foreign government levels. Regulations affecting elements of the energy sector are under continuous review for amendment or expansion over time, which may result in incremental costs of doing business and affect our profitability. See Regulatory, Legal and Environmental Risks in Item 1A. Risk Factors. Compliance with various existing environmental, health and safety regulations is not expected to have a material adverse effect on our financial condition or results of operations. However, increasingly stringent environmental regulations have resulted and will likely continue to result in higher capital expenditures and operating expenses for us and the oil and gas industry in general and may reduce demand for our products. We spent $17 million in 2024 (2023: $28 million; 2022: $23 million) for environmental remediation. Additionally, we may be exposed to decommissioning liabilities, including for divested assets. The level of other expenditures to comply with federal, state, local and foreign country regulations is difficult to quantify as such costs are captured as mostly indistinguishable components of our capital expenditures and operating expenses. For further discussion of environmental, health and safety regulations affecting our business, see Environment, Health and Safety in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Human Capital Management
Corporate Culture and Overview
Our human capital strategy aims to attract, engage and retain our talent by investing in their professional development and providing them with challenging and rewarding opportunities for personal growth. Our workplace culture is guided by our values and reinforced by developing quality leadership, fostering an inclusive environment where everyone can perform at their best, emphasizing continuous learning, creating opportunities for engagement, driving innovation and embracing Lean improvement processes. We utilize the Life at Hess framework to optimize the work experience for our multigenerational and demographically diverse workforce and unlock the discretionary effort that is required to perform at a high level on a sustained basis. The Life at Hess framework encompasses programs, policies and practices, and a listening system that draws on in-person dialogues, pulse polls and data analytics to help leaders understand employees’ experiences and perspectives to inform their decision making.
As of December 31, 2024, we had 1,797 employees globally, as detailed below.
United States Guyana Malaysia and JDA Total
Job Category
Executives and Senior Officers 30 - 1 31
First and Mid-Level Managers 369 - 67 436
Professionals 798 - 96 894
Other 388 - 48 436
Total 1,585 - 212 1,797
Life at Hess
We prioritize the safety of our workforce with programs and practices designed to help ensure that everyone, everywhere gets home safe every day. We continue to adapt our work policies and benefits to prioritize emotional, mental and physical health and well-being.
During 2024, we held several employee surveys throughout the year to understand employee sentiment and engagement in a time of change given the pending Merger. The following improvements were made in response to employee feedback:
•enhanced learning and development opportunities to better meet employee development goals and address evolving industry demands;
•promoted our wellness program supporting physical, financial, social and emotional well-being of our employees; and
•broadened leadership training and development program to help leaders navigate an increasingly dynamic, diverse, and complex work environment.
In keeping with our values and purpose, we have a longstanding commitment to fostering a sustainable culture of inclusion and respect for everyone. We believe that being inclusive and promoting diverse perspectives is a business imperative for improved performance and the innovation needed to accomplish our business goals now and in the future. Additionally, Hess is committed to providing a global workplace free from discrimination and harassment, where everyone can achieve their full potential. We provide equal employment opportunities for all employees and job candidates regardless of race, color, religion, gender, age, sexual orientation, gender identity, creed, national origin, genetic information, disability, veteran status or any other protected status.
Hess’ executive leadership provides guidance to embed inclusion into our culture and drive progress throughout the organization. Our expectations for a culture fostering mutual respect and trust are included in our Code of Business Conduct and Ethics and related policies. It is also reinforced regularly with employees at every level through regular communication, ongoing training and events. Additional information about our policies and practices, including training, employee engagement initiatives and workforce data, is included in our Key Sustainability Metrics and annual U.S. Equal Employment Opportunity reporting, which is available on our website at www.hess.com/sustainability.
During 2024, Hess continued to execute our inclusion strategy, cast a wide net for the best talent and either maintain or improve diversity across most levels of our workforce, as illustrated in the table below. We believe our strategic focus on these initiatives, including new training, mentoring, outreach and recruitment, and community partnerships, contributed to this outcome. Our six employee resource groups continued to grow and mature providing valuable employee insights to sustain an inclusive environment for everyone to perform at their best and partnering with diverse organizations in our communities to help them prosper. Hess inclusion efforts have also been recognized by numerous reputable third party organizations.
Each year, we share workforce data and trends such as demographics, employee turnover, promotions, compensation and development metrics, along with qualitative information such as program development and progress, with our Board of Directors. Management also reviews these topics in greater detail with the Compensation and Management Development Committee throughout the year.
Women
(U.S. and International) Minorities (a)
(U.S. Based Employees)
2024 2023 2022 2024 2023 2022
Job Category
Executives and Senior Officers 19 % 17 % 16 % 19 % 20 % 19 %
First and Mid-Level Managers 24 % 24 % 23 % 23 % 22 % 22 %
Professionals 33 % 33 % 33 % 32 % 32 % 31 %
Other 15 % 17 % 18 % 17 % 16 % 16 %
Total 26 % 27 % 27 % 26 % 26 % 25 %
(a)As defined by the U.S. Department of Labor.
Compensation and Benefits Programs
Our compensation and benefits programs are focused on attracting and retaining a highly skilled workforce in a rapidly changing industry. We benchmark these programs each year against other companies in our industry and conduct a review to help foster pay equity. The results are shared in our Key Sustainability Metrics on www.hess.com/sustainability. We maintain an annual incentive plan that applies to all employees, including executive officers, with shared enterprise performance metrics for all participants. We also provide a comprehensive, nationally recognized wellness program that is designed to improve the physical, financial, social and emotional well-being of our employees.
Information about our Executive Officers
The following table presents information as of February 27, 2025 regarding executive officers of the Corporation:
Name
Age Office Held* and Business Experience Year Individual Became an Executive Officer
John B. Hess 70 Chief Executive Officer and Director
Mr. Hess has been Chief Executive Officer of the Corporation since 1995 and employed by the Corporation since 1977. He has over 45 years of experience in the oil and gas industry.
Gregory P. Hill 63 President and Chief Operating Officer
Mr. Hill has been Chief Operating Officer since 2014 and President of the Corporation’s worldwide Exploration and Production business since joining the Corporation in January 2009. Prior to joining the Corporation, Mr. Hill spent 25 years at Royal Dutch Shell and its affiliates in a variety of operations, engineering, technical and managerial roles in Asia-Pacific, Europe and the United States.
Timothy B. Goodell 67 Executive Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer
Mr. Goodell has been General Counsel of the Corporation since 2009, Corporate Secretary since 2016, Chief Compliance Officer since 2017 and Executive Vice President since 2020. Prior to joining the Corporation in 2009, he was a partner at the law firm of White & Case, LLP where he spent 25 years.
John P. Rielly 62 Executive Vice President and Chief Financial Officer
Mr. Rielly has been Chief Financial Officer of the Corporation since 2004 and Executive Vice President since 2020. Mr. Rielly previously served as Vice President and Controller of the Corporation from 2001 to 2004. Prior to joining the Corporation in 2001, he was a Partner at Ernst & Young, LLP where he was employed for 17 years.
Richard Lynch 67 Senior Vice President, Technology and Services
Mr. Lynch has been Senior Vice President, Technology and Services of the Corporation since 2018. Mr. Lynch previously was Senior Vice President Global Developments, Drilling and Completions from 2014. Prior to joining the Corporation in 2014, Mr. Lynch spent over 30 years in well delivery and operations, as well as project and asset management, with BP plc and ARCO.
Gerbert Schoonman 59 Senior Vice President, Global Production
Mr. Schoonman has been Senior Vice President, Global Production of the Corporation since January 2020. Since joining the Company in 2011, he served in various operational leadership roles, including as Vice President, Production - Asia Pacific, from January 2011 through August 2012; Vice President, Onshore - Bakken from September 2012 through December 2016; and most recently, as Vice President, Offshore since January 2017. Prior to joining the Corporation, he spent 20 years with Royal Dutch Shell where he served in operational and leadership roles.
Andrew Slentz 63 Senior Vice President, Human Resources and Office Management
Mr. Slentz has been Senior Vice President, Human Resources of the Corporation since April 2016 and responsible for Office Management since 2018. Prior to joining the Corporation in 2016, Mr. Slentz served as Executive Vice President of Administration and Human Resources at Peabody Energy since 2010. Mr. Slentz has over 30 years in human resources experience at large international public companies.
Barbara Lowery-Yilmaz 68 Senior Vice President and Chief Exploration Officer
Ms. Lowery-Yilmaz has been the Senior Vice President, Exploration of the Corporation since 2014 and Chief Exploration Officer since 2020. Ms. Lowery-Yilmaz has over 30 years of oil and gas industry experience in exploration and technology with BP plc and its affiliates including senior leadership roles.
*All officers referred to herein hold office in accordance with our By-laws until the first meeting of directors in connection with the annual meeting of stockholders of the Corporation and until their successors shall have been duly chosen and qualified. Each of said officers was elected to the office opposite their name on May 15, 2024.
Each of the above officers has been employed by the Corporation or its affiliates in various managerial and executive capacities for more than five years.
Access to Our Reports
We make available free of charge through our website, www.hess.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission. The information on our website, including our sustainability reports, is not part of or otherwise incorporated by reference in this report. Our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and the charters for the Audit Committee, Compensation and Management Development Committee, Corporate Governance and Nominating Committee and Environmental, Health and Safety Committee of the Board of Directors are available on our website and are also available free of charge upon request to Investor Relations at our principal executive office. We also file with the New York Stock Exchange (NYSE) an annual certification by our Chief Executive Officer regarding our compliance with the NYSE’s corporate governance standards.

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
Our business activities and the value of our securities are subject to significant risks, including the risk factors described below. These risk factors could negatively affect our operations, financial condition, liquidity and results of operations, and as a result, holders and purchasers of our securities could lose part or all of their investments. It is possible that additional risks relating to our securities may be described in a prospectus supplement if we issue securities in the future.
Chevron Merger Risks
The Merger is subject to conditions, some or all of which may not be satisfied, or completed on a timely basis, if at all. Failure to complete the Merger in a timely manner or at all could have adverse effects on Hess. The completion of the Merger is subject to a number of conditions, including (i) the authorization for listing on the New York Stock Exchange of the shares of Chevron common stock to be issued in connection with the Merger, (ii) the absence of any order or law prohibiting consummation of the Merger, (iii) with respect to each party’s obligation to consummate the merger, the performance by the other party of its respective obligations under the Merger Agreement in all material respects, and the accuracy of such other party’s representations and warranties in the Merger Agreement (subject to certain materiality qualifiers) and (iv) with respect to Hess’ obligation to consummate the merger, the receipt by Hess of a tax opinion from legal counsel that the Merger will qualify as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code of 1986, as amended.
Additionally, HGEL is currently in arbitration with respect to the Stabroek ROFR. The arbitration merits hearing about the applicability of the Stabroek ROFR to the Merger has been scheduled for May 2025, with a decision expected in the third quarter. If the arbitration does not result in a confirmation that the Stabroek ROFR is inapplicable to the Merger, and if Chevron, Hess, Exxon Mobil and/or CNOOC do not otherwise agree upon an acceptable resolution, then there would be a failure of a closing condition under the Merger Agreement, in which case the Merger would not close.
Under the Merger Agreement, either Chevron or Hess may terminate the Merger Agreement if the Merger has not been completed by April 22, 2025 (or October 22, 2025, if the applicable end date is extended pursuant to the Merger Agreement) or by such later date as the parties may mutually agree. The parties have subsequently agreed that in the event there is ongoing arbitration relating to the Stabroek ROFR at any time when the end date would otherwise occur, the end date will be automatically extended until the earlier of (i) the third business day following the determination of such arbitration and (ii) October 22, 2025 (or such later date as the parties may mutually agree). However, this right to terminate the Merger Agreement will not be available to any party whose failure to perform any obligation under the Merger Agreement has principally caused or resulted in the failure of the Merger to be consummated on or before that date.
There can be no assurance that the conditions to the completion of the Merger will be satisfied or waived or that the Merger will be completed. The failure to satisfy all of the required conditions could delay the completion of the Merger for a significant period of time or prevent it from occurring at all. If the Merger is not completed, or if there are significant delays in completing the Merger, the trading prices of our common stock and our future business and financial results could be negatively affected, and we may be subject to several risks, including the following:
•negative reactions from the financial markets, including declines in the prices of our common stock due to the fact that current prices may reflect a market assumption that the Merger will be completed;
•having to pay certain significant costs relating to the Merger; and
•the attention of our management will have been diverted to the Merger rather than our own operations and pursuit of other opportunities that could have been beneficial to us.
We will be subject to business uncertainties while the Merger is pending, which could adversely affect our businesses. Uncertainty about the effect of the Merger on employees and those that do business with us may have an adverse effect on the Corporation. These uncertainties may impair our ability to attract, retain and motivate key personnel until the Merger is completed and for a period of time thereafter, and could cause those that transact with us to seek to change their existing business relationships with us. Employee retention at the Corporation may be challenging during the pendency of the Merger, as employees may experience uncertainty about their roles. In addition, the Merger Agreement restricts us from entering into certain corporate transactions, entering into certain material contracts, making certain changes to our capital budget, incurring certain indebtedness and taking other specified actions without the consent of Chevron, and generally requires us to continue our operations in the ordinary course of business during the pendency of the Merger. These restrictions may prevent us from pursuing attractive business opportunities or adjusting our capital plan prior to the completion of the Merger.
We have and may become subject to lawsuits relating to the Merger, which could adversely affect our business, financial condition and operating results. We and/or our respective directors and officers have and may become subject to lawsuits relating to the Merger. Such litigation is very common in connection with acquisitions of public companies, regardless of the merits of the underlying acquisition. While we will evaluate and defend against any actions vigorously, the costs of the defense of such lawsuits and other effects of such litigation could have an adverse effect on our business, financial condition and operating results.
The Merger Agreement restricts us from pursuing alternatives to the Merger. The Merger Agreement contains provisions that restrict us from soliciting or entering into discussions with any third party regarding any competing proposal or offer for a competing transaction.
Because the exchange ratio in the Merger Agreement is fixed and because the market price of Chevron common stock will fluctuate prior to the completion of the Merger, our stockholders cannot be sure of the market value of the Chevron common stock they will receive as consideration in the Merger. Under the terms of the Merger Agreement, if the Merger is completed, our stockholders will receive at the effective time of the Merger consideration consisting of 1.025 shares of Chevron common stock for each share of our common stock. The exchange ratio of the Merger consideration is fixed, and under the Merger Agreement there will be no adjustment to the Merger consideration for changes in the market price of Chevron common stock or our common stock prior to the completion of the Merger.
If the Merger is completed, there will be a time lapse between the date of signing of the Merger Agreement and the date on which our stockholders who are entitled to receive the Merger consideration actually receive the Merger consideration. The respective market values of Chevron common stock and our common stock have fluctuated and may continue to fluctuate during this period as a result of a variety of factors, including general market and economic conditions, changes in each company’s business, operations and prospects, commodity prices, regulatory considerations, and the market’s assessment of Chevron’s business and the Merger. Such factors are difficult to predict and in many cases may be beyond the control of Chevron and us. The actual value of the Merger consideration received by our stockholders at the completion of the Merger will depend on the market value of Chevron common stock at that time. This market value may differ, possibly materially, from the market value of Chevron common stock at the time the Merger Agreement was entered into or at any other time.
Shares of Chevron common stock received by our stockholders as a result of the Merger will have different rights from shares of our common stock. Upon completion of the Merger, our stockholders will no longer be stockholders of Hess, and our stockholders who receive the Merger consideration will become Chevron stockholders, and their rights as Chevron stockholders will be governed by the terms of Chevron’s charter and by-laws. There are differences between the current rights of our stockholders and the rights to which such stockholders will be entitled as Chevron stockholders.
Market and Third-Party Risks
Our business and operating results are highly dependent on the market prices of crude oil, NGL and natural gas, which can be very volatile. Our estimated proved reserves, revenue, operating cash flows, operating margins, liquidity, financial condition and future earnings are highly dependent on the benchmark market prices of crude oil, NGL and natural gas, and our associated realized price differentials, which are volatile and influenced by numerous factors beyond our control. The major foreign oil producing countries, including members of OPEC, may exert considerable influence over the supply and price of crude oil and refined petroleum products. Their ability to agree on a common policy on rates of production and other matters may have a significant impact on the oil markets. Other factors include, but are not limited to: worldwide and domestic supplies of and demand for crude oil, NGL and natural gas; political conditions and events (including weather, instability, changes in governments, armed conflict, economic sanctions and outbreaks of infectious diseases, such as COVID-19) around the world and in particular in crude oil or natural gas producing regions; the cost of exploring for, developing and producing crude oil, NGL and natural gas; the price, availability of and demand for alternative fuels or other forms of energy; the effect of energy conservation and environmental protection efforts; and overall geopolitical and economic conditions globally (including inflation, slower growth or recession, higher interest rates, tariffs and escalations of trade disputes, supply chain constraints, consequences associated with the ongoing invasion of Ukraine by Russia, or the conflict between Israel and Hamas). The sentiment of commodities trading markets as well as other supply and demand factors may also influence the selling prices of crude oil, NGL and natural gas. Average benchmark prices for 2024 were $75.76 per barrel for WTI (2023: $77.60; 2022: $94.33) and $79.86 per barrel for Brent (2023: $82.18; 2022: $99.04). In order to manage the potential volatility of cash flows and credit requirements, we maintain significant bank credit facilities. An inability to access, renew or replace such credit facilities or access other sources of funding as they mature would negatively impact our liquidity. Furthermore, from time to time we have entered into, and may in the future enter into or modify, commodity price hedging arrangements to manage commodity price volatility. These arrangements may limit potential upside from commodity price increases, or expose us to additional risks, such as counterparty credit risk, which could adversely impact our cash flow, liquidity or financial condition.
We do not always control decisions made under joint operating agreements and the parties under such agreements may fail to meet their obligations. We conduct many of our E&P operations through joint operating agreements with other parties under which we may not control decisions, either because we do not have a controlling interest or are not operator under the agreement. There is risk that these parties may at any time have economic, business, or legal interests or goals that are inconsistent with ours, and therefore decisions may be made which are not what we believe is in our best interest. Moreover, parties to these agreements may be unable to meet their economic or other obligations and we may be required to fulfill those obligations alone. As a result, actions of our contractual counterparties may adversely affect the value of our investments and result in increased costs or liabilities.
Our industry is highly competitive and many of our competitors are larger and have greater resources and more diverse portfolios than we have. The petroleum industry is highly competitive and very capital intensive. We encounter competition from numerous companies, including acquiring rights to explore for crude oil and natural gas. To a lesser extent, we are also in competition with producers of alternative fuels or other forms of energy, including wind, solar and electric power, and in the future, could face
increasing competition due to the development and adoption of new technologies. Many competitors, including national oil companies, are larger and have substantially greater resources to acquire and develop oil and gas assets, or may have established strategic relationships in areas we operate, or may be willing to incur a higher level of risk than we are willing to incur. In addition, competition for drilling services, technical expertise and equipment may affect the availability of technical personnel and drilling rigs, resulting in increased capital and operating costs. Many of our competitors have a more diverse portfolio of assets, which may minimize the impact of adverse events occurring at any one location.
Operational and Strategic Risks
If we fail to successfully increase our reserves, our future crude oil and natural gas production will be adversely impacted. We own or have access to a finite amount of oil and gas reserves, which will be depleted over time. Replacement of oil and gas production and reserves, including proved undeveloped reserves, is subject to successful exploration drilling, development activities, and enhanced recovery programs. Therefore, future oil and gas production is dependent on technical success in finding and developing additional hydrocarbon reserves. Exploration activity involves the interpretation of seismic and other geological and geophysical data, which does not always successfully predict the presence of commercial quantities of hydrocarbons. Drilling risks include unexpected adverse conditions, irregularities in pressure or formations, equipment failure, blowouts and weather interruptions. Future developments may be affected by unforeseen reservoir conditions, which negatively affect recovery factors or flow rates. Similar risks may be encountered in the production of oil and gas on properties acquired from others. In addition, replacing reserves and developing future production are also influenced by the price of crude oil and natural gas and costs of drilling and development activities. Lower crude oil and natural gas prices may reduce capital available for our exploration and development activities, render certain development projects uneconomic or delay their completion, and result in negative revisions to existing reserves while increasing drilling and development costs could negatively affect expected economic returns.
There are inherent uncertainties in estimating quantities of proved reserves and discounted future net cash flows, and actual quantities may be lower than estimated. Numerous uncertainties exist in estimating quantities of proved reserves and future net revenues from those reserves. Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses, and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates and could materially affect the estimated quantities of our proved reserves and the related future net revenues. In addition, reserve estimates may be subject to downward or upward changes based on production performance, purchases or sales of properties, results of future development, changes in prevailing oil and gas prices, PSCs, which may decrease reserves as crude oil and natural gas prices increase, and other factors.
Catastrophic and other events, whether naturally occurring or man-made, may materially affect our operations and financial condition. Our oil and gas operations are subject to numerous risks and hazards inherent to operating in the crude oil and natural gas industry, including catastrophic events, which may damage or destroy assets, interrupt operations, result in personal injury and have other significant adverse effects. These events include unexpected drilling conditions, pressure conditions or irregularities in reservoir formations, equipment malfunctions or failures, derailments, fires, explosions, blowouts, oil releases, power outages, cratering, pipeline interruptions and ruptures, severe weather, such as hurricanes, floods, freezes and heat waves or droughts, geological events, shortages in availability of skilled labor, cyber-attacks or health measures related to outbreaks of infectious diseases, such as COVID-19. We maintain insurance coverage against many, but not all, potential losses and liabilities in amounts we deem prudent, including for property and casualty losses. Some forms of insurance may be unavailable in the future or be available only on terms that are deemed economically unacceptable. Moreover, there can be no assurance that such insurance will adequately protect us against liability from all potential consequences and damages. For example, we are self-insured against physical damage to property and liability related to windstorms. In 2024, hurricane related downtime reduced net production by approximately 2,000 boepd and hurricane related maintenance and repair costs were approximately $1 million, whereas in 2023 and 2022 there was no significant hurricane related downtime. In addition, the frequency and severity of weather conditions and other meteorological phenomena, including storms, droughts, extreme temperatures, and changes in temperature and precipitation patterns that impact our business activities, may also be impacted by the effects of climate change. Energy needs could increase or decrease as a result of extreme weather conditions depending on the duration and magnitude of any such climate change. Increased energy use due to weather changes may require us to invest in order to serve increased demand or create operational challenges. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. To the extent the frequency of extreme weather events increases, this could adversely impact our business, results of operations and financial condition.
Significant time delays between the estimated and actual occurrence of critical events associated with development projects may result in material negative economic consequences. As part of our business, we are involved in large development projects, the completion of which may be delayed beyond what was originally planned. Such examples include, but are not limited to, delays in receiving necessary approvals from project members or regulatory or other government agencies, timely access to necessary equipment, services or resources, availability of necessary personnel, construction delays, unfavorable weather conditions, equipment failures, and outbreaks of infectious diseases, such as COVID-19. These delays could impact our future results of operations and cash flows.
An inability to secure personnel, drilling rigs, equipment, supplies and other required services or to retain key employees may result in material negative economic consequences. We are dependent on oilfield service companies for items including drilling rigs, equipment, supplies and skilled labor. The availability and cost of drilling rigs, equipment, supplies and skilled labor will fluctuate over time given the cyclical nature of the E&P industry. Concerns over global economic conditions, inflation, supply chain disruptions, labor shortages, tariffs, trade disputes and other factors, each of which are beyond our control, contribute to increased economic uncertainty for us and our suppliers. As a result, we may encounter difficulties in obtaining required equipment, supplies or services or could face an increase in cost, which may impact our ability to run our operations and deliver projects on time with the potential for material negative economic consequences. In addition, difficulty in recruiting and retaining adequate numbers of experienced technical personnel could negatively impact our ability to deliver on our strategic goals. Our future success also depends upon the continued service of key members of our senior management team, who play an important role in developing and implementing our strategy. An inability to recruit and retain adequate numbers of experienced technical and professional personnel in the necessary locations or the loss or departure of key members of senior management may prevent us from executing our strategy in full or in part, which could negatively impact our business.
Disruption, failure or cybersecurity attacks affecting or targeting information technology systems and infrastructure used by the Corporation or our business partners may materially impact our business and operations. Computers and telecommunication systems are an integral part of our exploration, development and production activities and the activities of our business partners. We rely on computer systems, hardware, software, technology infrastructure and online sites and networks for both internal and external operations that are critical to our business (collectively, Digital Systems). Some of our Digital Systems are managed and owned by us, but we rely on third parties for a range of Digital Systems and related products and services, including but not limited to cloud computing services. We use these Digital Systems to communicate, analyze and store proprietary, financial and operating data as well as data about employees, business partners and other third parties (collectively, Confidential Information). Our reliance on technology has increased due to our use of remote communications and hybrid work-from-home arrangements, which increase cybersecurity risks due to the challenges associated with managing remote computing assets and security vulnerabilities that are present in many non-corporate and home networks. In addition, any integration of artificial intelligence in our or any service providers’ operations, products or services is expected to pose new or unknown cybersecurity risks and challenges.
Technical system flaws, power loss and cybersecurity risks, including cyber or social engineering/phishing-attacks, unauthorized access, malicious or misconfigured software, malfeasance by employees or others with authorized access, ransomware, and other cybersecurity issues, threaten the confidentiality, integrity and availability of our Digital Systems and Confidential Information and could compromise our Digital Systems or those of our business partners and result in disruptions to our business operations or the access, disclosure or loss of our Confidential Information and communications. In addition, computers control oil and gas production, processing equipment and distribution systems globally and are necessary to deliver our production to market. A disruption, failure or a cyber breach of these operating systems, or of the networks and infrastructure on which they rely, could damage critical production, distribution and/or storage assets, delay or prevent delivery to markets, and make it difficult or impossible to accurately account for production and settle transactions. As a result, any such disruption, failure or cyber breach and any resulting investigation or remediation costs, reputational harm, litigation or regulatory action could have a material adverse impact on our cash flows and results of operations, reputation and competitiveness.
We routinely experience attempts by external parties to penetrate and attack our Digital Systems. Although such attempts to date have not resulted in any material breaches, disruptions, financial loss, or loss of business-critical information, our systems and procedures for protecting against such attacks and mitigating such risks may prove to be insufficient in the future. Cyberattacks are expected to accelerate on a global basis in frequency and magnitude as threat actors are becoming increasingly adept in using techniques and tools, including artificial intelligence, that circumvent security controls, evade detection and remove forensic evidence. As technologies evolve and these cybersecurity attacks become more sophisticated, we may incur significant costs to upgrade or enhance our security measures to protect against such attacks. We may also face difficulties in fully anticipating or implementing adequate preventive measures or mitigating potential harm.
Any adverse impact to the availability, integrity or confidentiality of our Digital Systems or Confidential Information can result in legal claims or proceedings (such as class actions), regulatory investigations and enforcement actions, fines and penalties, negative reputational impacts and/or significant incident response, system restoration or remediation and future compliance costs. Any or all of the foregoing could materially adversely affect our business, results of operations, and financial condition. Finally, we cannot guarantee that any costs and liabilities incurred in relation to an attack or incident will be covered by our existing insurance policies or that applicable insurance will be available to us in the future on economically reasonable terms or at all.
Financial Risks
We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms. The exploration, development and production of crude oil and natural gas involve substantial costs, which may not be fully funded from operations. All three major credit rating agencies that rate our debt have assigned an investment grade rating. Although currently we do not have any borrowings under our long-term credit facility, a ratings downgrade, rising interest rates, continued weakness in the oil and gas industry or negative outcomes within commodity and financial markets could adversely impact our access to capital markets by increasing the costs of financing, or by impacting our ability to obtain financing on satisfactory terms. In addition, a
ratings downgrade may require that we issue letters of credit or provide other forms of collateral under certain contractual requirements. Environmental concerns and other factors have led to lower oil and gas representation in certain key equity market indices and may increase our costs to access the equity capital markets. Any inability to access capital markets could adversely impact our financial adaptability and our ability to execute our strategy.
We may engage in risk management transactions designed to mitigate commodity price volatility and other risks that may impede our ability to benefit from commodity price increases and can expose us to similar potential counterparty credit risk as amounts due from the sale of hydrocarbons. We may enter into commodity price hedging arrangements to protect us from commodity price declines. These arrangements may, depending on the instruments used and the level of additional hedges involved, limit any potential upside from commodity price increases. As with accounts receivable from the sale of hydrocarbons, we may be exposed to potential economic loss should a counterparty be unable or unwilling to perform their obligations under the terms of a hedging agreement. In addition, we are exposed to risks related to changes in interest rates and foreign currency values, and may engage in hedging activities to mitigate related volatility.
Regulatory, Legal and Environmental Risks
Our oil and gas operations are subject to environmental risks and environmental, health and safety laws and regulations that can result in significant costs and liabilities. Our oil and gas operations are subject to environmental risks such as oil spills, produced water spills, gas leaks and ruptures and discharges of substances or gases that could expose us to substantial liability for pollution or other environmental damage. Our operations are also subject to numerous U.S. federal, state, local and foreign environmental, health and safety laws and regulations. Non-compliance with these laws and regulations may subject us to administrative, civil or criminal penalties, remedial clean-ups, natural resource damages and other liabilities. In addition, increasingly stringent environmental regulations have resulted and will likely continue to result in higher capital expenditures and operating expenses for us. Similarly, we have material legal obligations to dismantle, remove and abandon production facilities and wells that will occur many years in the future, in most cases. These estimates may be impacted by future changes in regulations, solvency of subsequent owners and partners and other uncertainties.
Concerns have been raised in certain jurisdictions where we have operations concerning the safety and environmental impact of the drilling and development of shale oil and gas resources, particularly hydraulic fracturing, water usage, flaring of associated natural gas and air emissions. While we believe that these operations can be conducted safely and with minimal impact on the environment, regulatory bodies are responding to these concerns and may impose moratoriums and new regulations on such drilling operations that would likely have the effect of prohibiting or delaying such operations and increasing their cost.
Climate change, sustainability and other ESG initiatives may result in significant operational changes and expenditures, reduced demand for our products and adversely affect our business. We recognize that climate change and sustainability is a growing global environmental concern. Continuing political and social attention to the issue of climate change and sustainability has resulted in both existing and pending international agreements and national, regional or local legislation and regulatory measures to limit GHG emissions. These agreements and measures may require, or could result in future legislation and regulatory measures that require, significant equipment modifications, operational changes, taxes, financial contributions to state climate adaptation funds, or purchase of emission credits to reduce emission of GHGs from our operations, which may result in substantial capital expenditures and compliance, operating, maintenance and remediation costs. For example, the Inflation Reduction Act of 2022 (IRA) includes a methane emissions reduction program for petroleum and natural gas systems, which requires the EPA to impose a “waste emissions charge” on excess methane emissions from certain natural gas and oil sources that are required to report under EPA’s Greenhouse Gas Reporting Program and also provides significant funding and incentives for research and development of competing low carbon energy production methods. In November 2024, the EPA finalized a rule to implement Congress’ directive in the IRA to impose a fee on excess methane emissions from the oil and gas sector. The states of New York and Vermont recently enacted legislation that seeks to impose retroactive strict liability on certain companies engaged in the extraction and refining of oil and gas for the funding of state climate adaptation funds. Similar legislation is under consideration in other states, including California. In addition, California has enacted three climate-related disclosure laws, the Climate Corporate Data Accountability Act, Climate Related Financial Risk Act and Voluntary Carbon Market Disclosures Act, which together will require certain entities doing business in California or taking certain actions in California to report and attain third-party assurance of greenhouse gas emissions information, reporting on climate-related financial risks and reporting regarding the use of voluntary carbon credits and/or carbon reduction claims. Legislation similar to California’s Climate Corporate Data Accountability Act is under consideration in other states, including in New York, Washington and Illinois. In addition to increased costs for compliance, such legislation, regulations and initiatives could also impact demand as our production is sold to third parties that produce petroleum fuels, which through normal end user consumption result in the emission of GHGs.
We are prioritizing sustainable energy practices to further reduce our carbon footprint while at the same time remaining a successful operating public company. However, various key stakeholders, including our stockholders, employees, suppliers, customers, local communities and others, may have differing approaches to climate change initiatives. If we do not successfully manage expectations across these varied stakeholder interests, it could erode our stakeholders’ trust and thereby affect our reputation. Shareholder activism has been recently increasing in our industry, and stockholders may attempt to effect changes to our business or governance, whether by shareholder proposals, public campaigns, proxy solicitations or otherwise. In addition, certain financial
institutions, institutional investors and other sources of capital have begun to limit or eliminate their investment in oil and gas activities due to concerns about climate change, which could make it more difficult to finance our business. We continue to focus on developing our ESG practices, and as voluntary and regulatory ESG disclosure standards and policies continue to evolve, we have expanded and expect to further expand our public disclosures in these areas. Such disclosures may reflect aspirational goals, targets, cost estimates and other expectations and assumptions, including over long timelines, which aspirational goals, targets, cost estimates, and other expectations and assumptions are necessarily uncertain and may not be realized. The lack of an established single approach to identifying, measuring, and reporting on many ESG matters may further create uncertainty and ambiguities. Failure to realize or timely achieve progress on such aspirational goals, targets, cost estimates, and other expectations or assumptions may adversely impact us. Unfavorable ESG ratings could also lead to further increased negative sentiment towards us and our industry, negatively impacting us and our access to and costs of capital. In addition, voluntary disclosures regarding ESG matters, as well as any ESG disclosures currently required or required in the future, could result in private litigation or government investigation or enforcement action regarding the sufficiency or validity of such disclosures.
Furthermore, as a result of heightened public awareness and attention to climate change and sustainability as well as continued regulatory initiatives to reduce the use of petroleum fuels, demand for crude oil and other hydrocarbons may be reduced, which may have an adverse effect on our sales volumes, revenues and margins. The imposition and enforcement of stringent GHG emissions reduction requirements could severely and adversely impact the oil and gas industry and therefore significantly reduce the value of our business. Increasing attention to climate change risks and sustainability has resulted in governmental investigations, and public and private litigation, which could increase our costs or otherwise adversely affect our business. For example, beginning in 2017, certain states, municipalities and private associations in California, Delaware, Maryland, Rhode Island and South Carolina separately filed lawsuits against oil, gas and coal producers, including us, for alleged damages purportedly caused by climate change. Such actions could adversely impact our business by distracting management and other personnel from their primary responsibilities, require us to incur increased costs, and/or result in reputational harm.
We are subject to changing laws and regulations, other governmental actions and legal proceedings that can significantly and adversely affect our business. Political or regulatory developments and governmental actions, including federal, state, local, territorial and foreign laws and regulations may adversely affect our operations and those of our counterparties with whom we have contracted, which may affect our financial results. These actions could result in tax increases retroactively through tax claims or prospectively through changes to applicable statutory tax rates, modification of the tax base, or imposition of new tax types. Additionally, governmental actions could include limitations on post-production deductions from royalty payments; limitations or prohibitions on the sales of new oil and gas leases or extensions on existing oil and gas leases; adverse court decisions with respect to the sale of new and existing oil and gas leases or claims related to working interest payments; expropriation or nationalization of property; mandatory government participation, cancellation or amendment of contract rights; imposition of capital controls or blocking of funds; changes in import and export regulations; the imposition of tariffs; and anti-bribery or anti-corruption laws. In recent years, proposals for limitations on access to oil and gas exploration and development opportunities and related litigation have grown in certain areas and may include efforts to reduce access to public and private lands; restriction of exploration and production activities within government-owned and other lands; delaying or canceling permits for drilling or pipeline construction; restrictions or changes to existing pipeline easements; limiting or banning industry techniques such as hydraulic fracturing and/or adding restrictions on the use of water and associated disposal; imposition of set-backs on oil and gas sites; reduction of sulfur content in bunker fuel; delaying or denying air-quality or siting permits; advocating for increased regulations, punitive taxation, or citizen ballot initiatives or moratoriums on industry activity; and the use of social media channels to cause reputational harm. Furthermore, we are involved in six claims in federal and state courts in North Dakota related to post-production deductions from royalty and working interest payments for various oil and gas processing and transportation related costs and expenses. Costs associated with responding to anti-development efforts, litigation or complying with any new legal or regulatory requirements could significantly and adversely affect our business, financial condition and results of operations.
Political instability globally and in the areas where we operate can adversely affect our business. Political instability and civil unrest have affected and may continue to affect the oil and gas markets generally. Some international areas are politically less stable than other areas and may be subject to civil unrest, conflict, insurgency, corruption, security risks and labor unrest. Political instability in areas where we operate may expose our operations to increased risks, including increased difficulty in obtaining required permits and government approvals, enforcing our agreements in those jurisdictions and potential adverse actions by local government authorities. The invasion of Ukraine by Russia in February 2022 has led to disruption, instability, and volatility in global markets and industries, including the oil and gas markets. The U.S. government and other foreign governments imposed severe economic sanctions and export controls against Russia, certain regions of Ukraine and particular entities and individuals, and may impose additional sanctions and controls. The war between Israel and Hamas, which began in October 2023, has the potential for further disruption of economic markets, particularly if the conflict does not come to a successful resolution and expands to other parts of the Middle East.
Political developments, including changes in leadership, shifts in policy priorities, and legislation could have significant implications for our business operations, regulatory environment, and financial performance. The unpredictability of the political environment poses challenges in anticipating and mitigating risks effectively. We may also be negatively affected by the prospect of expanded trade restrictions between the government of the U.S. and where we or our partners operate. The escalation of any “trade
war” may contribute to the rise of inflation, which may negatively affect the U.S. and global markets. At this time, it is unclear how further expanded trade restrictions may impact us or our partners, although they pose the risk of price instability and that exports of our products may become subject to retaliatory tariffs.
To date, we have not experienced a material impact to operations or the consolidated financial statements as a result of these conflicts; however, we will continue to monitor for events that could materially impact us or our industry. Furthermore, the threat of terrorism around the world also poses additional risks to our operations and the operations of the oil and gas industry in general. In addition, geographic territorial border disputes may affect our business in certain areas, such as the border dispute between Guyana and Venezuela over a portion of the Stabroek Block.
One of our subsidiaries is the general partner of a publicly traded limited partnership, Hess Midstream LP. The responsibilities associated with being a general partner expose us to a broader range of legal liabilities. Our control of Hess Midstream LP bestows upon us additional duties and obligations including, but not limited to, the obligations associated with managing potential conflicts of interests and additional reporting requirements from the Securities and Exchange Commission. These heightened duties expose us to additional potential for legal claims that may have a material negative economic impact on our stockholders. Moreover, these increased duties may lead to an increase in compliance costs.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
Information regarding legal proceedings is contained in Note 17, Guarantees, Contingencies and Commitments in the Notes to Consolidated Financial Statements and is incorporated herein by reference. Pursuant to Item 103(c)(3)(iii) of Regulation S-K under the Exchange Act, we are required to disclose certain information about environmental proceedings to which a governmental authority is a party if we reasonably believe such proceedings may result in monetary sanctions, exclusive of interest and costs, above a stated threshold. We have elected to apply a threshold of $1 million for purposes of determining whether disclosure of any such proceedings is required.
Merger
Stockholder Suits
In connection with the Merger Agreement, two lawsuits were filed challenging the sufficiency of the disclosures made in connection therewith. First, a complaint was filed in federal court as an individual action. The complaint is captioned as Globokar v. Hess Corporation, et al., 24-cv-01723 (filed March 6, 2024 in the Southern District of New York). It alleged, among other things, that the preliminary proxy statement filed on February 26, 2024 in connection with the Merger Agreement misrepresented and/or omitted certain purportedly material information and sought, among other things an injunction enjoining the consummation of the Merger and the other transactions contemplated by the Merger Agreement. Second, a putative class-action complaint was filed in the Delaware Court of Chancery under the caption Assad v. Hess Corporation, et al., C.A. No. 2024-0468-NAC (filed May 2, 2024). It alleged that Hess Board of Directors breached its fiduciary duties by failing to disclose purportedly material information in the definitive proxy statement filed on April 26, 2024 and sought, among other things an injunction enjoining the consummation of the Merger and the other transactions contemplated by the Merger Agreement (including a preliminary injunction against the closing of the transaction) unless and until the allegedly omitted material information was disclosed.
In addition to these lawsuits, several purported stockholders of Hess sent demand letters alleging similar deficiencies regarding the disclosures made in the proxy statement.
In order to avoid the risk that the lawsuits or demand letters delay or otherwise adversely affect the Merger, and to minimize the costs, risks and uncertainties inherent in litigation, and without admitting any liability or wrongdoing, Hess provided supplemental disclosures to the definitive proxy statement filed in connection with the Merger Agreement in Hess’s Current Report on Form 8-K, filed with the SEC on May 21, 2024. On May 31, 2024, the individual plaintiff in the above-captioned Assad v. Hess Corporation, et al., C.A. No. 2024-0468-NAC filed a notice voluntarily dismissing the action without prejudice. On June 5, 2024, the individual plaintiff in the above-captioned Globokar v. Hess Corporation, et al., 24-cv-01723, filed a notice voluntarily dismissing the action without prejudice and the matter has been dismissed.
Hess believes that these matters are without merit and intends to defend against demands or filed actions relating to the Merger. If additional similar complaints are filed or demands sent, Hess will not necessarily disclose such additional filings or demands. Hess cannot predict the outcomes of these matters.
Arbitration
On March 6, 2024, an affiliate of Exxon Mobil commenced arbitration proceedings regarding the applicability of the Stabroek ROFR to the Merger pursuant to the dispute resolution requirements of the Stabroek operating agreement (the Stabroek JOA). On March 11, 2024 and March 15, 2024, HGEL and an affiliate of CNOOC, respectively, commenced parallel arbitration proceedings regarding the applicability of the Stabroek ROFR to the Merger pursuant to the dispute resolution requirements of the Stabroek JOA. On March 26, 2024, following a joint application by the parties, the authority administering the arbitration consolidated the three arbitration proceedings. The arbitration merits hearing about the applicability of the Stabroek ROFR to the Merger has been scheduled for May 2025, with a decision expected in the third quarter.
HGEL has asserted in these arbitration proceedings that the Stabroek ROFR does not apply to the Merger due to the structure of the Merger and the language of the Stabroek ROFR provisions. The Exxon Mobil affiliate and the CNOOC affiliate have asserted in these arbitration proceedings that the Stabroek ROFR applies to the Merger. Chevron and Hess believe that Exxon Mobil’s and CNOOC’s asserted claims are without merit. HGEL intends to vigorously defend its position in the arbitration proceedings and expects the arbitration tribunal will confirm that the Stabroek ROFR does not apply to the Merger. However, the outcome of any arbitration proceedings regarding the applicability of the Stabroek ROFR to the Merger is uncertain.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
None.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities
Stock Market Information, Holders and Dividends
Our common stock is listed on the New York Stock Exchange (ticker symbol: HES). At January 31, 2025, there were 2,369 stockholders (based on the number of holders of record) who owned a total of 308,291,660 shares of common stock. In 2024, cash dividends on common stock totaled $1.875 per share per year ($0.4375 per share for the first two quarters and $0.50 per share commencing in the third quarter of 2024), $1.75 per share per year ($0.4375 per quarter) in 2023 and $1.50 per share per year ($0.3750 per quarter) in 2022.
Performance Graph
Set forth below is a line graph comparing the five-year shareholder returns on a $100 investment in our common stock assuming reinvestment of dividends, against the cumulative total returns for the following:
•Standard & Poor’s (S&P) 500 Stock Index, which includes us.
•Proxy Peer Group comprising eight oil and gas peer companies as disclosed in our 2024 Proxy Statement, excluding Pioneer Natural Resources Company, which was acquired by Exxon Mobil Corporation, and Marathon Oil Corporation, which was acquired by ConocoPhillips.
Comparison of Five-Year Shareholder Returns
Years Ended December 31,
2019 2020 2021 2022 2023 2024
Hess Corporation
$100.00 $80.81 $114.85 $222.88 $229.38 $214.51
S&P 500
$100.00 $118.39 $152.34 $124.73 $157.48 $196.85
Proxy Peer Group
$100.00 $60.80 $113.89 $194.33 $189.60 $172.04
Share Repurchase Activities
Our share repurchases for the quarter ended December 31, 2024, were as follows:
Period Total Number of
Shares Purchased (a) Average
Price Paid
per Share Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs Maximum Approximate
Dollar Value of
Shares that May
Yet be Purchased
Under the Plans
or Programs (b)
(In millions)
October - $ - - $ 1,000
November 9,356 142.75 - 1,000
December - - - 1,000
Total 9,356 $ 142.75 -
(a)These shares were withheld to satisfy tax withholding obligations upon vesting of restricted stock awards under our long-term incentive program.
(b)On March 1, 2023, our Board of Directors approved a new authorization for the repurchase of our common stock in an aggregate amount of up to $1 billion. This new authorization replaced our previous repurchase authorization which was fully utilized at the end of 2022.
The Merger Agreement provides that, during the periods from the date of the Merger Agreement until the closing of the Merger, we are subject to certain restrictions that, among other things, restrict our ability to repurchase, redeem or retire any capital stock of the Corporation.
Equity Compensation Plans
Following is information related to our equity compensation plans at December 31, 2024.
Plan Category Number of Securities
to be Issued Upon Exercise of Outstanding Options, Warrants and Rights* Weighted Average
Exercise Price of
Outstanding Options,
Warrants and Rights Number of Securities
Remaining Available
for Future Issuance
Under Equity
Compensation Plans
(Excluding Securities
Reflected in
Column*)
Equity compensation plans approved by security holders 1,233,621 (a) $ 79.49 18,371,098 (b)
Equity compensation plans not approved by security holders - - -
(a)This amount includes 1,233,621 shares of common stock issuable upon exercise of outstanding stock options. This amount excludes 1,228,685 shares of common stock issued as restricted stock pursuant to our equity compensation plans. This amount also excludes 306,297 PSUs. For the PSUs granted in 2022, the number of shares of common stock to be issued will range from 0% to 200% based on our total shareholder return (TSR) relative to the TSR of a predetermined group of peer companies and the S&P 500 index over a three-year performance period ending December 31 of the year prior to settlement of the grant. For the PSUs granted in 2023, the number of shares of common stock to be issued is based on a comparison of the Corporation’s total shareholder return compound annual growth rate (TSR CAGR) to the TSR CAGR of the SPDR S&P Oil & Gas Exploration and Production ETF (XOP), with a modifier determined by comparing the Corporation’s TSR CAGR to the TSR CAGR of the S&P 500 index, over a three-year performance period ending December 31, 2025. Payout of these PSUs will range from 0% to 200% of the target awards based on the comparison of the Corporation’s TSR CAGR to the XOP’s TSR CAGR. The modifier can only adjust the payout percentage by plus or minus 10%, up to a maximum of 210% or a minimum of 0%. There were no PSUs granted in 2024.
(b)These securities may be awarded as stock options, restricted stock, PSUs or other awards permitted under our equity compensation plan.
See Note 13, Share-based Compensation in the Notes to Consolidated Financial Statements for further discussion of our equity compensation plans.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. [Reserved]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Form 10-K in Item 8, and the information set forth in Part 1, Item 1A. Risk Factors.
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations omits certain discussions of our financial condition and results of operations for the year ended December 31, 2023 compared with the year ended December 31, 2022, which can be found in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2023 Annual Report on Form 10-K, which was filed with the Securities and Exchange Commission on February 26, 2024, and such comparisons are incorporated herein by reference.
Index
Overview
Consolidated Results of Operations
Liquidity and Capital Resources
Critical Accounting Policies and Estimates
Overview
Hess Corporation is a global E&P company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA) and Malaysia. We conduct exploration activities primarily offshore Guyana, in the U.S. Gulf of America, and offshore Suriname. At the Stabroek Block (Hess 30%), offshore Guyana, we and our partners have discovered a significant resource base and are executing a multi-phased development of the block. We currently have three FPSOs producing, and plan to have eight FPSOs producing by the end of 2030 with an aggregate expected production capacity of approximately 1.7 million gross bopd. The discovered resources to date on the block are expected to underpin the potential for up to ten FPSOs.
Our Midstream operating segment, which is comprised of Hess Corporation’s approximate 38% consolidated ownership interest in Hess Midstream LP at December 31, 2024, provides fee-based services, including gathering, compressing and processing natural gas and fractionating NGL; gathering, terminaling, loading and transporting crude oil and NGL; storing and terminaling propane, and water handling services primarily in the Bakken shale play in the Williston Basin area of North Dakota.
On October 22, 2023, we entered into the Merger Agreement with Chevron and the Merger Subsidiary. The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, Merger Subsidiary will be merged with and into Hess, and Hess will be the surviving corporation in the Merger as a direct, wholly-owned subsidiary of Chevron. Under the terms of the Merger Agreement, if the Merger is completed, our stockholders will receive at the effective time of the Merger consideration consisting of 1.025 shares of Chevron common stock for each share of our common stock. On May 28, 2024, holders of a majority of Hess’ outstanding common stock voted to approve the Merger. Hess Guyana Exploration Limited (HGEL), a wholly-owned subsidiary of Hess, is currently in arbitration relating to the applicability of a right of first refusal (the Stabroek ROFR) contained in the operating agreement (the Stabroek JOA) among HGEL and affiliates of Exxon Mobil Corporation (Exxon Mobil) and China National Offshore Oil Corporation (CNOOC). The arbitration merits hearing about the applicability of the Stabroek ROFR to the Merger has been scheduled for May 2025, with a decision expected in the third quarter. We cannot predict the date on which the Merger will be completed because it is subject to conditions beyond our control, including the outcome of the arbitration. See Part I, Item 1A. Risk Factors for a discussion of risks related to the Merger.
Climate Change, Energy Transition and Our Strategy
We believe climate risks can and should be addressed while at the same time meeting the growing demand for affordable and secure energy, which is essential to ensure a just and orderly energy transition that aligns with the United Nations Sustainable Development Goals. The IEA’s 2024 World Energy Outlook provides three scenarios of global energy demand in 2040 based on varying levels of global response to climate change. Under all of the IEA scenarios, oil and natural gas are expected to be needed for decades to come and we expect that significant investment will be required to meet the world’s projected growing energy needs, both in renewable energy sources and in oil and gas.
Our strategy is to grow our resource base, have a low cost of supply and sustain cash flow growth. Our strategy aligns with the energy transition needed to reach the energy-related Sustainable Development Goals of the United Nations. Our commitment to sustainability starts with our Board of Directors and senior management and is reinforced throughout our organization. Our Board of Directors, led by its Environmental, Health and Safety Committee, is actively engaged in overseeing Hess’ sustainability practices so
that sustainability risks and opportunities are taken into account when making strategic decisions. Our Board’s Compensation and Management Development Committee has tied executive compensation to advancing our environmental, health and safety goals.
We have five year GHG reduction targets for 2025, which are to reduce operated Scope 1 and 2 GHG emissions intensity by approximately 50% and methane emissions intensity by approximately 50%, both from 2017 levels. In January 2022, we announced our plan to reduce routine flaring at Hess operated assets to zero by the end of 2025. In December 2022, we announced an agreement with the Government of Guyana to purchase 37.5 million REDD+ carbon credits, including current and future issuances, for a minimum of $750 million from 2022 through 2032 to prevent deforestation and support sustainable development in Guyana. This agreement adds to the Corporation’s ongoing emissions reduction efforts and is an important part of our commitment to achieve net zero Scope 1 and 2 greenhouse gas emissions on an equity basis by 2050.
Our business planning includes actions we expect to undertake to continue reducing our carbon footprint consistent with our targets. We also conduct scenario planning as a methodology to assess our portfolio’s resilience to differing scenarios of energy supply and demand over the longer term, and to inform our understanding of future risks and opportunities in relation to the potential evolution of energy demand, energy mix, the emergence of new technologies, and possible changes by policymakers with respect to greenhouse gas emissions and climate change.
Consolidated Results
Net income attributable to Hess Corporation was $2,769 million in 2024 compared with $1,382 million in 2023. Excluding items affecting comparability of earnings between periods summarized on page 35, adjusted net income was $2,983 million in 2024 compared with $1,552 million in 2023. Net production averaged 481,000 boepd in 2024 and 394,000 boepd in 2023. The average realized crude oil price was $77.28 per barrel in 2024 and $75.97 per barrel, including the effect of hedging, in 2023. Total proved reserves were 1,438 million boe and 1,370 million boe at December 31, 2024 and December 31, 2023, respectively.
Significant 2024 Activities
The following is an update of significant E&P activities during 2024:
E&P assets:
•In North Dakota, net production from the Bakken shale play averaged 204,000 boepd in 2024 (2023: 182,000 boepd). Net production was higher in 2024 primarily reflecting increased drilling and completion activity. NGL and natural gas volumes received under percentage of proceeds contracts were 22,000 boepd in 2024, compared with 19,000 boepd in 2023, due to lower commodity prices increasing volumes received as consideration for gas processing fees. During 2024 we operated four rigs and drilled 136 wells and brought 131 new wells online, bringing the total operated production wells to 1,864 at December 31, 2024. During 2025, we plan to continue operating four drilling rigs. We forecast net production to be in the range of 195,000 boepd to 200,000 boepd in the first quarter of 2025, reflecting the impact of winter weather.
•In the Gulf of America, net production averaged 31,000 boepd in 2024 (2023: 31,000 boepd). The Pickerel-1 oil discovery (Hess 100%) located in Mississippi Canyon Block 727 achieved first production in June as a tieback to the Tubular Bells production facilities. In late December, we completed drilling at the Vancouver-1 exploration well (Hess 40%) located in Green Canyon Block 287 which did not encounter commercial quantities of hydrocarbons. Accordingly, 2024 results include $92 million in exploration expense for well costs incurred through December 31, 2024. Additional exploration expense related to the Vancouver-1 exploration well of approximately $25 million is expected to be recognized in the first quarter of 2025 for well costs incurred after December 31, 2024. In March, we were awarded 20 leases in the U.S. Department of Interior’s Lease Sale 261 for $88 million. In the second quarter of 2025, we plan to bring online the Hess operated Black Pearl development well (Hess 25%) as a tieback to the Stampede production facilities. In 2025, we also plan to participate in three wells.
•At the Stabroek Block (Hess 30%), offshore Guyana, net production totaled 186,000 bopd in 2024 (2023: 115,000 bopd), which included 29,000 bopd of tax barrels (2023: 14,000 bopd). Net production in Guyana was higher in 2024 primarily due to the start-up of the third development on the block, Payara, which commenced production in November 2023. We forecast net production to be in the range of 180,000 bopd to 185,000 bopd in the first quarter of 2025, which includes tax barrels of approximately 20,000 bopd. In 2024, we sold 59 cargos of crude oil from Guyana compared with 37 cargos in 2023. We expect to sell 14 cargos of crude oil in the first quarter of 2025.
A fourth development, Yellowtail, was sanctioned in April 2022 and will utilize the ONE GUYANA FPSO with a production capacity of approximately 250,000 gross bopd, with first production expected in the fourth quarter of 2025. Six drill centers are planned with up to 26 production wells and 25 injection wells.
A fifth development, Uaru, was sanctioned in April 2023 and will utilize the Errea Wittu FPSO with a production capacity of approximately 250,000 gross bopd, with first production expected in 2026. Ten drill centers are planned with up to 21 production wells and 23 injection wells.
A sixth development, Whiptail, was sanctioned in April 2024 and will utilize the Jaguar FPSO with a production capacity of approximately 250,000 gross bopd, with first production expected in 2027. Ten drill centers are planned with up to 24 production wells and 24 injection wells.
The application for the environmental permit for the seventh development, Hammerhead, has been filed with Guyana’s Environmental Protection Agency. Pending government and regulatory approval and project sanctioning, the development is expected to have a production capacity of approximately 150,000 gross bopd, with first production anticipated in 2029.
In 2024, ExxonMobil Guyana Ltd. completed construction of a 130-mile pipeline in order to transport approximately 50 million standard cubic feet of natural gas per day from the Liza Field to a 300 megawatt onshore power plant, which will be constructed and operated by the Government of Guyana.
In 2024, the operator drilled a total of eight successful exploration and appraisal wells that encountered hydrocarbons and one unsuccessful exploration well for which the well costs were expensed. In 2025, the operator plans to utilize five drillships to continue to perform exploration, appraisal, and development activities.
•In the Gulf of Thailand, net production from Block A-18 of the JDA averaged 31,000 boepd in 2024 (2023: 36,000 boepd), including contribution from unitized acreage in Malaysia, while net production from North Malay Basin (NMB) averaged 29,000 boepd in 2024 (2023: 30,000 boepd). At the JDA, the operator drilled two production wells during 2024. In June 2024, the regulator provided notification that the current PSC for JDA Block A-18 will not be re-awarded to the existing PSC contractors upon its expiration in 2029. At the JDA, the operator plans to drill two development wells in 2025. At NMB, we drilled five production wells during 2024. In 2025, we plan to continue development activities at NMB.
The following is an update of significant Midstream activities during 2024:
•Hess Midstream LP completed three underwritten public equity offerings of an aggregate of 35.7 million Hess Midstream LP Class A shares held by an affiliate of GIP. We did not receive any proceeds from the public equity offerings.
•HESM Opco, a consolidated subsidiary of Hess Midstream LP, repurchased 8.4 million HESM Opco Class B units held by affiliates of Hess Corporation and GIP in three transactions, for which we received proceeds of $113 million.
Liquidity and Capital and Exploratory Expenditures
At December 31, 2024, cash and cash equivalents were $1,171 million (2023: $1,688 million) and consolidated debt was $8,578 million (2023: $8,613 million), which includes Hess Midstream debt that is nonrecourse to Hess Corporation of $3,472 million at December 31, 2024 (2023: $3,211 million).
Capital and exploratory expenditures were as follows (in millions):
2024 2023 2022
E&P Capital and Exploratory Expenditures:
United States
North Dakota $ 1,279 $ 1,138 $ 807
Offshore and other 478 290 224
Total United States 1,757 1,428 1,031
Guyana 2,932 2,518 1,345
Malaysia and JDA 147 189 275
Other (a) 23 41 70
E&P Capital and Exploratory Expenditures $ 4,859 $ 4,176 $ 2,721
Exploration Expenses Charged to Income Included Above:
United States $ 104 $ 106 $ 107
International 41 37 25
Total Exploration Expenses Charged to Income included above $ 145 $ 143 $ 132
Midstream Capital Expenditures:
Midstream Capital Expenditures $ 288 $ 246 $ 232
(a)Other includes our interests in Libya (sold in November 2022), and certain non-producing countries.
Our E&P capital and exploratory expenditures are projected to be approximately $4.5 billion in 2025, inclusive of capitalized interest of approximately $240 million, compared with $4.9 billion in 2024. Capital investment for our Midstream operations is expected to be approximately $300 million in 2025, compared with $288 million in 2024.
Consolidated Results of Operations
Results by Segment:
The after-tax income (loss) by major operating activity is summarized below:
2024 2023 2022
(In millions, except per share amounts)
Net Income Attributable to Hess Corporation:
Exploration and Production $ 2,780 $ 1,601 $ 2,396
Midstream 276 252 269
Corporate, Interest and Other (287) (471) (569)
Total $ 2,769 $ 1,382 $ 2,096
Net Income Attributable to Hess Corporation Per Common Share:
Basic $ 9.03 $ 4.52 $ 6.80
Diluted $ 8.98 $ 4.49 $ 6.77
In the following discussion and elsewhere in this report, the financial effects of certain transactions are disclosed on an after-tax basis. Management reviews segment earnings on an after-tax basis and uses after-tax amounts in its review of variances in segment earnings. Management believes that after-tax amounts are a preferable method of explaining variances in earnings, since they show the entire effect of a transaction rather than only the pre-tax amount. After-tax amounts are determined by applying the income tax rate in each tax jurisdiction to pre-tax amounts.
Items Affecting Comparability of Earnings Between Periods:
The following table summarizes, on an after-tax basis, items of income (expense) that are included in net income and affect comparability of earnings between periods. The items in the table below are explained on pages 40 through 41.
2024 2023 2022
(In millions)
Items Affecting Comparability of Earnings Between Periods, After Income Taxes:
Exploration and Production $ (214) $ (101) $ 22
Midstream - - -
Corporate, Interest and Other - (69) (102)
Total $ (214) $ (170) $ (80)
The following table presents the pre-tax amount of items affecting comparability of income (expense) by financial statement line item in the Statement of Consolidated Income on page 58. The items in the table below are explained on pages 40 through 41.
Before Income Taxes
2024 2023 2022
(In millions)
Gains on asset sales, net $ - $ - $ 98
Other, net (35) (17) -
Operating costs and expenses (18) - -
Exploration expenses, including dry holes and lease impairment (48) (52) -
General and administrative expenses - (52) (124)
Impairment (132) (82) (54)
Total Items Affecting Comparability of Earnings Between Periods, Pre-Tax $ (233) $ (203) $ (80)
Reconciliations of GAAP and Non-GAAP Measures:
The following table reconciles reported net income attributable to Hess Corporation and adjusted net income attributable to Hess Corporation:
2024 2023 2022
(In millions)
Adjusted Net Income Attributable to Hess Corporation:
Net income attributable to Hess Corporation $ 2,769 $ 1,382 $ 2,096
Less: Total items affecting comparability of earnings between periods, after-tax (214) (170) (80)
Adjusted Net Income Attributable to Hess Corporation $ 2,983 $ 1,552 $ 2,176
The following table reconciles reported net cash provided by (used in) operating activities and net cash provided by (used in) operating activities before changes in operating assets and liabilities:
2024 2023 2022
(In millions)
Net cash provided by (used in) operating activities before changes in operating assets and liabilities:
Net cash provided by (used in) operating activities $ 5,600 $ 3,942 $ 3,944
Changes in operating assets and liabilities 753 552 1,177
Net cash provided by (used in) operating activities before changes in operating assets and liabilities $ 6,353 $ 4,494 $ 5,121
Adjusted net income attributable to Hess Corporation is a non-GAAP financial measure, which we define as reported net income attributable to Hess Corporation excluding items identified as affecting comparability of earnings between periods, which are summarized on pages 40 through 41. Management uses adjusted net income to evaluate the Corporation’s operating performance and believes that investors’ understanding of our performance is enhanced by disclosing this measure, which excludes certain items that management believes are not directly related to ongoing operations and are not indicative of future business trends and operations.
Net cash provided by (used in) operating activities before changes in operating assets and liabilities presented in this report is a non-GAAP measure, which we define as reported net cash provided by (used in) operating activities excluding changes in operating assets and liabilities. Management uses net cash provided by (used in) operating activities before changes in operating assets and liabilities to evaluate the Corporation’s ability to internally fund capital expenditures, pay dividends and service debt and believes that
investors’ understanding of our ability to generate cash to fund these items is enhanced by disclosing this measure, which excludes working capital and other movements that may distort assessment of our performance between periods.
These measures are not, and should not be viewed as, substitutes for GAAP net income and net cash provided by (used in) operating activities.
Comparison of Results
Exploration and Production
Following is a summarized statement of income for our E&P operations:
2024 2023 2022
(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues $ 12,869 $ 10,500 $ 11,324
Gains on asset sales, net 1 - 76
Other, net 37 50 102
Total revenues and non-operating income 12,907 10,550 11,502
Costs and Expenses
Marketing, including purchased oil and gas 2,695 2,809 3,394
Operating costs and expenses 1,631 1,479 1,186
Production and severance taxes 234 216 255
Midstream tariffs 1,376 1,245 1,193
Exploration expenses, including dry holes and lease impairment 326 317 208
General and administrative expenses 321 254 224
Depreciation, depletion and amortization 2,282 1,852 1,520
Impairment 132 82 54
Total costs and expenses 8,997 8,254 8,034
Results of Operations Before Income Taxes 3,910 2,296 3,468
Provision for income taxes 1,130 695 1,072
Net Income Attributable to Hess Corporation $ 2,780 $ 1,601 $ 2,396
Excluding the E&P items affecting comparability of earnings between periods in the table on page 40, the changes in E&P results are primarily attributable to changes in selling prices, production and sales volumes, marketing expenses, cash operating costs, Midstream tariffs, DD&A expense, exploration expenses and income taxes, as discussed below.
Selling Prices: The impact of changes in realized selling prices in 2024 to after-tax earnings was not significant, compared with 2023. Our average selling prices were as follows:
2024 2023 2022
Average Selling Prices (a)
Crude Oil - Per Barrel (Including Hedging)
United States
North Dakota $ 72.11 $ 70.44 $ 81.06
Offshore 75.07 72.06 81.38
Total United States 72.70 70.80 81.14
Guyana 80.04 80.72 89.86
Malaysia and JDA 77.76 75.51 89.77
Other (b) - - 93.67
Worldwide 77.28 75.97 85.76
Crude Oil - Per Barrel (Excluding Hedging)
United States
North Dakota $ 72.11 $ 73.80 $ 91.26
Offshore 75.07 75.39 91.51
Total United States 72.70 74.15 91.32
Guyana 80.04 82.20 96.52
Malaysia and JDA 77.76 75.51 89.77
Other (b) - - 101.92
Worldwide 77.28 78.29 94.15
Natural Gas Liquids - Per Barrel
United States
North Dakota $ 21.75 $ 20.77 $ 35.09
Offshore 21.73 20.87 35.24
Worldwide 21.75 20.77 35.09
Natural Gas - Per Mcf
United States
North Dakota $ 1.17 $ 1.68 $ 5.50
Offshore 1.78 2.16 6.21
Total United States 1.25 1.76 5.66
Malaysia and JDA 6.57 5.95 5.62
Other (b) - - 5.93
Worldwide 4.20 4.32 5.64
(a)Selling prices in the United States and Guyana are adjusted for certain processing and distribution fees included in Marketing expenses. Excluding these fees worldwide selling prices for 2024 would be $79.70 per barrel for crude oil (including hedging) (2023: $79.30; 2022: $89.50), $79.70 per barrel for crude oil (excluding hedging) (2023: $81.62; 2022: $97.89), $21.86 per barrel for NGL (2023: $21.01; 2022: $35.44) and $4.31 per mcf for natural gas (2023: $4.47; 2022: $5.76).
(b)Other includes our interests in Libya (sold in November 2022).
There were no crude oil hedging activities in 2024 as such strategies are subject to certain limitations under the Merger Agreement. Crude oil hedging activities in 2023 were a net loss of $190 million before and after income taxes, and a net loss of $585 million before and after income taxes in 2022.
Production Volumes: Our daily worldwide net production was as follows:
2024 2023 2022
(In thousands)
Crude Oil - Barrels
United States
North Dakota 91 83 75
Offshore 23 22 22
Total United States 114 105 97
Guyana 186 115 78
Malaysia and JDA 5 5 4
Other (a) - - 15
Total 305 225 194
Natural Gas Liquids - Barrels
United States
North Dakota 74 67 53
Offshore 2 2 2
Total United States 76 69 55
Natural Gas - Mcf
United States
North Dakota 232 191 156
Offshore 35 43 44
Total United States 267 234 200
Malaysia and JDA 332 368 360
Other (a) - - 10
Total 599 602 570
Barrels of Oil Equivalent 481 394 344
Crude oil and natural gas liquids as a share of total production 79 % 75 % 72 %
(a)Other includes our interests in Libya (sold in November 2022) which produced 17,000 boepd for 2022.
We forecast total net production to be in the range of 465,000 boepd to 475,000 boepd in the first quarter of 2025.
Net production variances related to 2024 and 2023 are summarized as follows:
United States: North Dakota net production was higher in 2024, primarily reflecting increased drilling and completion activity.
International: Net production in Guyana was higher in 2024, primarily due to start-up of the third development on the Stabroek Block, Payara, which commenced production in November 2023. Net production from Guyana included 29,000 bopd of tax barrels in 2024 (2023: 14,000 bopd). Net production in Malaysia and JDA was lower in 2024 due to planned maintenance at JDA.
Sales Volumes: Higher sales volumes in 2024 increased after-tax earnings by approximately $1,985 million, compared with 2023. Net worldwide sales volumes from Hess net production, which excludes sales volumes of crude oil, NGLs and natural gas purchased from third parties, were as follows:
2024 2023 2022
(In thousands)
Crude oil - barrels
111,284 81,941 69,679
Natural gas liquids - barrels
28,051 25,184 19,843
Natural gas - mcf
219,269 219,750 208,001
Barrels of Oil Equivalent 175,880 143,750 124,189
Crude oil - barrels per day
304 225 191
Natural gas liquids - barrels per day
77 69 54
Natural gas - mcf per day
599 602 570
Barrels of Oil Equivalent Per Day 481 394 340
Marketing, including purchased oil and gas (Marketing expense): Marketing expense is mainly comprised of costs to purchase crude oil, NGL and natural gas from our partners in Hess operated wells or other third parties, primarily in the U.S., and transportation and other distribution costs for U.S. and Guyana marketing activities. Marketing expense was lower in 2024, compared to 2023, primarily due to lower purchased volumes.
Cash Operating Costs: Cash operating costs consist of operating costs and expenses, production and severance taxes and E&P general and administrative expenses. Cash operating costs increased in 2024, compared to 2023, primarily due to Guyana following the start-up of Payara in November 2023 partially offset by lower FPSO lease payments following the purchase of the Liza Unity in November 2023, increased maintenance activity in North Dakota, and start-up of the Pickerel well (Hess 100%) in June 2024. On a per-unit basis, the decrease in cash operating costs in 2024, compared to 2023, primarily reflects the impact of the higher production volumes.
Midstream Tariffs Expense: Tariffs expense increased in 2024, compared to 2023, primarily due to higher throughput volumes. We estimate Midstream tariffs expense to be in the range of $350 million to $360 million in the first quarter of 2025.
DD&A Expense: DD&A expense was higher in 2024, compared to 2023, primarily due to higher production volumes from Guyana following the start-up of Payara in November 2023, and start-up of the Pickerel well (Hess 100%) in June 2024.
Unit Costs: Unit cost per boe information is based on total E&P net production volumes and excludes items affecting comparability of earnings as disclosed on page 40. Actual and forecast unit costs per boe are as follows:
Actual Forecast range
Twelve Months Ended December 31, Three Months Ended March 31,
2024 2023 2022 2025
Cash operating costs (a) $ 12.31 $ 13.57 $ 13.28 $ 12.50 - $ 13.00
DD&A expense (b) 12.96 12.89 12.13 13.50 - 13.50
Total Production Unit Costs $ 25.27 $ 26.46 $ 25.41 $ 26.00 - $ 26.50
(a)Cash operating costs per boe, excluding Libya, were $13.77 in 2022.
(b)DD&A expense per boe, excluding Libya, was $12.59 in 2022.
Exploration Expenses: Exploration expenses, including items affecting comparability of earnings described below, were as follows:
2024 2023 2022
(In millions)
Exploratory dry hole costs (a) $ 159 $ 147 $ 56
Exploration lease impairment 22 27 20
Geological and geophysical expense and exploration overhead 145 143 132
$ 326 $ 317 $ 208
(a)Exploratory dry hole costs in 2024 primarily relates to the Vancouver-1 well in the Gulf of America, previously capitalized exploratory wells (see Items Affecting Comparability of Earnings Between Periods on page 40) and the Trumpetfish-1 exploration well at the Stabroek Block, offshore Guyana. In 2023, dry hole costs primarily related to the Ephesus exploration well, offshore Newfoundland, Canada, the Kokwari-1 and Fish/Tarpon-1 exploration wells at the Stabroek Block, offshore Guyana, and the write-off of a previously capitalized exploratory well (see Items Affecting Comparability of Earnings Between Periods on page 40). Dry hole costs in 2022 primarily related to the Fish/Tarpon-1 well and Banjo-1 well at the Stabroek Block, offshore Guyana.
Exploration expenses, excluding dry hole expense, are estimated to be in the range of $60 million to $65 million in the first quarter of 2025.
Income Taxes: In 2024, E&P income tax expense was $1,130 million compared to $695 million in 2023. The increase in income tax expense in 2024 compared to 2023 was primarily due to higher income tax expense in Guyana as a result of higher pre-tax income.
We are generally not recognizing deferred tax benefit or expense in certain countries, primarily the United States (non-Midstream), while we maintain valuation allowances against net deferred tax assets in these jurisdictions in accordance with GAAP. As of December 31, 2024, we have a valuation allowance in our Consolidated Balance Sheet of $3,719 million, primarily related to the U.S. (non-Midstream) which is in a cumulative loss position.
Actual effective tax rates are as follows:
2024 2023 2022
% % %
Effective income tax benefit (expense) rate (29) (30) (31)
Adjusted effective income tax benefit (expense) rate (a) (28) (30) (19)
(a)Excludes any contribution from Libya, sold in November 2022, and items affecting comparability of earnings.
E&P income tax expense, excluding items affecting comparability of earnings, is expected to be in the range of $260 million to $270 million in the first quarter of 2025.
Items Affecting Comparability of Earnings Between Periods: Reported E&P earnings include the following items affecting comparability of income (expense):
Before Income Taxes After Income Taxes
2024 2023 2022 2024 2023 2022
(In millions)
Impairment $ (132) $ (82) $ (54) $ (130) $ (82) $ (54)
JDA non-renewal of PSC (66) - - (52) - -
Pension plan amendment (35) - - (32) - -
Dry hole expenses
- (52) - - (52) -
Gains on asset sales, net - - 76 - - 76
Release of deferred tax asset valuation allowance - - - - 33 -
$ (233) $ (134) $ 22 $ (214) $ (101) $ 22
The pre-tax amounts of E&P items affecting comparability of income (expense) as presented in the Statement of Consolidated Income are as follows:
Before Income Taxes
2024 2023 2022
(In millions)
Gains on asset sales, net $ - $ - $ 76
Other, net (35) - -
Operating costs and expenses (18) - -
Exploration expenses, including dry holes and lease impairment (48) (52) -
Impairment (132) (82) (54)
$ (233) $ (134) $ 22
2024:
•Impairment: We recorded a pre-tax charge of $92 million ($92 million after income taxes) to fully impair the net book value of our interests in Conger, a mature field in the Gulf of America, due to a mechanical issue on one of the main producing wells, and a pre-tax charge of $40 million ($38 million after income taxes) resulting from revisions to our estimated abandonment liabilities for uneconomic properties, primarily in the Gulf of America. See Note 12, Impairment in the Notes to Consolidated Financial Statements.
•JDA non-renewal of PSC: We recorded a pre-tax charge of $48 million ($38 million after income taxes) to write-off previously capitalized exploration wells (See Note 3, Property, Plant and Equipment in the Notes to Consolidated Financial Statements), and a pre-tax charge of $18 million ($14 million after income taxes) related to materials and supplies inventory recorded to Operating costs and expenses in the Statement of Consolidated Income, both in the JDA, based on the regulator’s notification that the current PSC for JDA Block A-18 will not be re-awarded to the existing PSC contractors upon its expiration in 2029.
•Pension plan amendment: We recorded a pre-tax charge of $35 million ($32 million after income taxes), included in Other, net in the Statement of Consolidated Income, resulting from amendments to the Corporation’s pension plan in the United Kingdom, associated with the purchase of a bulk annuity policy as part of the ongoing process to settle the plan’s liabilities. See Note 9, Retirement Plans in the Notes to Consolidated Financial Statements.
2023:
•Dry hole expenses: We recorded a pre-tax charge of $52 million ($52 million after income taxes) to write-off the Huron-1 exploration well in the Gulf of America, which was completed in 2022, based on the decision by the Corporation and its partners in the fourth quarter of 2023 to exit the project.
•Impairment: We recorded a pre-tax charge of $82 million ($82 million after income taxes) that resulted from revisions to our estimated abandonment obligations in the West Delta Field in the Gulf of America. These abandonment obligations were assigned to us as a former owner after they were discharged from Fieldwood Energy LLC as part of its approved bankruptcy plan in 2021. See Note 12, Impairment in the Notes to Consolidated Financial Statements.
•Release of deferred tax asset valuation allowance: We recorded a noncash income tax benefit of $33 million, which resulted from the reversal of a valuation allowance against net deferred tax assets in Malaysia.
2022:
•Gains on asset sales, net: We recognized a pre-tax gain of $76 million ($76 million after income taxes) associated with the sale of our interest in the Waha Concession in Libya.
•Impairment: We recorded charges of $28 million ($28 million after income taxes) that resulted from updates to our estimated abandonment liabilities for non-producing properties in the Gulf of America and $26 million ($26 million after income taxes) related to the Penn State Field in the Gulf of America. See Note 12, Impairment in the Notes to Consolidated Financial Statements.
Midstream
Following is a summarized statement of income for our Midstream operations:
2024 2023 2022
(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues $ 1,495 $ 1,349 $ 1,273
Other, net 16 8 8
Total revenues and non-operating income 1,511 1,357 1,281
Costs and Expenses
Operating costs and expenses 347 313 280
General and administrative expenses 26 26 23
Interest expense 204 179 150
Depreciation, depletion and amortization 203 193 181
Total costs and expenses 780 711 634
Results of Operations Before Income Taxes 731 646 647
Provision for income taxes 72 38 27
Net income 659 608 620
Less: Net income attributable to noncontrolling interests 383 356 351
Net Income Attributable to Hess Corporation $ 276 $ 252 $ 269
Sales and other operating revenues increased from 2023 primarily due to higher throughput volumes. Operating costs and expenses increased from 2023 primarily as a result of the higher throughput volumes. Interest expense increased from 2023 primarily due to the new $600 million 6.500% fixed-rate senior unsecured notes issued during the second quarter of 2024. DD&A expense increased from 2023 primarily due to additional assets placed in service. Provision for income taxes increased from 2023 primarily driven by increased ownership of HESM Opco by Hess Midstream LP following the equity offerings and unit repurchase transactions in 2023 and 2024.
Net income attributable to Hess Corporation from the Midstream segment is estimated to be approximately $70 million in the first quarter of 2025.
Corporate, Interest and Other
The following table summarizes Corporate, Interest and Other expenses:
2024 2023 2022
(In millions)
Corporate and other expenses (excluding items affecting comparability) $ 79 $ 103 $ 124
Interest expense 340 347 353
Less: Capitalized interest (132) (48) (10)
Interest expense, net 208 299 343
Corporate, Interest and Other expenses before income taxes 287 402 467
Provision for income taxes - - -
Corporate, Interest and Other expenses after income taxes 287 402 467
Items affecting comparability of earnings between periods, after income taxes - 69 102
Net Corporate, Interest and Other expenses after income taxes $ 287 $ 471 $ 569
Corporate and other expenses, excluding items affecting comparability, were lower in 2024 compared to 2023 primarily due to lower legal fees and other general and administrative expenses, partially offset by lower interest income. Interest expense, net was lower in 2024 compared to 2023 primarily due to higher capitalized interest associated with the Yellowtail, Uaru, and Whiptail development projects in Guyana.
First quarter 2025 corporate and other expenses, excluding items affecting comparability, are expected to be approximately $40 million, and interest expense, net is expected to be in the range of $35 million to $40 million.
Items Affecting Comparability of Earnings Between Periods: Corporate, Interest and Other results included the following items affecting comparability of income (expense):
2023:
•Litigation costs: We incurred pre-tax charges totaling $52 million ($52 million after income taxes) for litigation related costs associated with our former downstream business, HONX, Inc., which are included in General and administrative expenses in the Statement of Consolidated Income.
•Pension settlement: We recorded a noncash charge to recognize unamortized actuarial losses of $17 million ($17 million after income taxes) resulting from the payment of lump sums to certain participants in the Hess Corporation Employees’ Pension Plan. The charge is included in Other, net in the Statement of Consolidated Income. See Note 9, Retirement Plans in the Notes to Consolidated Financial Statements.
2022:
•Gains on asset sales, net: We recorded a pre-tax gain of $22 million ($22 million after income taxes) associated with the sale of real property related to our former downstream business.
•Litigation costs: We incurred pre-tax charges totaling $124 million ($124 million after income taxes) for litigation related costs associated with our former downstream business, HONX, Inc., which are included in General and administrative expenses in the Statement of Consolidated Income.
Liquidity and Capital Resources
The following table sets forth certain relevant measures of our liquidity and capital resources at December 31:
2024 2023
(In millions, except ratio)
Cash and cash equivalents (a) $ 1,171 $ 1,688
Current portion of long-term debt 23 311
Total debt (b) 8,578 8,613
Total equity 12,003 9,602
Debt to capitalization ratio for debt covenants (c) 28.3 % 33.6 %
(a)Includes $5 million of cash attributable to our Midstream segment at December 31, 2024 (2023: $6 million) of which, $4 million is held by Hess Midstream LP at December 31, 2024 (2023: $5 million).
(b)Includes $3,472 million of debt outstanding from our Midstream segment at December 31, 2024 (2023: $3,211 million) that is non-recourse to Hess Corporation.
(c)Total Consolidated Debt of Hess Corporation (including finance leases and excluding Midstream non-recourse debt) as a percentage of Total Capitalization of Hess Corporation as defined under Hess Corporation’s revolving credit facility financial covenants. Total Capitalization excludes the impact of noncash impairment charges and non-controlling interests. See Note 7, Debt in the Notes to Consolidated Financial Statements.
Cash Flows
The following table sets forth a summary of our cash flows:
2024 2023 2022
(In millions)
Net cash provided by (used in):
Operating activities $ 5,600 $ 3,942 $ 3,944
Investing activities (4,937) (4,113) (2,555)
Financing activities (1,180) (627) (1,616)
Net Increase (Decrease) in Cash and Cash Equivalents $ (517) $ (798) $ (227)
Operating Activities: Net cash provided by operating activities was $5,600 million in 2024 (2023: $3,942 million), while net cash provided by operating activities before changes in operating assets and liabilities was $6,353 million in 2024 (2023: $4,494 million). Net cash provided by operating activities before changes in operating assets and liabilities increased from 2023 primarily due to higher production volumes. Changes in operating assets and liabilities in 2024 reduced cash flow from operating activities by $753 million primarily due to payments for abandonment activities, the purchase of REDD+ carbon credits in accordance with our long-term agreement with the Government of Guyana, and a payment in connection with a legal settlement related to our former downstream business, HONX, Inc. Changes in operating assets and liabilities in 2023 reduced net cash provided by operating activities by $552 million primarily due to premiums paid for crude oil hedge contracts and payments for abandonment activities.
Investing Activities: Additions to Property, Plant and Equipment were $4,946 million in 2024 (2023: $4,108 million). The increase is primarily due to higher development activities in Guyana and higher drilling activity in the Gulf of America and the Bakken. 2024 Additions to Property, Plant and Equipment included the purchases of the Liza Destiny and Prosperity FPSOs for approximately $635 million, while 2023 Additions to Property, Plant and Equipment included the purchase of the Liza Unity FPSO for approximately $380 million.
Financing Activities: Common stock dividends paid were $579 million in 2024 (2023: $539 million) reflecting a 14% increase in our dividend on common stock commencing in the third quarter of 2024.
Net borrowings (repayments) of debt with maturities of 90 days or less related to the HESM Opco revolving credit facility. In 2023, the proceeds from the HESM Opco revolving credit facility were used primarily to finance the repurchase of HESM Opco Class B units. Borrowings in 2024 resulted from the issuance by HESM Opco of $600 million of 6.500% fixed-rate senior unsecured notes due in 2029, and the proceeds were primarily used to reduce debt outstanding under HESM Opco’s revolving credit facility. Repayments of debt in 2024 primarily resulted from the $300 million principal amount of our 3.500% fixed-rate senior unsecured notes, which matured on July 15, 2024. Net cash outflows to noncontrolling interests were $551 million in 2024 (2023: $550 million) which included $187 million paid to GIP for the repurchase by HESM Opco of GIP-owned Class B units (2023: $212 million). In 2023, we received net proceeds of $167 million from the public offering of Class A shares in Hess Midstream LP.
Future Capital Requirements and Resources
At December 31, 2024, we had $1.17 billion in cash and cash equivalents, excluding Midstream, and total liquidity, including available committed credit facilities, of approximately $4.5 billion. In 2025, based on current forward strip crude oil prices, we expect cash flow from operating activities and cash and cash equivalents at December 31, 2024 will be sufficient to fund our capital investment and capital return programs. Depending on market conditions, we may take any of the following steps, or a combination thereof, to improve our liquidity and financial position: reduce the planned capital program and other cash outlays, including dividends, pursue asset sales, borrow against our committed revolving credit facility, or issue debt or equity securities. These actions are subject to certain limitations under the Merger Agreement. See Part I, Item 1A. Risk Factors for a discussion of risks related to the Merger.
The table below summarizes the capacity, usage, and available capacity of our borrowing and letter of credit facilities at December 31, 2024:
Expiration Date Capacity Borrowings Letters of
Credit
Issued Total
Used Available
Capacity
(In millions)
Hess Corporation
Revolving credit facility July 2027 $ 3,250 $ - $ - $ - $ 3,250
Committed lines Various (a) 75 - 8 8 67
Uncommitted lines Various (a) 77 - 77 77 -
Total - Hess Corporation $ 3,402 $ - $ 85 $ 85 $ 3,317
Midstream
Revolving credit facility (b) July 2027 $ 1,000 $ 15 $ - $ 15 $ 985
Total - Midstream $ 1,000 $ 15 $ - $ 15 $ 985
(a)Committed and uncommitted lines have expiration dates through 2025.
(b)This credit facility may only be utilized by HESM Opco and is non-recourse to Hess Corporation.
Hess Corporation
The revolving credit facility can be used for borrowings and letters of credit. Borrowings on the facility will generally bear interest at 1.400% above SOFR, though the interest rate is subject to adjustment based on the credit rating of the Corporation’s senior, unsecured, non-credit enhanced long-term debt. The revolving credit facility is subject to customary representations, warranties, customary events of default and covenants, including a financial covenant limiting the ratio of Total Consolidated Debt to Total Capitalization of the Corporation and its consolidated subsidiaries to 65%, and a financial covenant limiting the ratio of secured debt to Consolidated Net Tangible Assets of the Corporation and its consolidated subsidiaries to 15% (as these capitalized terms are defined in the credit agreement for the revolving credit facility). The indentures for the Corporation’s fixed-rate senior unsecured notes limit the ratio of secured debt to Consolidated Net Tangible Assets (as that term is defined in the indentures) to 15%. As of December 31, 2024, Hess Corporation was in compliance with these financial covenants. The most restrictive of the financial covenants relating to our fixed-rate senior unsecured notes and our revolving credit facility would allow us to borrow up to an additional $3,226 million of secured debt at December 31, 2024.
We have a shelf registration under which we may issue additional debt securities, warrants, common stock or preferred stock.
Midstream
At December 31, 2024, HESM Opco had $1.4 billion of senior secured syndicated credit facilities, consisting of a $1.0 billion revolving credit facility and a $400 million term loan facility. Borrowings under the term loan facility will generally bear interest at SOFR plus an applicable margin ranging from 1.650% to 2.550%, while the applicable margin for the syndicated revolving credit facility ranges from 1.375% to 2.050%. Pricing levels for the facility fee and interest-rate margins are based on HESM Opco’s ratio of total debt to EBITDA (as defined in the credit facilities). If HESM Opco obtains an investment grade credit rating, the pricing levels will be based on HESM Opco’s credit ratings in effect from time to time. The credit facilities contain covenants that require HESM Opco to maintain a ratio of total debt to EBITDA (as defined in the credit facilities) for the prior four fiscal quarters of not greater than 5.00 to 1.00 as of the last day of each fiscal quarter (5.50 to 1.00 during the specified period following certain acquisitions) and, prior to HESM Opco obtaining an investment grade credit rating, a ratio of secured debt to EBITDA for the prior four fiscal quarters of not greater than 4.00 to 1.00 as of the last day of each fiscal quarter. HESM Opco was in compliance with these financial covenants at December 31, 2024. 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, 2024, borrowings of $15 million were drawn under HESM Opco’s revolving credit facility, and borrowings of $385 million, excluding deferred issuance costs, were drawn under HESM Opco’s term loan facility. Borrowings under these credit facilities are non-recourse to Hess Corporation.
Credit Ratings
All three major credit rating agencies that rate the senior unsecured debt of Hess Corporation have assigned an investment grade credit rating. At December 31, 2024, our credit ratings were BBB- at S&P Global Ratings, Baa3 at Moody’s Investors Service, and BBB at Fitch Ratings. Subsequent to the announcement of the Merger all three agencies placed our credit ratings on review for positive action in connection with the Merger.
At December 31, 2024, HESM Opco’s senior unsecured debt is rated BB+ by S&P Global Ratings and Fitch Ratings, and Ba2 by Moody’s Investors Service.
Cash Requirements
Our cash obligations and commitments over the next twelve months include accounts payable, accrued liabilities, the current portion of long-term debt, interest, lease payments, and purchase obligations which cover a portion of our planned capital expenditure program in 2025 and include commitments for oil and gas production expenses, carbon credits, transportation and related contracts, seismic purchases and other normal business expenses.
Our long-term cash obligations and commitments include:
•Debt and interest: See Note 7, Debt in the Notes to Consolidated Financial Statements.
•Operating and finance leases: The Corporation and certain of its subsidiaries lease drilling rigs, equipment, logistical assets (offshore vessels, aircraft, and shorebases), and office space for varying periods. See Note 6, Leases in the Notes to Consolidated Financial Statements.
•Purchase obligations: We were contractually committed at December 31, 2024 for certain long-term capital expenditures and operating expenses. Long-term obligations for operating expenses include commitments for oil and gas production expenses, transportation and related contracts, carbon credits, seismic purchases and other normal business expenses. See Note 17, Guarantees, Contingencies and Commitments in the Notes to Consolidated Financial Statements.
•Asset retirement obligations: See Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements.
•Post-retirement plan liabilities: We have certain unfunded post-retirement plans, including our post-retirement medical plan. See Note 9, Retirement Plans in the Notes to Consolidated Financial Statements.
•Uncertain income tax positions: See Note 14, Income Taxes in the Notes to Consolidated Financial Statements.
Off-Balance Sheet Arrangements
See Note 17, Guarantees, Contingencies and Commitments in the Notes to Consolidated Financial Statements.
Foreign Operations
We conduct E&P activities outside the U.S., principally in Guyana, the Joint Development Area of Malaysia/Thailand, Malaysia, and Suriname. Therefore, we are subject to the risks associated with foreign operations. See Part 1, Item 1A. Risk Factors for further details.
Critical Accounting Policies and Estimates
Accounting policies and estimates affect the recognition of assets and liabilities in the Consolidated Balance Sheet and revenues and expenses in the Statement of Consolidated Income. The accounting methods used can affect net income, equity and various financial statement ratios. However, our accounting policies generally do not change cash flows or liquidity.
Accounting for Exploration and Development Costs: E&P activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized.
The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of the project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves, and the economic and operating viability of a project include: commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors and firm plans for additional drilling and other factors.
Crude Oil and Natural Gas Reserves: The determination of estimated proved reserves is a significant element in arriving at the results of operations of E&P activities. The estimates of proved reserves affect well capitalization, the unit of production depreciation rates of proved properties and wells and equipment, as well as impairment testing of oil and gas assets.
For reserves to be booked as proved they must be determined with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. In addition, government and project operator approvals must be obtained and, depending on the amount of the project cost, senior management or the Board of
Directors must commit to fund the project. We maintain our own internal reserve estimates that are calculated by technical staff that work directly with the oil and gas properties. Our technical staff update reserve estimates throughout the year based on evaluations of new wells, performance reviews, new technical data and other studies. To provide consistency throughout the Corporation, standard reserve estimation guidelines, definitions, reporting reviews and approval practices are used. The internal reserve estimates are subject to internal technical audits and senior management review. We also engage an independent third-party consulting firm to audit approximately 80% of our total proved reserves each year.
Proved reserves are calculated using the average price during the twelve-month period ending December 31 determined as an unweighted arithmetic average of the price on the first day of each month within the year, unless prices are defined by contractual agreements, excluding escalations based on future conditions. As discussed in Part 1, Item 1A. Risk Factors, crude oil prices are volatile which can have an impact on our proved reserves. Crude oil prices used in the determination of proved reserves at December 31, 2024 were $74.88 per barrel for WTI (2023: $78.10) and $78.81 per barrel for Brent (2023: $82.51). At December 31, 2024, spot prices closed at $71.72 per barrel for WTI and $74.64 per barrel for Brent. If crude oil prices in 2025 are at levels below that used in determining 2024 proved reserves, we may recognize negative revisions to our December 31, 2025 proved undeveloped reserves. In addition, we may recognize negative revisions to proved developed reserves, which can vary significantly by asset due to differing operating cost structures. Conversely, price increases in 2025 above those used in determining 2024 proved reserves could result in positive revisions to proved developed and proved undeveloped reserves at December 31, 2025. It is difficult to estimate the magnitude of any potential net negative or positive change in proved reserves at December 31, 2025, due to numerous currently unknown factors, including 2025 crude oil prices, the amount of any additions to proved reserves, positive or negative revisions in proved reserves related to 2025 reservoir performance, the levels to which industry costs will change in response to 2025 crude oil prices, and management’s plans as of December 31, 2025 for developing proved undeveloped reserves. A 10% change in proved developed and proved undeveloped reserves at December 31, 2024 would result in an approximate $230 million pre-tax change in depreciation, depletion, and amortization expense for 2025 based on projected production volumes. See the Supplementary Oil and Gas Data on pages 93 through 102 in the accompanying financial statements for additional information on our oil and gas reserves.
Impairment of Long-lived Assets: We review long-lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. Long-lived assets are tested based on identifiable cash flows that are largely independent of the cash flows of other assets and liabilities. If the carrying amounts of the long-lived assets are not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is 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 stipulated 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, since the standardized measure requires the use of historical twelve-month average prices.
Our impairment tests of long-lived E&P producing assets are based on our best estimates of future production volumes (including recovery factors), selling prices, operating and capital costs, the timing of future production and other factors, which are updated each time an impairment test is performed. We could experience an impairment in the future if one or a combination of the following occur: the projected production volumes from oil and gas fields decrease, crude oil and natural gas selling prices decline significantly for an extended period or future estimated capital and operating costs increase significantly.
Hess Midstream LP: We consolidate the activities of our interest in Hess Midstream LP, which qualifies as a variable interest entity (VIE) under U.S. generally accepted accounting principles. We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power through Hess Corporation’s approximate 38% consolidated ownership interest in Hess Midstream LP to direct those activities that most significantly impact the economic performance of Hess Midstream LP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to Hess Midstream LP. 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.
Income Taxes: Judgments are required in the determination and recognition of income tax assets and liabilities in the financial statements. These judgments include the requirement to recognize the financial statement effect of a tax position only when management believes it is more likely than not, based on the technical merits, that the position will be sustained upon examination.
We have net operating loss carryforwards or credit carryforwards in multiple jurisdictions and have recognized deferred tax assets for those losses and credits. Additionally, we have deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If,
when tested under the relevant accounting standards, it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is established to reduce the deferred tax assets to the amount that is expected to be realized.
The accounting standards require the evaluation of all available positive and negative evidence giving weight based on the evidence’s relative objectivity. In evaluating potential sources of positive evidence, we consider the reversal of taxable temporary differences, taxable income in carryback and carryforward periods, the availability of tax planning strategies, the existence of appreciated assets, estimates of future taxable income, and other factors. Estimates of future taxable income are based on assumptions of oil and gas reserves, selling prices, and other subjective operating assumptions that are consistent with internal business forecasts. In evaluating potential sources of negative evidence, we consider a cumulative loss in recent years, any history of operating losses or tax credit carryforwards expiring unused, losses expected in early future years, unsettled circumstances that, if unfavorably resolved, would adversely affect future operations and profit levels on a continuing basis in future years, and any carryback or carryforward period so brief that a significant deductible temporary difference expected to reverse in a single year would limit realization of tax benefits. A recent cumulative loss constitutes objective negative evidence to which the accounting standards require we assign significant weight relative to subjective evidence such as our estimates of future taxable income. We are generally not recognizing deferred tax benefit or expense in certain countries, primarily the U.S. (non-Midstream) while we maintain valuation allowances against net deferred tax assets in these jurisdictions.
At December 31, 2024, the Consolidated Balance Sheet reflects a $3,719 million valuation allowance against the net deferred tax assets for multiple jurisdictions based on the evaluation of the accounting standards described above. The amount of the deferred tax asset considered realizable, however, could be adjusted if objective negative evidence in the form of cumulative losses is no longer present and additional weight can be given to subjective evidence. At December 2024, the U.S. (non-Midstream) is in a cumulative loss position. Until we see a significant and sustained pattern of objectively verifiable income, we do not assign significant weight to subjective long-term projections of future income and thus maintain a full valuation allowance against our U.S. (non-Midstream) federal and state deferred tax assets. If anticipated future earnings are exceeded, sufficient positive evidence may become available to support the release of valuation allowance in the future. This would result in the recognition of certain deferred tax assets on the balance sheet and a decrease to income tax expense for the period in which the release is recorded.
Asset Retirement Obligations: We have legal obligations to remove and dismantle long-lived assets and to restore land or seabed at certain E&P locations. In accordance with generally accepted accounting principles, we recognize a liability for the fair value of required asset retirement obligations. In addition, the fair value of any legally required conditional asset retirement obligation is recorded if the liability can be reasonably estimated. We capitalize such costs as a component of the carrying amount of the underlying assets in the period in which the liability is incurred. In subsequent periods, the liability is accreted, and the asset is depreciated over the useful life of the related asset. We estimate the fair value of these obligations by discounting projected future payments that will be required to satisfy the obligations. In determining these estimates, we are required to make several assumptions and judgments related to the scope of dismantlement, timing of settlement, interpretation of legal requirements, inflationary factors and discount rate. In addition, there are other external factors, which could significantly affect the ultimate settlement costs or timing for these obligations including changes in environmental regulations and other statutory requirements, fluctuations in industry costs and foreign currency exchange rates and advances in technology. As a result, our estimates of asset retirement obligations are subject to revision due to the factors described above. Changes in estimates prior to settlement result in adjustments to both the liability and related asset values, unless the field has ceased production, in which case changes are recognized in our Statement of Consolidated Income. See Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements.
Retirement Plans: We have funded non-contributory defined benefit pension plans, an unfunded supplemental pension plan and an unfunded postretirement medical plan. We recognize the net change in the funded status of the projected benefit obligation for these plans in the Consolidated Balance Sheet. The determination of the obligations and expenses related to these plans are based on several actuarial assumptions. These assumptions represent estimates made by us, some of which can be affected by external factors. The most significant assumptions relate to:
Discount rates used for measuring the present value of future plan obligations and net periodic benefit cost: The discount rates used to estimate our projected benefit obligations and net periodic benefit cost is based on a portfolio of high-quality, fixed income debt instruments with maturities that approximate the expected payment of plan obligations. At December 31, 2024, a 0.25% decrease in the discount rate assumptions would increase projected benefit obligations by approximately $65 million and would increase forecasted 2025 annual net periodic benefit expense by approximately $2 million. The increase in the projected benefit obligations would decrease the funded status of our pension plans, but any decrease in the funded status would be partially mitigated by increases in the fair value of fixed income investments in the asset portfolios.
Expected long-term rates of returns on plan assets: The expected rate of return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of plan assets to that asset category. The future expected rate of return assumptions for individual asset categories are largely based on inputs from various investment experts regarding their future return expectations for particular asset categories. At December 31, 2024, a 0.25% decrease in the expected long-term rates of return on plan assets assumption would increase forecasted 2025 annual net periodic benefit expense by approximately $5 million.
Other assumptions include the rate of future increases in compensation levels and expected participant mortality.
Derivatives: We utilize derivative instruments, including futures, forwards, options and swaps, individually or in combination to mitigate our exposure to fluctuations in the prices of crude oil and natural gas, as well as changes in interest and foreign currency exchange rates. All derivative instruments are recorded at fair value in our Consolidated Balance Sheet. Our policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not designated as hedges are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges), or hedges of changes in fair value of recognized assets and liabilities or of unrecognized firm commitments (fair value hedges). Changes in fair value of derivatives that are designated as cash flow hedges are recorded as a component of Other Comprehensive Income (Loss). Amounts included in Accumulated Other Comprehensive Income (Loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged 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 generally accepted accounting principles. These fair value measurements are recorded in connection with business combinations, qualifying non-monetary exchanges, the initial recognition of asset retirement obligations and any impairment of long-lived assets, equity method investments or goodwill.
We determine fair value in accordance with the fair value measurements accounting standard which established a hierarchy for the inputs used to measure fair value based on the source of the inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3), including discounted cash flows and other unobservable data. Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market. Multiple inputs 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.
Environment, Health and Safety
Our long-term vision and values provide a foundation for how we do business and define our commitment to meeting high standards of corporate citizenship and creating a positive impact on the communities where we do business. Our strategy is reflected in our EHS & SR policies and by a management system framework that helps protect our workforce, customers and local communities. Our management systems are intended to promote internal consistency, adherence to policy objectives and continual improvement in EHS & SR performance. Improved performance may, in the short-term, increase our operating costs and could also require increased capital expenditures to reduce potential risks to our assets, reputation and license to operate. In addition to enhanced EHS & SR performance, improved productivity and operational efficiencies may be realized from investments in EHS & SR. We have programs in place to evaluate regulatory compliance, audit facilities, train employees, prevent and manage risks and emergencies and to generally meet corporate EHS & SR goals and objectives.
Environmental Matters
We recognize that climate change is a global environmental concern. We assess, monitor and take measures to reduce our carbon footprint at existing and planned operations. The EPA has adopted a series of GHG monitoring, reporting, and emissions control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting further legislation to reduce GHG emissions. For example, in March 2024, the EPA published a final rule in the Federal Register to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. In addition, the IRA includes a methane emissions reduction program for petroleum and natural gas systems, which requires the EPA to impose a “waste emissions charge” on excess methane emissions from certain natural gas and oil sources that are required to report under EPA’s Greenhouse Gas Reporting Program. In November 2024, the EPA finalized a rule to implement Congress’ directive in the IRA to impose a fee on excess methane emissions from the oil and gas sector. Furthermore, states have taken measures to reduce emissions of GHGs, primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs. In addition, New York and Vermont enacted legislation in 2024 that seeks to impose retroactive strict liability on certain companies engaged in the extraction and refining of oil and gas for the funding of state climate adaptation funds. Other states are considering enacting similar measures. At the international level, the Paris Agreement on climate change adopted in 2015 aimed to enhance global response to global temperature changes and to reduce GHG emissions, among other things, which has been reaffirmed by subsequent United Nations Climate Change Conferences, although in January 2025, President Trump signed an executive order to withdraw the U.S. from the Paris Agreement.
We are committed to complying with all GHG emissions regulations that apply to our operations, including those related to venting or flaring of natural gas, and the responsible management of GHG emissions at our facilities. While we monitor climate-related regulatory initiatives and international public policy issues, the current state of ongoing international climate initiatives and any related domestic actions make it difficult to assess the timing or effect on our operations or to predict with certainty the future costs that we may incur in order to comply with future international treaties, legislation or new regulations. However, future restrictions on emissions of GHGs, or related measures to encourage use of low carbon energy could result in higher capital expenditures and operating expenses for us and the oil and gas industry in general and may reduce demand for our products, as described under Regulatory, Legal and Environmental Risks in Part 1, Item 1A. Risk Factors.
We will have continuing expenditures for environmental assessment and remediation. Sites where corrective action may be necessary include E&P facilities, sites from discontinued operations where we retained liability and, although not currently significant, EPA “Superfund” sites where we have been named a potentially responsible party. We accrue for environmental assessment and remediation expenses when the future costs are probable and reasonably estimable. For additional information, see Item 3. Legal Proceedings. At December 31, 2024, our reserve for estimated remediation liabilities was $35 million. We expect that existing reserves for environmental liabilities will adequately cover costs to assess and remediate known sites. Our remediation spending was $17 million in 2024 (2023: $28 million; 2022: $23 million). The amount of other expenditures incurred to comply with federal, state, local and foreign country environmental regulations is difficult to quantify as such costs are captured as mostly indistinguishable components of our capital expenditures and operating expenses.
As an element of our EHS and SR strategy, we purchase carbon credits annually to offset 100 percent of our estimated Scope 3 business travel emissions and 100 percent of our estimated Scope 1 and Scope 3 emissions associated with operating the Corporation’s truck fleet, aviation activities (aircraft and helicopters) and personal and rental vehicle miles driven on company business. We also offset purchased electricity used in our operations from nonrenewable sources by purchasing renewable energy certificates. The cost of these purchased and retired renewable energy certificates was not material to our financial results in 2024 and are included in Operating costs and expenses in the Statement of Consolidated Income.
In December 2022, we announced an agreement with the Government of Guyana to purchase 37.5 million REDD+ carbon credits, including current and future issuances, for a minimum of $750 million from 2022 through 2032 to prevent deforestation and support sustainable development in Guyana. These credits will be on the ART Registry and will be independently verified to represent permanent and additional emissions reductions under ART’s REDD+ Environmental Standard 2.0 (TREES). This agreement adds to the Corporation’s ongoing emissions reduction efforts and is an important part of our commitment to achieve net zero Scope 1 and 2 greenhouse gas emissions on an equity basis by 2050. As of December 31, 2024, we have purchased 15 million REDD+ carbon credits registered on the ART Registry for $238 million under this agreement, which is included in non-current Other assets in the Consolidated Balance Sheet.
Health and Safety Matters
The crude oil and natural gas industry is regulated at federal, state, local and foreign government levels regarding the health and safety of E&P operations. Such laws and regulations relate to, among other matters, occupational safety, the use of hydraulic fracturing to stimulate crude oil and natural gas production, well control and integrity, process safety and equipment integrity, and may include permitting and disclosure requirements, operating restrictions and other conditions on the development of crude oil and natural gas. The level of our expenditures to comply with federal, state, local and foreign country health and safety regulations is difficult to quantify as such costs are captured as mostly indistinguishable components of our capital expenditures and operating expenses. While compliance with laws and regulations relating to health and safety matters increases the overall cost of business for us and the oil and gas industry in general, it has not had, to date, a material adverse effect on our operations, financial condition or results of operations.
Occupational Safety: We are subject to the requirements set forth under federal workplace standards by the OSHA and comparable state statutes that regulate the protection of the health and safety of workers. Under OSHA and other federal and state occupational safety and health laws and laws of foreign countries in which we operate, we must develop, maintain and disclose certain information about hazardous materials used, released, or produced in our operations.
Production and Well Integrity: Our U.S. onshore production facilities are subject to U.S. federal government, state and local regulations regarding the use of hydraulic fracturing and well control and integrity. Our offshore production facilities in the Gulf of America are subject to the U.S. federal government’s Safety and Environmental Management System regulations, which provide a systematic approach for identifying, managing and mitigating hazards. Adapting to new technical standards and procedures in production and in our well integrity management system is fundamental to our aim of protecting the environment as well as the health and safety of our workforce and the communities in which we operate, and to safeguarding our product.
Process Safety and Equipment Integrity: We are also regulated at federal, state, local and foreign government levels regarding process safety and the integrity of our equipment, including OSHA’s Process Safety Management of Highly Hazardous Chemicals standard. ICE are barriers and safeguards that prevent or mitigate process safety incidents through detection, isolation, containment, control or emergency preparedness and response within our facilities. We have established ICE performance standards, which set specific requirements and criteria for inspections and tests that help to ensure ICE barriers are effective. We conduct assessments
collaboratively with our operated assets, subject matter experts and technical authorities to evaluate compliance with corporate and asset environment, health and safety standards and procedures, as well as with applicable regulations. For additional information on our emergency response and incident mitigation activities, see Emergency Preparedness and Response Plans and Procedures in Items 1 and 2. Business and Properties.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
In the normal course of our business, we are exposed to commodity risks related to changes in the prices of crude oil, NGL, and natural gas as well as changes in interest rates and foreign currency values. In the disclosures that follow, financial risk management activities refer to the mitigation of these risks through hedging activities.
Controls: We maintain a control environment under the direction of our Chief Risk Officer. Controls over instruments used in financial risk management activities include volumetric and term limits. Our Treasury department is responsible for administering and monitoring foreign exchange rate and interest rate hedging programs using similar controls and processes, where applicable. Hedging strategies are reviewed annually by the Audit Committee of the Board of Directors. Such strategies are subject to certain limitations under the Merger Agreement.
Instruments: We primarily use forward commodity contracts, foreign exchange forward contracts, futures, swaps, and options in our risk management activities. These contracts are generally widely traded instruments with standardized terms. The following describes these instruments and how we use them:
•Swaps: We use financially settled swap contracts with third parties as part of our financial risk management activities. Cash flows from swap contracts are determined based on underlying commodity prices, interest rates or foreign exchange rates and are typically settled over the life of the contract.
•Forward Foreign Exchange Contracts: We enter into forward contracts, primarily for the British Pound and Malaysian Ringgit, which commit us to buy or sell a fixed amount of those currencies at a predetermined exchange rate on a future date.
•Exchange-traded Contracts: We may use exchange-traded contracts, including futures, on a number of different underlying energy commodities. These contracts are settled daily with the relevant exchange and may be subject to exchange position limits.
•Options: Options on various underlying energy commodities include exchange-traded and third-party contracts and have various exercise periods. As a purchaser of options, we pay a premium at the outset and are exposed to the favorable consequence of collecting payment upon exercise depending upon the underlying commodity price movement. As a seller of options, we receive a premium at the outset and are exposed to the unfavorable consequence of having to make payment upon exercise depending upon the underlying commodity price movement.
Financial Risk Management Activities
We have outstanding foreign exchange contracts with notional amounts totaling $189 million at December 31, 2024 that are used to reduce our exposure to fluctuating foreign exchange rates for various currencies. The change in fair value of foreign exchange contracts from a 10% strengthening or weakening in the U.S. Dollar exchange rate is estimated to be a gain or loss of approximately $20 million at December 31, 2024.
At December 31, 2024, our total long-term debt, which was substantially comprised of fixed-rate instruments, had a carrying value of $8,578 million and a fair value of $8,750 million. A 15% increase or decrease in interest rates would decrease or increase the fair value of debt by approximately $395 million or $425 million, respectively. Any changes in interest rates do not impact our cash outflows associated with fixed-rate interest payments or settlement of debt principal, unless a debt instrument is repurchased prior to maturity.
See Note 19, Financial Risk Management Activities in the Notes to Consolidated Financial Statements for further details.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
Page
Number
Management’s Report on Internal Control over Financial Reporting
Reports of Independent Registered Public Accounting Firm (PCAOB ID 42)
Consolidated Balance Sheet at December 31, 2024, and 2023
Statement of Consolidated Income for each of the Three Years in the Period Ended December 31, 2024
Statement of Consolidated Comprehensive Income for each of the Three Years in the Period Ended December 31, 2024
Statement of Consolidated Cash Flows for each of the Three Years in the Period Ended December 31, 2024
Statement of Consolidated Equity for each of the Three Years in the Period Ended December 31, 2024
Notes to Consolidated Financial Statements
Note 1 - Nature of Operations, Basis of Presentation and Summary of Accounting Policies
Note 2 - Inventories
Note 3 - Property, Plant and Equipment
Note 4 - Hess Midstream LP
Note 5 - Accrued Liabilities
Note 6 - Leases
Note 7 - Debt
Note 8 - Asset Retirement Obligations
Note 9 - Retirement Plans
Note 10 - Revenue
Note 11 - Dispositions
Note 12 - Impairment
Note 13 - Share-based Compensation
Note 14 - Income Taxes
Note 15 - Outstanding and Weighted Average Common Shares
Note 16 - Supplementary Cash Flow Information
Note 17 - Guarantees, Contingencies and Commitments
Note 18 - Segment Information
Note 19 - Financial Risk Management Activities
Note 20 - Subsequent Events
Supplementary Oil and Gas Data
Schedules have been omitted because of the absence of the conditions under which they are required or because the required information is presented in the financial statements or the notes thereto.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act, based on the framework in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2024.
The Corporation’s independent registered public accounting firm, Ernst & Young LLP, has audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31, 2024, as stated in their report, which is included herein.
By /s/ John P. Rielly By /s/ John B. Hess
John P. Rielly
Executive Vice President and
Chief Financial Officer John B. Hess
Chief Executive Officer
February 27, 2025
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of Hess Corporation
Opinion on Internal Control Over Financial Reporting
We have audited Hess Corporation and consolidated subsidiaries’ internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Hess Corporation and consolidated subsidiaries (the Corporation) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Corporation as of December 31, 2024 and 2023, the related statements of consolidated income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2024, and the related notes and our report dated February 27, 2025 expressed an unqualified opinion thereon.
Basis for Opinion
The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Houston, Texas
February 27, 2025
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of Hess Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Hess Corporation and consolidated subsidiaries (the Corporation) as of December 31, 2024 and 2023, the related statements of consolidated income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Corporation at December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Corporation’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 27, 2025 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on the Corporation’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Depreciation, depletion and amortization of proved developed oil and gas properties
Description of the
Matter
The Corporation’s Property, plant and equipment - net was $19,921 million at December 31, 2024, and Depreciation, depletion and amortization (DD&A) was $2,487 million for the year then ended. As noted in the consolidated financial statements, the Corporation follows the successful efforts method of accounting for its exploration and production activities. Under this method, depreciation and depletion expense for oil and gas production facilities and wells is calculated and recorded using the units of production method over proved developed oil and gas reserves. Proved oil and gas reserves are calculated in accordance with the Securities and Exchange Commission regulations and the requirements of the Financial Accounting Standards Board. Proved oil and gas reserves are quantities, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations.
The Corporation's DD&A expense calculation includes (i) subjective judgments by the Corporation’s geoscience and reservoir engineering professionals when developing the estimates of proved developed oil and gas reserve volumes, and (ii) a high degree of auditor judgment in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by the Corporation’s geoscience and reservoir engineering professionals and its independent petroleum engineering consulting firm (together the “Engineers”) in developing the estimates of proved developed oil and gas reserve volumes.
How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design and tested the operating effectiveness of internal controls that address the risks of material misstatement relating to the DD&A expense calculation related to the units of production method over proved developed oil and gas reserves. This included controls over the completeness and accuracy of data used by the Engineers related to historical production volumes used in estimating proved developed oil and gas reserves.
The work of the Engineers was used in performing our procedures to evaluate the reasonableness of the proved developed oil and gas reserve volumes. As a basis for using this work, the qualifications of the Engineers were understood and the Corporation’s relationship with the Engineers was assessed. Our audit procedures performed, also included, among others, i) evaluating the methods and assumptions used by the Engineers, ii) testing the completeness and accuracy of the data used by the Engineers related to historical production volumes, and iii) evaluating the Engineers findings related to estimated future production volumes.
/s/ Ernst & Young LLP
We have served as the Corporation’s auditor since 1971
Houston, Texas
February 27, 2025
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
December 31,
2024 2023
(In millions,
except share amounts)
Assets
Current Assets:
Cash and cash equivalents $ 1,171 $ 1,688
Accounts receivable:
From contracts with customers 1,274 1,180
Joint venture and other 196 150
Inventories 419 304
Other current assets 113 108
Total current assets 3,173 3,430
Property, plant and equipment:
Total - at cost 41,023 36,771
Less: Reserves for depreciation, depletion, amortization and lease impairment 21,102 19,339
Property, plant and equipment - net 19,921 17,432
Operating lease right-of-use assets - net 652 720
Finance lease right-of-use assets - net 90 108
Goodwill 360 360
Deferred income taxes 579 320
Post-retirement benefit assets 655 685
Other assets 1,121 952
Total Assets $ 26,551 $ 24,007
Liabilities
Current Liabilities:
Accounts payable $ 417 $ 402
Accrued liabilities 1,942 2,102
Taxes payable 98 85
Current portion of long-term debt 23 311
Current portion of operating and finance lease obligations 346 370
Total current liabilities 2,826 3,270
Long-term debt 8,555 8,302
Long-term operating lease obligations 404 459
Long-term finance lease obligations 132 156
Deferred income taxes 784 608
Asset retirement obligations 1,377 1,186
Other liabilities and deferred credits 470 424
Total Liabilities 14,548 14,405
Equity
Hess Corporation stockholders’ equity:
Common stock, par value $1.00; Authorized - 600,000,000 shares:
Issued - 308,293,765 shares (2023: 307,158,272)
308 307
Capital in excess of par value 6,616 6,495
Retained earnings 4,500 2,318
Accumulated other comprehensive income (loss) (208) (134)
Total Hess Corporation stockholders’ equity 11,216 8,986
Noncontrolling interests 787 616
Total equity 12,003 9,602
Total Liabilities and Equity $ 26,551 $ 24,007
The consolidated financial statements reflect the successful efforts method of accounting for oil and gas exploration and production activities.
See accompanying Notes to Consolidated Financial Statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED INCOME
Year Ended December 31,
2024 2023 2022
(In millions, except per share amounts)
Revenues and Non-Operating Income
Sales and other operating revenues $ 12,896 $ 10,511 $ 11,324
Gains on asset sales, net 1 2 101
Other, net 121 132 145
Total revenues and non-operating income 13,018 10,645 11,570
Costs and Expenses
Marketing, including purchased oil and gas 2,620 2,732 3,328
Operating costs and expenses 1,961 1,776 1,452
Production and severance taxes 234 216 255
Exploration expenses, including dry holes and lease impairment 326 317 208
General and administrative expenses 492 527 531
Interest expense 412 478 493
Depreciation, depletion and amortization 2,487 2,046 1,703
Impairment 132 82 54
Total costs and expenses 8,664 8,174 8,024
Income Before Income Taxes 4,354 2,471 3,546
Provision for income taxes 1,202 733 1,099
Net Income 3,152 1,738 2,447
Less: Net income attributable to noncontrolling interests 383 356 351
Net Income Attributable to Hess Corporation $ 2,769 $ 1,382 $ 2,096
Net Income Attributable to Hess Corporation Per Common Share:
Basic $ 9.03 $ 4.52 $ 6.80
Diluted $ 8.98 $ 4.49 $ 6.77
Weighted Average Number of Common Shares Outstanding:
Basic 306.8 305.9 308.1
Diluted 308.3 307.6 309.6
Common Stock Dividends Per Share $ 1.875 $ 1.750 $ 1.500
See accompanying Notes to Consolidated Financial Statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME
Year Ended December 31,
2024 2023 2022
(In millions)
Net Income $ 3,152 $ 1,738 $ 2,447
Other Comprehensive Income (Loss):
Derivatives designated as cash flow hedges
Effect of hedge (gains) losses reclassified to income - 190 585
Income taxes on effect of hedge (gains) losses reclassified to income - - -
Net effect of hedge (gains) losses reclassified to income - 190 585
Change in fair value of cash flow hedges - (190) (517)
Income taxes on change in fair value of cash flow hedges - - -
Net change in fair value of cash flow hedges - (190) (517)
Change in derivatives designated as cash flow hedges, after taxes - - 68
Pension and other postretirement plans
(Increase) reduction in unrecognized actuarial losses (87) (22) 201
Income taxes on actuarial changes in plan liabilities 10 2 (5)
(Increase) reduction in unrecognized actuarial losses, net (77) (20) 196
Amortization of net actuarial losses 4 18 12
Income taxes on amortization of net actuarial losses (1) (1) (1)
Net effect of amortization of net actuarial losses 3 17 11
Change in pension and other postretirement plans, after taxes (74) (3) 207
Other Comprehensive Income (Loss) (74) (3) 275
Comprehensive Income 3,078 1,735 2,722
Less: Comprehensive income attributable to noncontrolling interests 383 356 351
Comprehensive Income Attributable to Hess Corporation $ 2,695 $ 1,379 $ 2,371
See accompanying Notes to Consolidated Financial Statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
Year Ended December 31,
2024 2023 2022
(In millions)
Cash Flows From Operating Activities
Net income $ 3,152 $ 1,738 $ 2,447
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
(Gains) on asset sales, net (1) (2) (101)
Depreciation, depletion and amortization 2,487 2,046 1,703
Impairment 132 82 54
Exploratory dry hole costs 159 147 56
Exploration lease impairment 22 27 20
Pension prior service cost 35 - -
Pension settlement loss - 17 2
Stock compensation expense 100 87 83
Noncash (gains) losses on commodity derivatives, net - 156 548
Provision (benefit) for deferred income taxes and other tax accruals 267 196 309
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable (140) (324) (301)
(Increase) decrease in inventories (115) (87) 2
Increase (decrease) in accounts payable and accrued liabilities (115) 253 50
Increase (decrease) in taxes payable 13 38 (465)
Changes in other operating assets and liabilities (396) (432) (463)
Net cash provided by (used in) operating activities 5,600 3,942 3,944
Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P (4,640) (3,884) (2,487)
Additions to property, plant and equipment - Midstream (306) (224) (238)
Proceeds from asset sales, net of cash sold 16 3 178
Other, net (7) (8) (8)
Net cash provided by (used in) investing activities (4,937) (4,113) (2,555)
Cash Flows From Financing Activities
Net borrowings (repayments) of debt with maturities of 90 days or less (325) 322 (86)
Debt with maturities of greater than 90 days:
Borrowings 600 - 420
Repayments (313) (3) (510)
Cash dividends paid (579) (539) (465)
Common stock acquired and retired - (20) (630)
Proceeds from sale of Class A shares of Hess Midstream LP - 167 146
Noncontrolling interests, net (551) (550) (510)
Employee stock options exercised 21 10 52
Payments on finance lease obligations (11) (10) (9)
Other, net (22) (4) (24)
Net cash provided by (used in) financing activities (1,180) (627) (1,616)
Net Increase (Decrease) in Cash and Cash Equivalents (517) (798) (227)
Cash and Cash Equivalents at Beginning of Year 1,688 2,486 2,713
Cash and Cash Equivalents at End of Year $ 1,171 $ 1,688 $ 2,486
See accompanying Notes to Consolidated Financial Statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED EQUITY
Common Stock Capital in Excess of Par Retained Earnings Accumulated Other Comprehensive Income (Loss) Total Hess Stockholders’ Equity
Noncontrolling Interests Total Equity
Balance at December 31, 2021 $ 310 $ 6,017 $ 379 $ (406) $ 6,300 $ 726 $ 7,026
Net income - - 2,096 - 2,096 351 2,447
Other comprehensive income (loss) - - - 275 275 - 275
Share-based compensation 1 136 - - 137 - 137
Dividends on common stock - - (465) - (465) - (465)
Sale of Class A shares of Hess Midstream LP - 130 - - 130 88 218
Repurchase of Class B units of Hess Midstream Operations LP - 32 - - 32 (215) (183)
Common stock acquired and retired (5) (109) (536) - (650) - (650)
Noncontrolling interests, net - - - - - (309) (309)
Balance at December 31, 2022 $ 306 $ 6,206 $ 1,474 $ (131) $ 7,855 $ 641 $ 8,496
Net income - - 1,382 - 1,382 356 1,738
Other comprehensive income (loss) - - - (3) (3) - (3)
Share-based compensation 1 100 - - 101 - 101
Dividends on common stock - - (538) - (538) - (538)
Sale of Class A shares of Hess Midstream LP - 158 - - 158 175 333
Repurchase of Class B units of Hess Midstream Operations LP - 31 - - 31 (220) (189)
Noncontrolling interests, net - - - - - (336) (336)
Balance at December 31, 2023 $ 307 $ 6,495 $ 2,318 $ (134) $ 8,986 $ 616 $ 9,602
Net income - - 2,769 - 2,769 383 3,152
Other comprehensive income (loss) - - - (74) (74) - (74)
Share-based compensation 1 121 (6) - 116 - 116
Dividends on common stock - - (581) - (581) - (581)
Sale of Class A shares of Hess Midstream LP - - - - - 309 309
Repurchase of Class B units of Hess Midstream Operations LP - - - - - (157) (157)
Noncontrolling interests, net - - - - - (364) (364)
Balance at December 31, 2024 $ 308 $ 6,616 $ 4,500 $ (208) $ 11,216 $ 787 $ 12,003
See accompanying Notes to Consolidated Financial Statements.
1. Nature of Operations, Basis of Presentation and Summary of Accounting Policies
Unless the context indicates otherwise, references to “Hess”, “the Corporation”, “Registrant”, “we”, “us” and “our” refer to the consolidated business operations of Hess Corporation and its affiliates.
Nature of Business: Hess Corporation, incorporated in the State of Delaware in 1920, is a global E&P company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA), and Malaysia. We conduct exploration activities primarily offshore Guyana, in the U.S. Gulf of America, and offshore Suriname.
Our Midstream operating segment, which is comprised of Hess Corporation’s approximate 38% consolidated ownership interest in Hess Midstream LP at December 31, 2024 (see Note 4, Hess Midstream LP) provides fee-based services, including gathering, compressing and processing natural gas and fractionating NGL; gathering, terminaling, loading and transporting crude oil and NGL; storing and terminaling propane, and water handling services primarily in the Bakken shale play in the Williston Basin area of North Dakota.
On October 22, 2023, we entered into an Agreement and Plan of Merger (the Merger Agreement) with Chevron Corporation (Chevron) and Yankee Merger Sub Inc. (Merger Subsidiary), a direct, wholly-owned subsidiary of Chevron. The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, Merger Subsidiary will be merged with and into Hess, and Hess will be the surviving corporation in the Merger as a direct, wholly-owned subsidiary of Chevron (such transaction, the Merger). Under the terms of the Merger Agreement, if the Merger is completed, our stockholders will receive at the effective time of the Merger consideration consisting of 1.025 shares of Chevron common stock for each share of our common stock. On May 28, 2024, holders of a majority of Hess’ outstanding common stock voted to approve the Merger. Hess Guyana Exploration Limited (HGEL), a wholly-owned subsidiary of Hess, is currently in arbitration relating to the applicability of a right of first refusal (the Stabroek ROFR) contained in the operating agreement (the Stabroek JOA) among HGEL and affiliates of Exxon Mobil Corporation (Exxon Mobil) and China National Offshore Oil Corporation (CNOOC). The arbitration merits hearing about the applicability of the Stabroek ROFR to the Merger has been scheduled for May 2025, with a decision expected in the third quarter. We cannot predict the date on which the Merger will be completed because it is subject to conditions beyond our control, including the outcome of the arbitration.
Basis of Presentation and Principles of Consolidation: The consolidated financial statements include the accounts of Hess Corporation and entities in which we own more than a 50% voting interest. We consolidate Hess Midstream LP, a variable interest entity, based on our conclusion that we have the power through Hess Corporation’s approximate 38% consolidated ownership interest in Hess Midstream LP to direct those activities that most significantly impact the economic performance of Hess Midstream LP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to Hess Midstream LP. Our undivided interests in unincorporated oil and gas E&P ventures are proportionately consolidated. Investments in affiliated companies, 20% to 50% owned and where we have the ability to influence the operating or financial decisions of the affiliate, are accounted for using the equity method.
Estimates and Assumptions: In preparing financial statements in conformity with GAAP, management makes estimates and assumptions that affect the reported amounts of assets and liabilities in the Consolidated Balance Sheet and revenues and expenses in the Statement of Consolidated Income. Actual results could differ from those estimates. Estimates made by management include oil and gas reserves, asset and other valuations, depreciable lives, post-retirement liabilities, legal and environmental obligations, asset retirement obligations and income taxes.
Revenue Recognition:
Exploration and Production
Revenue is recognized from the sale of crude oil, NGL, and natural gas as performance obligations under contracts with customers are satisfied. Our responsibility 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. Generally, we receive payments from customers on a monthly basis, shortly after the physical delivery of the crude oil, NGL, or natural gas.
International contracts for the sale of natural gas are in the form of long-term natural gas sales agreements with government entities that have durations that are aligned with the durations of PSCs or other contractual arrangements with host governments. For international natural gas contracts with ship-or-pay provisions, penalties owed against future deliveries of natural gas due to delivery of volumes below minimum commitments are recognized as reductions to revenue in the commitment period when the shortfall occurs. 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. Pricing for our international natural gas contracts are determined using contractual formulas that are based on the price of alternative fuels as obtained from price indices and other factors.
Certain crude oil, NGL, and natural gas volumes are purchased by us 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 us 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 us, revenue is presented net of the associated cost of purchased volumes within Sales and other operating revenues in the Statement of Consolidated Income.
Contract Balances:
At December 31, 2024 and 2023, there were no contract liabilities. During the year ended December 31, 2023, revenue of $24 million was recognized within Sales and other operating revenues that was included in the contract liability balance at December 31, 2022. The $24 million contract liability balance at December 31, 2022, resulted from a take-or-pay deficiency payment received in 2021 that was subject to a make-up period expiring in December 2023. At December 31, 2024 and 2023, there were no contract assets.
Transaction Price Allocated to Remaining Performance Obligations:
The transaction price allocated to our wholly unsatisfied performance obligations on uncompleted contracts is variable. Further, many of our contracts with customers have durations of less than twelve months. Accordingly, we have elected under the provisions of Accounting Standards Codification (ASC) 606, Revenues from Contracts with Customers, the exemption from disclosure of revenue recognizable in future periods as these performance obligations are satisfied.
Sales-based Taxes:
We exclude sales-based taxes that are collected from customers from the transaction price in our contracts with customers. Accordingly, revenue from contracts with customers is net of sales-based taxes that are collected from customers and remitted to taxing authorities.
Revenue from Non-customers:
In Guyana, the joint venture partners (Co-Venturers) to the Stabroek Block petroleum agreement are subject to the income tax laws of Guyana and remain primarily liable for income taxes due on the results of operations, resulting in recognition of income tax expense. Pursuant to the contractual arrangements of the petroleum agreement, a portion of gross production from the block, separate from the Co-Venturers’ cost oil and profit oil entitlement, is used to satisfy the Co-Venturers’ income tax liability. This portion of gross production, referred to as tax barrels, is included in our reported production volumes and estimated proved reserves, and is recognized as sales revenue from non-customers.
Midstream
Substantially all revenue is earned by charging fees for gathering, compressing and processing natural gas and fractionating NGLs; gathering, terminaling, loading and transporting crude oil and NGLs; storing and terminaling propane; and gathering and disposing produced water. Effective January 1, 2014, certain subsidiaries of Hess Midstream LP entered into (i) gas gathering, (ii) crude oil gathering, (iii) gas processing and fractionation, (iv) storage services and (v) terminaling and export services commercial agreements with certain subsidiaries of Hess, each generally with an initial ten-year term which could be extended for an additional ten-year term at the unilateral right of the Hess Midstream LP subsidiaries. These Hess Midstream LP subsidiaries exercised their right to extend the terms of the gas gathering, crude oil gathering, gas processing and fractionation, storage services, and terminaling and export services commercial agreements for the secondary term effective January 1, 2024 through December 31, 2033. Effective January 1, 2019, a subsidiary of Hess Midstream LP entered into water gathering and disposal services agreements with a subsidiary of Hess. All the above agreements provide Hess Midstream the capacity to provide concurrent use of the services directly to third parties.
The responsibility of the Hess Midstream LP subsidiaries to provide each service for each year under each of the commercial agreements are considered separate, distinct performance obligations. Revenue is recognized over-time for each performance obligation as services are rendered using the output method, measured using the amount of volumes serviced during the period. The commercial agreements contain minimum volume commitments which fluctuate based on nominations covering substantially all of our E&P segment's existing and future owned or controlled production in the Bakken and projected third-party volumes owned or
controlled by our E&P segment through dedicated third-party contracts. Minimum volume commitments are equal to 80% of the nominations and apply on a three-year rolling basis such that they are set for the three years following the most recent nomination.
If the volumes delivered are less than the applicable minimum volume commitments under the commercial agreements during any quarter, the applicable Hess subsidiary is obligated to pay a shortfall fee equal to the volume deficiency multiplied by the related gathering, processing and/or terminaling fee. During the initial term of each commercial agreement, volume deficiencies are measured quarterly and recognized as revenue in the same period, as any associated shortfall payments are not subject to future reduction or offset. During the secondary term of each commercial agreement, the applicable Hess subsidiary will be entitled to receive a credit with respect to the amount of any shortfall payment made. Such Hess subsidiary may apply the credit against the fees payable for any volumes delivered under the applicable agreement in excess of the nominated volumes up to four quarters after the credit is earned. Shortfall payments are deferred upon receipt as a contract liability. Revenue is recognized at the earlier of when the excess volumes are delivered in subsequent periods or when it becomes remote that the credit will be utilized. No credits will be provided with respect to crude oil terminaling services under the terminaling and export services commercial agreement or water handling services under the water gathering and disposal services agreements.
The Midstream segment has elected the practical expedient under the provisions of Accounting Standards Codification (ASC) 606, Revenue from Contracts with Customers to recognize revenue in the amount it is entitled to invoice. All revenues, receivables, and contract balances arising from agreements between Hess Midstream LP subsidiaries and other Hess subsidiaries are eliminated upon consolidation.
Exploration and Development Costs: E&P activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized.
The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of a project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors, firm plans for additional drilling and other factors.
Depreciation, Depletion and Amortization: We record depletion expense for acquisition costs of proved properties using the units of production method over proved oil and gas reserves. Depreciation and depletion expense for oil and gas production facilities and wells is calculated using the units of production method over proved developed oil and gas reserves. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors. Depreciation of all other plant and equipment is determined on the straight-line method based on estimated useful lives.
Capitalized Interest: Interest from external borrowings is capitalized on material projects using the weighted average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at first production from the field. Capitalized interest is depreciated in the same manner as the depreciation of the underlying assets.
Impairment of Long-lived Assets: We review long-lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts of the long-lived assets are not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is measured based on the estimated fair value of the assets generally determined by discounting anticipated future net cash flows, an income valuation approach, or by a market-based valuation approach, which are Level 3 fair value measurements.
In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a projected amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairment will generally differ from those used in the standardized measure of discounted future net cash flows reported in Supplementary Oil and Gas Data, since the standardized measure requires the use of historical twelve-month average prices.
Impairment of Goodwill: Goodwill is tested for impairment annually on October 1st or when events or circumstances indicate it is more likely than not that the fair value of the reporting unit is less than its carrying value, including goodwill. If the fair value of the reporting unit exceeds its carrying value, goodwill is not impaired. If the carrying value of the reporting unit exceeds its fair value, an
impairment loss would be recorded for the excess of the carrying value over fair value, limited by the amount of goodwill allocated to the reporting unit. At December 31, 2024, goodwill of $360 million relates to the Midstream operating segment.
Cash and Cash Equivalents: Cash and cash equivalents primarily comprises cash on hand and on deposit, as well as highly liquid investments that are readily convertible into cash and have maturities of three months or less when acquired.
Inventories: Produced and unsold crude oil and NGL are valued at the lower of cost or net realizable value. Cost is determined using the average cost of production plus any transport cost incurred in bringing the volumes to their present location. Materials and supplies are valued at cost. Obsolete or surplus materials identified during periodic reviews are valued at the lower of cost or estimated net realizable value.
Leases: We determine if an arrangement is a lease at inception by evaluating whether the contract conveys the right to control an identified asset during the period of use. ROU assets represent our right to use an identified asset for the lease term and lease obligations represent our obligation to make payments as set forth in the lease arrangement. ROU assets and lease liabilities are recognized in the Consolidated Balance Sheet as operating leases or finance leases at the commencement date based on the present value of the minimum lease payments over the lease term. Where the implicit discount rate in a lease is not readily determinable, we use our incremental borrowing rate based on information available at the commencement date for determining the present value of the minimum lease payments. The lease term used in measurement of our lease obligations includes options to extend or terminate the lease when, in our judgment, it is reasonably certain that we will exercise that option. Variable lease payments that depend on an index or a rate are included in the measurement of lease obligations using the index or rate at the commencement date. Variable lease payments that vary because of changes in facts or circumstances after the commencement date of the lease are not included in the minimum lease payments used to measure lease obligations. We have agreements that include financial obligations for lease and nonlease components. For purposes of measuring lease obligations, we have elected not to separate nonlease components from lease components for the following classes of assets: drilling rigs, office space, offshore vessels, and aircraft. We apply a portfolio approach to account for operating lease ROU assets and liabilities for certain vehicles, railcars, field equipment and office equipment leases.
Finance lease cost is recognized as amortization of the ROU asset and interest expense on the lease liability. Operating lease cost is generally recognized on a straight-line basis. Operating lease costs for drilling rigs used to drill development wells and successful exploration wells are capitalized. Operating lease cost for other ROU assets used in oil and gas producing activities are either capitalized or expensed based on the nature of operation for which the ROU asset is utilized.
Leases with an initial term of 12 months or less are not recorded on the balance sheet as permitted under ASC 842, Leases. We recognize lease cost for short-term leases on a straight-line basis over the term of the lease. Some of our leases with initial terms of 12 months or less include one or more options to renew. The renewal option is at our sole discretion and is not included in the lease term for measurement of the lease obligation unless we are reasonably certain at the commencement date of the lease, to renew the lease.
Income Taxes: Deferred income taxes are determined using the liability method. We have net operating loss carryforwards or credit carryforwards in multiple jurisdictions and have recognized deferred tax assets for those losses and credits. Additionally, we have deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If, when tested under the relevant accounting standards, it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is established to reduce the deferred tax assets to the amount that is expected to be realized. The accounting standards require the evaluation of all available positive and negative evidence giving weight based on the evidence’s relative objectivity. In evaluating potential sources of positive evidence, we consider the reversal of taxable temporary differences, taxable income in carryback and carryforward periods, the availability of tax planning strategies, the existence of appreciated assets, estimates of future taxable income, and other factors. In evaluating potential sources of negative evidence, we consider a cumulative loss in recent years, any history of operating losses or tax credit carryforwards expiring unused, losses expected in early future years, unsettled circumstances that, if unfavorably resolved, would adversely affect future operations and profit levels on a continuing basis in future years, and any carryback or carryforward period so brief that a significant deductible temporary difference expected to reverse in a single year would limit realization of tax benefits. We assign cumulative historical losses significant weight in the evaluation of realizability relative to more subjective evidence such as forecasts of future income. In addition, we recognize the financial statement effect of a tax position only when management believes that it is more likely than not, that based on the technical merits, the position will be sustained upon examination. We are not indefinitely reinvested with respect to the book in excess of tax basis in the investment in our foreign subsidiaries. Because of U.S. tax rules related to foreign operations, we expect that the future reversal of such temporary differences will occur free of material taxation. We classify interest and penalties associated with uncertain tax positions as income tax expense. We account for the U.S. tax effect of global intangible low-taxed income earned by foreign subsidiaries in the period that such income is earned. We utilize the aggregate approach for releasing disproportionate income tax effects from Accumulated other comprehensive income (loss).
Asset Retirement Obligations: We have legal obligations to remove and dismantle long-lived assets and to restore land or the seabed at certain E&P locations. We initially recognize a liability for the fair value of legally required asset retirement obligations in
the period in which the retirement obligations are incurred and capitalize the associated asset retirement costs as part of the carrying amount of the long-lived assets. In subsequent periods, the liability is accreted over the useful life of the related asset, and the capitalized asset retirement costs are depreciated over proved developed oil and gas reserves using the units of production method or the useful life of the related asset. Fair value is determined by applying a credit adjusted risk-free rate to the undiscounted expected future abandonment expenditures. Changes in estimates prior to settlement result in adjustments to both the liability and related asset values, unless the field has ceased production, in which case changes are recognized in the Statement of Consolidated Income.
We measure asset retirement obligations based on the requirements of existing laws and regulations in accordance with ASC 410-20, Asset Retirement Obligations. Laws and regulations associated with the scope and timing for the abandonment of oil and gas wells, facilities and equipment could change which could increase the cost of our abandonment obligations. In addition, we may be required to assume abandonment obligations for certain divested assets in the event the current or future owners of facilities previously owned by us are unable to perform, whether due to bankruptcy or otherwise.
Retirement Plans: We recognize the funded status of defined benefit postretirement plans in the Consolidated Balance Sheet. The funded status is measured as the difference between the fair value of plan assets and the projected benefit obligation. We recognize the net changes in the funded status of these plans as a component of Other Comprehensive Income (Loss) in the year in which such changes occur. Actuarial gains and losses in excess of 10% of the greater of the benefit obligation or the fair value of plan assets are amortized over the average remaining service period of active employees or the remaining average expected life if a plan’s participants are predominantly inactive.
Derivatives: We utilize derivative instruments for financial risk management activities. In these activities, we may use futures, forwards, options and swaps, individually or in combination, to mitigate our exposure to fluctuations in prices of crude oil and natural gas, as well as changes in interest and foreign currency exchange rates.
All derivative instruments are recorded at fair value in the Consolidated Balance Sheet. Our policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not designated as hedges are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges), or hedges of changes in fair value of recognized assets and liabilities or of unrecognized firm commitments (fair value hedges). Changes in fair value of derivatives that are designated as cash flow hedges are recorded as a component of Other Comprehensive Income (Loss). Amounts included in Accumulated Other Comprehensive Income (Loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged item is recorded as an adjustment to its carrying amount and recognized currently in earnings.
Fair Value Measurements: We use various valuation approaches in determining fair value for financial instruments, including the market and income approaches. Our fair value measurements also include non-performance risk and time value of money considerations. Counterparty credit is considered for financial assets, and our credit is considered for financial liabilities. We also record certain nonfinancial assets and liabilities at fair value when required by GAAP. These fair value measurements are recorded in connection with business combinations, qualifying nonmonetary exchanges, the initial recognition of asset retirement obligations and any impairment of long-lived assets, equity method investments, goodwill or other indefinite-lived intangible assets, such as environmental credits. We determine fair value in accordance with the fair value measurements accounting standard which established a hierarchy for the inputs used to measure fair value based on the source of the inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3), including discounted cash flows and other unobservable data. Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market. Multiple inputs may be used to measure fair value; however, the level assigned to a fair value measurement is based on the lowest significant input level within this fair value hierarchy.
Details on the methods and assumptions used to determine the fair values are as follows:
Fair value measurements based on Level 1 inputs: Measurements that are most observable are based on quoted prices of identical instruments obtained from the principal markets in which they are traded. Closing prices are both readily available and representative of fair value. Market transactions occur with sufficient frequency and volume to assure liquidity.
Fair value measurements based on Level 2 inputs: Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. Measurements based on Level 2 inputs include over-the-counter derivative instruments that are priced on an exchange-traded curve but have contractual terms that are not identical to exchange-traded contracts.
Fair value measurements based on Level 3 inputs: Measurements that are least observable are estimated from related market data, determined from sources with little or no market activity for comparable contracts or are positions with longer durations. Fair values determined using discounted cash flows and other unobservable data are also classified as Level 3.
Netting of Financial Instruments: We generally enter into master netting arrangements to mitigate legal and counterparty credit risk. Master netting arrangements are generally accepted overarching master contracts that govern all individual transactions with the same counterparty entity as a single legally enforceable agreement. The U.S. Bankruptcy Code provides for the enforcement of certain termination and netting rights under certain types of contracts upon the bankruptcy filing of a counterparty, commonly known as the “safe harbor” provisions. If a master netting arrangement provides for termination and netting upon the counterparty’s bankruptcy, these rights are generally enforceable with respect to “safe harbor” transactions. If these arrangements provide the right of offset and our intent and practice is to offset amounts in the case of such a termination, our policy is to record the fair value of derivative assets and liabilities on a net basis. In the normal course of business, we rely on legal and credit risk mitigation clauses providing for adequate credit assurance as well as close-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 Remeasurement: The U.S. Dollar is the functional currency (primary currency in which business is conducted) for our foreign operations. Adjustments resulting from remeasuring monetary assets and liabilities that are denominated in a currency other than the functional currency are recorded in Other, net in the Statement of Consolidated Income.
Maintenance and Repairs: Maintenance and repairs 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 December 31, 2024, our reserve for estimated remediation liabilities was $35 million, of which $14 million is classified as Accrued liabilities and $21 million is classified as Other liabilities and deferred credits in the Consolidated Balance Sheet. Environmental expenditures that increase the life or efficiency of property or reduce or prevent future adverse impacts to the environment are capitalized.
Environmental Credits: Environmental credits are purchased to fulfill voluntary emissions reduction targets and are classified as indefinite-lived intangible assets. They are expensed when retired to offset emissions and are tested for impairment annually on October 1st, or when events or circumstances indicate it is more likely than not that fair value is less than carrying value. If the carrying value exceeds fair value, an impairment loss would be recorded for the excess of the carrying value over fair value.
In response to feedback from constituents and the staff’s related research and analysis, the Financial Accounting Standards Board (FASB) added a project to its technical agenda on May 25, 2022 to address the accounting for environmental credits due to a lack of existing guidance for accounting for environmental credits. On December 17, 2024, the FASB issued the proposed Accounting Standards Update (ASU), Environmental Credits and Environmental Credit Obligations (Topic 818). Included within the proposed ASU is a requirement to expense the cost of environmental credits that will not be sold or used to settle environmental credit obligations. Our environmental credits fall within the scope of the proposed ASU and would have been expensed in the period of purchase, instead of capitalized as indefinite-lived intangible assets, if the requirements in the proposed ASU were applied. In 2024, we purchased $88 million REDD+ carbon credits (2023: $75 million, 2022: $75 million) under a long-term agreement with the Government of Guyana that was executed in December 2022 in order to support ongoing carbon emissions reduction efforts by the Corporation. These carbon credits are registered on the ART Registry, an over-the-counter registry, and can be sold to third parties or retired to offset emissions. At December 31, 2024, the carrying value of our carbon credits of $238 million (2023: $150 million) is included in non-current Other assets in the Consolidated Balance Sheet.
New Accounting Pronouncements:
In November 2023, the FASB issued ASU No. 2023-07, Improvements to Reportable Segment Disclosures. The ASU improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The ASU does not change how an entity identifies its operating segments. We adopted this ASU for fiscal year 2024 and applied the amendments retrospectively to all prior periods presented in our consolidated financial statements (see Note 18, Segment Information).
In December 2023, the FASB issued ASU No. 2023-09, Improvements to Income Tax Disclosures, which enhances the disclosure requirements within ASC Topic 740. The ASU requires, among other disclosures, greater disaggregation of information and the use of certain categories in the rate reconciliation, and the disaggregation of income taxes paid by jurisdiction. The ASU is effective for
annual periods beginning after December 15, 2024. Early adoption is permitted. We do not expect this ASU to have a material impact on our consolidated financial statements.
In November 2024, the FASB issued ASU No. 2024-03, Disaggregation of Income Statement Expenses. This ASU requires disclosure of specified information about certain cost and expense captions. Such information includes the amounts of certain items included within those captions, such as the amount of employee compensation, and depreciation, depletion and amortization. The ASU is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. We are currently assessing the impact of adopting this ASU on our consolidated financial statements.
2. Inventories
Inventories at December 31 were as follows:
2024 2023
(In millions)
Crude oil and natural gas liquids $ 95 $ 72
Materials and supplies 324 232
Total Inventories $ 419 $ 304
3. Property, Plant and Equipment
Property, plant and equipment at December 31 were as follows:
2024 2023
(In millions)
Exploration and Production
Unproved properties $ 179 $ 103
Proved properties 2,638 2,660
Wells, equipment and related facilities 33,059 29,159
35,876 31,922
Midstream 5,117 4,819
Corporate and Other 30 30
Total - at cost 41,023 36,771
Less: Reserves for depreciation, depletion, amortization and lease impairment 21,102 19,339
Property, Plant and Equipment - Net $ 19,921 $ 17,432
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:
2024 2023 2022
(In millions)
Balance at January 1 $ 952 $ 886 $ 681
Additions to capitalized exploratory well costs pending the determination of proved reserves 225 257 298
Reclassifications to wells, facilities and equipment based on the determination of proved reserves (117) (133) (93)
Capitalized exploratory well costs charged to expense (50) (58) -
Balance at December 31 $ 1,010 $ 952 $ 886
Number of Wells at December 31 40 43 43
During the three years ended December 31, 2024, additions to capitalized exploratory well costs primarily related to drilling at the Stabroek Block (Hess 30%), offshore Guyana. At December 31, 2024, 37 exploration and appraisal wells on the Stabroek Block, with a total cost of $942 million, were capitalized pending determination of proved reserves. Other additions to capitalized exploratory well costs in 2023 include the Pickerel-1 well (Hess 100%) in the Gulf of America. Other additions to capitalized exploratory wells costs in 2022 include the Huron-1 well (Hess 40%) in the Gulf of America, and the Zanderij-1 well on Block 42 (Hess 33%), offshore Suriname.
Reclassifications to wells, facilities and equipment based on the determination of proved reserves in 2024 resulted from the sanction of the Whiptail development project, the sixth sanctioned project on the Stabroek Block. Reclassifications to wells, facilities and equipment based on the determination of proved reserves in 2023 resulted from the sanction of the Uaru development project, the fifth sanctioned project on the Stabroek Block, and the Pickerel-1 well in the Gulf of America. In 2022, reclassifications to wells,
facilities and equipment based on the determination of proved reserves resulted from the sanction of the Yellowtail development project, the fourth sanctioned project on the Stabroek Block.
Capitalized exploratory well costs charged to expense in 2024 primarily relate to three exploration wells in the Malaysia/Thailand Joint Development Area (JDA) (Hess 50%) in the Gulf of Thailand for $48 million. In June 2024, the regulator provided notification that the current PSC for JDA Block A-18 will not be re-awarded to the existing PSC contractors upon its expiration in 2029. There is no plan to develop these discoveries prior to the expiration of the existing PSC. Capitalized exploratory well costs charged to expense in 2023 of $58 million primarily relate to the Huron-1 well in the Gulf of America.
The preceding table excludes well costs incurred and expensed during 2024 of $109 million, primarily related to the Vancouver-1 well in the Gulf of America and the Trumpetfish-1 well on the Stabroek Block, offshore Guyana (2023: $89 million; 2022: $56 million).
Exploratory well costs capitalized for greater than one year following completion of drilling were $787 million at December 31, 2024, separated by year of completion as follows (in millions):
2023 $ 214
2022 218
2021 106
2020 8
2019 and prior 241
$ 787
Guyana: 93% of the capitalized well costs in excess of one year relate to successful exploration and appraisal wells where hydrocarbons were encountered on the Stabroek Block (Hess 30%). The operator plans further appraisal drilling on the block and is conducting pre-development planning for additional phases of development.
Suriname: 5% of the capitalized well costs in excess of one year relates to the Zanderij-1 well on Block 42 (Hess 33%). Exploration and appraisal activities are ongoing.
Malaysia: 2% of the capitalized well costs in excess of one year relates to North Malay Basin (Hess 50%), offshore Peninsular Malaysia, where hydrocarbons were encountered in two successful exploration wells. Pre-development studies are ongoing.
4. Hess Midstream LP
Hess Midstream LP, a variable interest entity, has an "Up-C" organizational structure. We had an approximate 38% consolidated ownership interest at December 31, 2024 in Hess Midstream LP on an as-exchanged basis, primarily through our ownership of Class B units in Hess Midstream Operations LP (HESM Opco), the operating subsidiary of Hess Midstream LP, which are exchangeable into Class A shares of Hess Midstream LP on a one-for-one basis. An affiliate of Global Infrastructure Partners (GIP) owned an approximate 15% consolidated interest in Hess Midstream LP at December 31, 2024 on an as-exchanged basis, primarily through its ownership of Class B units in HESM Opco, and the public owned an approximate 47% consolidated interest in Hess Midstream LP at December 31, 2024, through the ownership of Class A shares of Hess Midstream LP. We have concluded that we are the primary beneficiary of the variable interest entity since we have the power to direct those activities that most significantly impact the economic performance of Hess Midstream LP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to Hess Midstream LP. This conclusion was based on a qualitative analysis that considered Hess Midstream LP’s governance structure, the commercial agreements between Hess Midstream LP and us, and the voting rights established between the members.
In 2022, Hess Midstream LP completed a single underwritten public equity offering of 10.2 million Hess Midstream LP Class A shares held by affiliates of Hess Corporation and GIP. Hess received net proceeds of $146 million from the transaction. The transaction resulted in an increase in Capital in excess of par and Noncontrolling interests of $130 million and $88 million, respectively. The increase to Noncontrolling interests of $88 million is comprised of $16 million resulting from the change in ownership interests and $72 million from an increase to deferred tax assets resulting from a step-up in the tax basis of Hess Midstream LP’s investment in HESM Opco.
In 2022, HESM Opco repurchased 13.6 million HESM Opco Class B units held by affiliates of Hess Corporation and GIP for $400 million in a single transaction. HESM Opco issued $400 million in aggregate principal amount of 5.500% fixed-rate senior unsecured notes due 2030 in a private offering to repay borrowings under its revolving credit facility used to finance the repurchase. The transaction resulted in an increase in Capital in excess of par and a decrease in Noncontrolling interests of $32 million, and an increase in deferred tax assets and Noncontrolling interests of $17 million resulting from an adjustment in the carrying value of Hess Midstream LP’s investment in HESM Opco without a corresponding adjustment in the tax basis. The $200 million paid to GIP reduced Noncontrolling interests.
In 2023, Hess Midstream LP completed two underwritten public equity offerings of an aggregate of 24.3 million Hess Midstream LP Class A shares. Hess Corporation received net proceeds of $167 million from the first public offering in May 2023, but did not participate or receive any proceeds from the second public offering in August 2023. These transactions, in aggregate, resulted in an increase in Capital in excess of par and Noncontrolling interests of $158 million and $175 million, respectively. The increase to Noncontrolling interests of $175 million is comprised of $9 million resulting from the changes to ownership interests due to the first public offering in May 2023, and $166 million from an increase to deferred tax assets resulting from step-ups in the tax basis of Hess Midstream LP’s investment in HESM Opco.
In 2023, HESM Opco repurchased an aggregate of 13.6 million HESM Opco Class B units in four transactions from affiliates of Hess Corporation and GIP for total proceeds of $400 million. The unit repurchases were financed by borrowings under HESM Opco’s revolving credit facility. The unit repurchases, in aggregate, resulted in an increase in Capital in excess of par and a decrease in Noncontrolling interests of $31 million, and an increase in deferred tax assets and Noncontrolling interests of $23 million due to adjustments in the carrying value of Hess Midstream LP’s investment in HESM Opco without corresponding adjustments in the tax basis. The aggregate proceeds paid to GIP of $212 million reduced Noncontrolling interests. Hess Corporation participated in all the HESM Opco Class B unit repurchase transactions in 2023 on a 50/50 basis with GIP with the exception of the HESM Opco Class B unit repurchase transaction in November 2023. Hess Corporation and GIP received $38 million and $62 million, respectively, of the total proceeds of $100 million. There was no change in Hess Corporation’s ownership interest in Hess Midstream LP on a consolidated basis as a result of this transaction and accordingly, there was no impact to the balance of Noncontrolling interests. However, the transaction did result in an increase in deferred tax assets and Noncontrolling interests of $7 million as a result of an adjustment in the carrying value of Hess Midstream LP’s investment in HESM Opco without a corresponding adjustment in the tax basis.
In 2024, Hess Midstream LP completed three underwritten public equity offerings of an aggregate of 35.7 million Hess Midstream LP Class A shares held by an affiliate of GIP. Hess Corporation did not receive any proceeds from these public equity offerings. As these transactions did not result in a change in Hess Corporation’s ownership interest in Hess Midstream LP on a consolidated basis, there was no adjustment to Noncontrolling interests resulting from changes to ownership interests. However, these transactions, in aggregate, resulted in an increase in Noncontrolling interests and deferred tax assets of $309 million resulting from step-ups in the tax basis of Hess Midstream LP’s investment in HESM Opco.
In 2024, HESM Opco repurchased an aggregate of 8.4 million HESM Opco Class B units in three transactions held by affiliates of Hess Corporation and GIP for total proceeds of $300 million. The unit repurchases were financed using borrowings under HESM Opco’s revolving credit facility and cash on hand. As Hess Corporation participated in these repurchases only to the extent necessary to maintain its current ownership interest in Hess Midstream LP on a consolidated basis, there was no adjustment to Noncontrolling interests resulting from changes to ownership interests. However, the repurchases, in aggregate, resulted in an increase in deferred tax assets and Noncontrolling interests of $30 million due to adjustments in the carrying value of Hess Midstream LP’s investment in HESM Opco without corresponding adjustments in the tax basis. The aggregate proceeds paid to GIP of $187 million reduced Noncontrolling interests.
At December 31, 2024, Hess Midstream LP liabilities totaling $3,652 million (2023: $3,385 million) are on a nonrecourse basis to Hess Corporation, while Hess Midstream LP assets available to settle the obligations of Hess Midstream LP included cash and cash equivalents totaling $4 million (2023: $5 million), property, plant and equipment, net totaling $3,325 million (2023: $3,229 million) and the equity-method investment in LM4 of $87 million (2023: $90 million).
LM4 is a 200 million standard cubic feet per day gas processing plant located south of the Missouri River in McKenzie County, North Dakota, that was constructed as part of a 50/50 joint venture between Hess Midstream LP and Targa Resources Corp. Hess Midstream LP has a natural gas processing agreement with LM4 under which it pays a processing fee and reimburses LM4 for its proportionate share of electricity costs. In 2024, processing fees were $33 million (2023: $24 million; 2022: $21 million) and are included in Operating costs and expenses in the Statement of Consolidated Income.
5. Accrued Liabilities
The following table provides detail of our accrued liabilities at December 31:
2024 2023
(In millions)
Accrued capital expenditures $ 726 $ 670
Accrued operating and marketing expenditures 584 593
Accrued compensation and benefits 199 193
Accrued payments to royalty and working interest owners 186 178
Accrued interest on debt 141 144
Current portion of asset retirement obligations 81 160
Other accruals 25 164
Total Accrued Liabilities $ 1,942 $ 2,102
6. Leases
Operating and finance lease obligations at December 31 included in the Consolidated Balance Sheet were as follows:
Operating Leases Finance Leases
2024 2023 2024 2023
(In millions)
Right-of-use assets - net (a) $ 652 $ 720 $ 90 $ 108
Lease obligations:
Current $ 321 $ 347 $ 25 $ 23
Long-term 404 459 132 156
Total lease obligations $ 725 $ 806 $ 157 $ 179
(a)At December 31, 2024, finance lease ROU assets had a cost of $212 million (2023: $212 million) and accumulated amortization of $122 million (2023: $104 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, 2024 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, 2024, the remaining lease term for the FSO was 8.8 years.
Maturities of lease obligations at December 31, 2024 were as follows:
Operating Leases Finance
Leases
(In millions)
2025 $ 349 $ 36
2026 200 31
2027 53 22
2028 26 23
2029 24 22
Remaining years 153 77
Total lease payments 805 211
Less: Imputed interest (80) (54)
Total lease obligations $ 725 $ 157
The following information relates to the operating and finance leases at December 31:
Operating Leases Finance Leases
2024 2023 2024 2023
Weighted average remaining lease term 4.7 years 5.0 years 8.8 years 9.8 years
Range of remaining lease terms 0.1 - 11.5 years
0.1 - 12.5 years
8.8 years 9.8 years
Weighted average discount rate 5.1% 5.1% 7.9% 7.9%
The components of lease costs were as follows:
2024 2023 2022
(In millions)
Operating lease cost (a) $ 385 $ 241 $ 114
Finance lease cost:
Amortization of leased assets 18 18 18
Interest on lease obligations 13 15 18
Short-term lease cost (b) 267 294 311
Variable lease cost (c) 60 67 33
Sublease income (d) (20) (19) (18)
Total lease cost $ 723 $ 616 $ 476
(a)Operating lease cost in 2024 included a drilling rig and offshore support vessels in the Gulf of America. Operating lease cost in 2023 included a drilling rig at North Malay Basin used for a 15 well development drilling program spanning 2023 and 2024, and offshore support vessels in the Gulf of America.
(b)Short-term lease cost is primarily attributable to equipment used in global exploration, development, production, and crude oil marketing activities. Future short-term lease costs will vary based on activity levels of our operated assets. In 2024, 2023 and 2022, short-term lease cost included drilling rigs and offshore support vessels used primarily for exploration and abandonment activities in the Gulf of America and workover rigs for maintenance activities in the Bakken.
(c)Variable lease costs for drilling rigs result from differences in the minimum rate and the actual usage of the ROU asset during the lease period. Variable lease costs for logistical assets result from differences in stated monthly rates and total charges reflecting the actual usage of the ROU asset during the lease period. Variable lease costs for our office leases represent common area maintenance charges which have not been separated from lease components.
(d)We sublease certain of our office space to third parties under our head lease.
The above lease costs represent 100% of the lease payments due for the period, including where we as operator have contracted directly with suppliers. As the payments under lease agreements where we are operator become due, we bill our partners their proportionate share for reimbursement pursuant to the terms of our joint operating agreements. Reimbursements are not reflected in the table above. Certain lease costs above associated with exploration and development activities are included in capital expenditures.
Supplemental cash flow information related to leases were as follows:
Operating Leases Finance Leases
2024 2023 2022 2024 2023 2022
(In millions)
Cash paid for amounts included in the measurement of lease obligations:
Operating cash flows (a) $ 401 $ 254 $ 126 $ 13 $ 15 $ 18
Financing cash flows (a) - - - 22 21 19
Noncash transactions:
Leased assets recognized for new lease obligations incurred (b) 40 267 294 - - -
Changes in leased assets and lease obligations due to lease modifications and remeasurements of lease payments (c) 239 97 16 - - -
(a)Amounts represent gross lease payments before any recovery from partners.
(b)In 2023, primarily related to leases for a drilling rig and offshore support vessels in the Gulf of America. In 2022, primarily related to leases for drilling rigs in the Bakken and at North Malay Basin.
(c)In 2024, primarily related to reassessments of the lease terms for a drilling rig and a offshore support vessel in the Gulf of America upon exercise of renewal options. In 2023, primarily related to reassessments of the lease terms for a drilling rig at North Malay Basin, and offshore support vessels and aircraft in the Gulf of America.
7. Debt
Total debt at December 31 consisted of the following:
2024 2023
(In millions)
Debt - Hess Corporation:
Senior unsecured fixed-rate public notes:
3.500% due 2024
$ - $ 300
4.300% due 2027
998 997
7.875% due 2029
465 465
7.300% due 2031
629 629
7.125% due 2033
538 537
6.000% due 2040
743 743
5.600% due 2041
1,238 1,238
5.800% due 2047
495 495
Total senior unsecured fixed-rate public notes 5,106 5,404
Fair value adjustments - interest rate hedging - (2)
Total Debt - Hess Corporation $ 5,106 $ 5,402
Debt - Midstream (Hess Midstream Operations LP):
Senior unsecured fixed-rate public notes:
5.625% due 2026 (a)
$ 798 $ 795
5.125% due 2028
545 545
6.500% due 2029
592 -
4.250% due 2030
743 742
5.500% due 2030
396 395
Total senior unsecured fixed-rate public notes 3,074 2,477
Term Loan A facility 383 394
Revolving credit facility 15 340
Total Debt - Midstream $ 3,472 $ 3,211
Total Debt:
Current portion of long-term debt $ 23 $ 311
Long-term debt 8,555 8,302
Total Debt $ 8,578 $ 8,613
(a)In February 2025, HESM Opco refinanced these notes on a long-term basis. See Note 20, Subsequent Events.
At December 31, 2024, the maturity profile of total debt was as follows:
Total Hess
Corporation Midstream
(In millions)
2025 $ 23 $ - $ 23
2026 832 - 832
2027 1,345 1,000 345
2028 550 - 550
2029 1,067 467 600
Thereafter 4,821 3,671 1,150
Total Borrowings 8,638 5,138 3,500
Less: Deferred financing costs and discounts (60) (32) (28)
Total Debt (excluding interest) $ 8,578 $ 5,106 $ 3,472
In 2024, $132 million of interest was capitalized (2023: $48 million; 2022: $10 million).
Debt - Hess Corporation:
Senior unsecured fixed-rate public notes:
At December 31, 2024, Hess Corporation’s fixed-rate senior unsecured notes had a gross principal amount of $5,138 million (2023: $5,438 million) and a weighted average interest rate of 6.0% (2023: 5.9%). In July, we repaid the $300 million principal amount of our 3.500% fixed-rate senior unsecured notes, which matured on July 15, 2024. The indentures for our fixed-rate senior
unsecured notes limit the ratio of secured debt to Consolidated Net Tangible Assets (as that term is defined in the indentures) to 15%. As of December 31, 2024, Hess Corporation was in compliance with this financial covenant.
Credit facility:
The revolving credit facility can be used for borrowings and letters of credit. Borrowings on the facility will generally bear interest at 1.400% above SOFR, though the interest rate is subject to adjustment based on the credit rating of the Corporation’s senior, unsecured, non-credit enhanced long-term debt. The revolving credit facility is subject to customary representations, warranties, customary events of default and covenants, including a financial covenant limiting the ratio of Total Consolidated Debt to Total Capitalization of the Corporation and its consolidated subsidiaries to 65%, and a financial covenant limiting the ratio of secured debt to Consolidated Net Tangible Assets of the Corporation and its consolidated subsidiaries to 15% (as these capitalized terms are defined in the credit agreement for the revolving credit facility). As of December 31, 2024, Hess Corporation was in compliance with these financial covenants. At December 31, 2024, Hess Corporation had no outstanding borrowings or letters of credit under its revolving credit facility.
Other outstanding letters of credit at December 31 were as follows:
2024 2023
(In millions)
Committed lines (a) $ 8 $ 2
Uncommitted lines (a) 77 86
Total $ 85 $ 88
(a)At December 31, 2024, committed and uncommitted lines have expiration dates through 2025.
The most restrictive of the financial covenants relating to our fixed-rate senior unsecured notes and our revolving credit facility would allow us to borrow up to an additional $3,226 million of secured debt at December 31, 2024.
Debt - Midstream (Hess Midstream Operations LP):
Senior unsecured fixed-rate public notes:
At December 31, 2024, HESM Opco’s fixed-rate senior unsecured notes had a gross principal amount of $3,100 million (2023: $2,500 million) and a weighted average interest rate of 5.4% (2023: 5.1%). HESM Opco’s senior unsecured notes are guaranteed by certain of HESM Opco’s direct and indirect wholly owned material domestic subsidiaries. These senior unsecured notes are non-recourse to Hess Corporation.
In May 2024, HESM Opco issued $600 million in aggregate principal amount of 6.500% fixed-rate senior unsecured notes due in 2029 in a private offering. At the time of issuance, the proceeds were primarily used to reduce indebtedness outstanding under HESM Opco’s revolving credit facility. In April 2022, HESM Opco issued $400 million in aggregate principal amount of 5.500% fixed-rate senior unsecured notes due in 2030 in a private offering to repay borrowings under its revolving credit facility used to finance the repurchase of 13.6 million HESM Opco Class B units held by Hess Corporation and GIP.
Credit facilities:
At December 31, 2024, HESM Opco had $1.4 billion of senior secured syndicated credit facilities, consisting of a $1.0 billion revolving credit facility and a $400 million term loan facility. Borrowings under the term loan facility will generally bear interest at SOFR plus an applicable margin ranging from 1.650% to 2.550%, while the applicable margin for the syndicated revolving credit facility ranges from 1.375% to 2.050%. Pricing levels for the facility fee and interest-rate margins are based on HESM Opco’s ratio of total debt to EBITDA (as defined in the credit facilities). If HESM Opco obtains an investment grade credit rating, the pricing levels will be based on HESM Opco’s credit ratings in effect from time to time. The credit facilities contain covenants that require HESM Opco to maintain a ratio of total debt to EBITDA (as defined in the credit facilities) for the prior four fiscal quarters of not greater than 5.00 to 1.00 as of the last day of each fiscal quarter (5.50 to 1.00 during the specified period following certain acquisitions) and, prior to HESM Opco obtaining an investment grade credit rating, a ratio of secured debt to EBITDA for the prior four fiscal quarters of not greater than 4.00 to 1.00 as of the last day of each fiscal quarter. HESM Opco was in compliance with these financial covenants at December 31, 2024. 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, 2024, borrowings of $15 million were drawn under HESM Opco’s revolving credit facility, and borrowings of $385 million, excluding deferred issuance costs, were drawn under HESM Opco’s term loan facility. Borrowings under these credit facilities are non-recourse to Hess Corporation.
8. Asset Retirement Obligations
The following table describes the changes in our asset retirement obligations for the years ended December 31:
2024 2023
(In millions)
Balance at January 1 $ 1,346 $ 1,241
Liabilities incurred 112 135
Liabilities settled or disposed of (a) (185) (240)
Accretion expense 73 61
Revisions of estimated liabilities 113 148
Foreign currency remeasurement (1) 1
Balance at December 31 $ 1,458 $ 1,346
Total Asset Retirement Obligations at December 31:
Current portion of asset retirement obligations $ 81 $ 160
Long-term asset retirement obligations 1,377 1,186
Total at December 31 $ 1,458 $ 1,346
(a)Payments to settle asset retirement obligations are presented in Changes in other operating assets and liabilities on the Statement of Consolidated Cash Flows.
The liabilities incurred in 2024 primarily relate to operations in Guyana and the Gulf of America while liabilities incurred in 2023 primarily relate to operations in Guyana. Liabilities settled or disposed of in 2024 and 2023 primarily result from abandonment activity completed in the Gulf of America and the Bakken.
Revisions of estimated liabilities in 2024 primarily reflect changes in service and equipment rates. Revisions of estimated liabilities in 2023 include $82 million that resulted from revisions to estimated costs to abandon certain wells, pipelines and production facilities in the West Delta Field in the Gulf of America. See Note 12, Impairment. Other revisions of estimated liabilities in 2023 primarily reflect changes in service and equipment rates.
Sinking fund deposits that are legally restricted for purposes of settling asset retirement obligations, which are reported in non-current Other assets in the Consolidated Balance Sheet, were $327 million at December 31, 2024 (2023: $294 million).
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 participants in the United Kingdom (U.K.) pension plan. The U.S. employees hired on or after January 1, 2017 participate under a cash accumulation formula and receive credits to a notional account based on a percentage of pensionable wages. Interest accrues on the balance in the notional account at a rate determined in accordance with plan provisions. Additionally, we maintain an unfunded post-retirement medical plan that provides health benefits to certain U.S. qualified retirees from ages 55 through 65. The measurement date for all retirement plans is December 31.
The following table summarizes the benefit obligations, the fair value of plan assets, and the funded status of our pension and postretirement medical plans:
Funded
Pension Plans Unfunded
Pension Plan Postretirement
Medical Plan
2024 2023 2024 2023 2024 2023
(In millions)
Change in Benefit Obligation
Balance at January 1, $ 1,760 $ 1,802 $ 222 $ 212 $ 53 $ 52
Service cost 29 26 11 9 3 3
Interest cost 81 88 10 9 3 2
Actuarial (gain) loss (a) (93) 44 42 7 1 1
Plan settlements - (143) - - - -
Benefit payments (88) (77) (6) (15) (4) (5)
Plan amendments 35 - - - - -
Foreign currency exchange rate changes (5) 20 - - - -
Balance at December 31, (b) $ 1,719 $ 1,760 $ 279 $ 222 $ 56 $ 53
Change in Fair Value of Plan Assets
Balance at January 1, $ 2,445 $ 2,450 $ - $ - $ - $ -
Actual return on plan assets 18 186 - - - -
Employer contributions 3 1 6 15 4 5
Plan settlements - (143) - - - -
Benefit payments (88) (77) (6) (15) (4) (5)
Foreign currency exchange rate changes (4) 28 - - - -
Balance at December 31, $ 2,374 $ 2,445 $ - $ - $ - $ -
Funded Status (Plan assets greater (less) than benefit obligations) at December 31, $ 655 $ 685 $ (279) $ (222) $ (56) $ (53)
Unrecognized Net Actuarial (Gains) Losses $ 372 $ 332 $ 71 $ 30 $ (23) $ (25)
(a)In 2024, changes in discount rates resulted in actuarial gains of $191 million, changes in the retirement rate assumption resulted in actuarial gains of $59 million, changes in the withdrawal rate assumption resulted in actuarial losses of $70 million, changes in the salary scale assumption resulted in actuarial losses of $55 million, and updates to census data resulted in actuarial losses of $19 million. In addition, the use of annuity pricing to measure the benefit obligation of the U.K. pension plan resulted in actuarial losses of $26 million in 2024. Finally, changes in all other assumptions resulted in net actuarial losses of $30 million in 2024. In 2023, changes in discount rates resulted in actuarial losses of $56 million, updates to census data resulted in actuarial losses of $18 million, and the alignment of the benefit obligation to the amount of plan settlement payments resulted in actuarial gains of $20 million. Changes in all other assumptions resulted in net actuarial gains of $2 million in 2023.
(b)At December 31, 2024, the accumulated benefit obligation for the funded and unfunded defined benefit pension plans was $1,619 million and $182 million, respectively (2023: $1,684 million and $181 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
2024 2023 2024 2023 2024 2023
(In millions)
Noncurrent assets $ 655 $ 685 $ - $ - $ - $ -
Current liabilities - - (15) (23) (4) (5)
Noncurrent liabilities - - (264) (199) (52) (48)
Post-retirement benefit assets (liabilities) $ 655 $ 685 $ (279) $ (222) $ (56) $ (53)
Accumulated other comprehensive (income) loss, pre-tax (a) $ 372 $ 332 $ 71 $ 30 $ (23) $ (25)
(a)The after-tax deficit reflected in Accumulated other comprehensive income (loss) was $208 million at December 31, 2024 (2023: $134 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
2024 2023 2022 2024 2023 2022
(In millions)
Service cost $ 40 $ 35 $ 44 $ 3 $ 3 $ 3
Interest cost (a) 91 97 69 3 2 1
Expected return on plan assets (a) (155) (156) (196) - - -
Amortization of unrecognized net actuarial losses (gains) (a) 5 3 11 (1) (2) (1)
Prior service cost (a) 35 - - - - -
Settlement loss (a) - 17 2 - - -
Net Periodic Benefit Cost (Income) (a) $ 16 $ (4) $ (70) $ 5 $ 3 $ 3
(a)These other components of net periodic benefit cost (income) included in Other, net in the Statement of Consolidated Income was $(22) million in 2024 (2023: $(39) million; 2022: $(114) million).
In September 2024, the board of trustees for our U.K. pension plan purchased a bulk annuity policy from an insurer for $483 million covering all benefits payable under the plan. The bulk annuity policy is an asset of the plan. The plan retains responsibility for all liabilities associated with member and beneficiary benefits until such time a buy-out transaction is executed with the insurer. Concurrent with the purchase of the bulk annuity policy, the plan was amended to augment benefits for certain members and beneficiaries to equalize the minimum level of pension inflation protection. Due to the amendments, an interim remeasurement of the funded status was performed at September 30, 2024. The augmentation of benefits generated prior service cost of $35 million, which was recognized immediately in earnings as a component of net periodic benefit cost (income).
At December 31, 2024, the funded status of our U.K. pension plan before any applicable taxes was $78 million, representing the excess of the fair value of plan assets over the benefit obligation. Should a buy-out transaction be executed that settles the entirety of the plan’s benefit obligation, a settlement loss will be recorded to recognize all cumulative net actuarial losses within Accumulated other comprehensive income (loss) associated with the plan. At December 31, 2024, cumulative net actuarial losses associated with the U.K. pension plan were $221 million (pre-tax).
In 2023, the Hess Corporation Employees’ Pension Plan paid lump sums to certain participants totaling $143 million which resulted in a settlement loss of $17 million to recognize net unamortized actuarial losses.
In 2022, the Hess Corporation Employees’ Pension Plan purchased a single premium annuity contract at a cost of $166 million using assets of the plan to settle and transfer certain of its obligations to a third party. This partial settlement resulted in a settlement loss of $13 million to recognize net unamortized actuarial losses.
In 2022, the HOVENSA Legacy Employees’ Pension Plan paid lump sums to certain participants totaling $20 million, and purchased a single premium annuity contract at a cost of $80 million, to settle the plan’s benefit obligation in connection with terminating the plan. The settlement transactions resulted in a settlement gain of $11 million to recognize net unamortized actuarial gains. The assets remaining after settlement of the plan’s projected benefit obligation of $15 million were transferred to the Hess Corporation Employees’ Pension Plan in December 2022.
In 2025, we forecast service cost for our pension and post-retirement medical plans to be approximately $50 million and other components of net periodic benefit cost to be approximately $35 million of income, which is comprised of estimated expected return on plan assets of approximately $150 million, interest cost of approximately $105 million, and amortization of unrecognized net actuarial losses of $10 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:
2024 2023 2022
Benefit Obligations:
Discount rate 5.4% 4.8% 5.0%
Rate of compensation increase 4.4% 3.9% 4.0%
Net Periodic Benefit Cost:
Discount rate
Service cost 4.8% 5.0% 3.3%
Interest cost 4.7% 4.9% 3.0%
Expected rate of return on plan assets 6.4% 6.5% 6.5%
Rate of compensation increase 3.9% 4.0% 3.8%
The actuarial assumptions used to determine benefit obligations at December 31 for the post-retirement medical plan were as follows:
2024 2023 2022
Discount rate 5.5% 4.7% 4.9%
Initial health care trend rate 7.1% 6.0% 6.3%
Ultimate trend rate 4.0% 4.0% 4.0%
Year in which ultimate trend rate is reached 2049 2046 2046
The assumptions used to determine net periodic benefit cost for each year were established at the end of each previous year. In 2024 and 2022, there was an interim remeasurement of the funded status of certain plans due to plan amendments or plan settlements which resulted in net periodic benefit cost being recalculated for the remainder of the year using assumptions as of the interim remeasurement dates. The assumptions disclosed in the preceding table used to determine net periodic benefit cost for 2024 and 2022 are a weighted average of the assumptions as of the end of the previous year and the interim remeasurement dates. Due to the timing of plan settlements in 2023, an interim remeasurement of the funded status was unnecessary in 2023.
The assumptions used to determine benefit obligations were established at each year end. For the U.K. pension plan, the benefit obligation at December 31, 2024 was measured by adjusting the premium paid for the bulk annuity policy for interest cost and benefit payments through December 31, 2024, along with changes in annuity pricing through December 31, 2024. Discount rates for benefit obligations that are not measured using annuity pricing are developed based on a portfolio of high-quality, fixed income debt instruments with maturities that approximate the expected payment of plan obligations.
The overall expected rate of return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of assets to that asset category. The future expected rate of return assumptions for individual asset categories are largely based on inputs from various investment experts regarding their future return expectations for particular asset categories. The expected rate of return on plan assets is applied to the fair value of plan assets to determine the expected return on plan assets component of net periodic benefit cost for the year.
Our investment strategy is to maximize long-term returns at an acceptable level of risk through broad diversification of plan assets in a variety of asset classes. Asset classes and target allocations are determined by our investment committee and include domestic and foreign equities, fixed income, and other investments, including hedge funds, real estate and private equity. Investment managers are prohibited from investing in securities issued by us unless indirectly held as part of an index strategy. The majority of plan assets are highly liquid, providing ample liquidity for benefit payment requirements. The current target allocations, excluding the bulk annuity policy, are 25% equity securities, 50% fixed income securities (including cash and short-term investment funds) and 25% 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, 2024 and 2023 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, 2024
Cash and Short-Term Investment Funds $ 47 $ - $ - $ - $ 47
Equities:
U.S. equities (domestic) 339 - - - 339
International equities (non-U.S.) 38 - - 114 152
Global equities (domestic and non-U.S.) - 5 - - 5
Fixed Income:
Treasury and government related (a) - 353 - - 353
Mortgage-backed securities (b) - 75 - 9 84
Corporate - 439 - 3 442
Other:
Private equity funds - - - 427 427
Real estate funds - - - 97 97
Bulk annuity policy - - 428 - 428
Total investments $ 424 $ 872 $ 428 $ 650 $ 2,374
December 31, 2023
Cash and Short-Term Investment Funds $ 27 $ - $ - $ - $ 27
Equities:
U.S. equities (domestic) 309 - - - 309
International equities (non-U.S.) 52 - - 158 210
Global equities (domestic and non-U.S.) - 6 - 55 61
Fixed Income:
Treasury and government related (a) - 581 - - 581
Mortgage-backed securities (b) - 98 - 12 110
Corporate - 547 - 3 550
Other:
Private equity funds - - - 414 414
Real estate funds - - - 183 183
Bulk annuity policy - - - - -
Total investments $ 388 $ 1,232 $ - $ 825 $ 2,445
(a)Includes securities issued and guaranteed by U.S. and non-U.S. governments, and securities issued by governmental agencies and municipalities.
(b)Comprised of U.S. residential and commercial mortgage-backed securities.
(c)Includes certain investments that have been valued using the net asset value (NAV) practical expedient, and therefore have not been categorized in the fair value hierarchy. The inclusion of such amounts in the above table is intended to aid reconciliation of investments categorized in the fair value hierarchy to total pension plan assets.
The following describes the financial assets of the funded pension plans:
Cash and short-term investment funds - Consists of cash on hand and short-term investment funds that provide for daily investments and redemptions which are classified as Level 1.
Equities - Consists of individually held U.S. and international equity securities. This investment category also includes funds that consist primarily of U.S. and international equity securities. Equity securities, which are individually held and are traded actively on exchanges, are classified as Level 1. Certain funds, consisting primarily of equity securities, are classified as Level 2 if the NAV is determined and published daily, and is the basis for current transactions. Commingled funds, consisting primarily of equity securities held in unitized trusts, are valued using the NAV per fund share.
Fixed income investments - Consists of individually held securities issued by the U.S. government, non-U.S. governments, governmental agencies, municipalities and corporations, and agency and non-agency mortgage-backed securities. This investment category also includes funds that consist primarily of fixed income securities. Individual fixed income securities are generally valued on the basis of evaluated prices from independent pricing services. Such prices are monitored by the trustee, which also serves as the independent third-party custodial firm responsible for safekeeping assets of the particular plan, and are classified as Level 2. 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 commingled funds and limited partnership investments in hedge funds, private equity and real estate funds which are valued at the NAV per fund share. This investment category also includes the bulk annuity policy purchased by the trustees of the U.K. pension plan. The fair value of the bulk annuity policy at December 31, 2024 was measured by adjusting the premium paid of $483 million for interest cost and benefit payments through December 31, 2024 of $5 million and $6 million, respectively, and for changes in annuity pricing through December 31, 2024, and is classified as Level 3. Changes in annuity pricing through December 31, 2024 were determined by evaluating changes in interest rates for securities issued by the U.K. government with maturities that approximate the timing of the annuity payments, and by evaluating changes in inflation rates. Changes in annuity pricing resulted in an unrealized loss of $26 million. Foreign exchange losses recognized upon remeasurement of the bulk annuity contract to U.S. dollars were $28 million. Changes in the fair value of the bulk annuity policy are offset by changes in the benefit obligation and do not affect the funded status.
Contributions and estimated future benefit payments: In 2025, we do not expect to make any contributions to our funded pension plans.
Estimated future benefit payments by the funded and unfunded pension plans, and the post-retirement medical plan, which reflect expected future service, are as follows (in millions):
2025 $ 108
2026 160
2027 117
2028 120
2029 117
Years 2030 to 2034 648
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 $29 million in 2024 for contributions to these plans (2023: $24 million; 2022: $22 million).
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
Sales of net production volumes:
Crude oil revenue $ 3,205 $ 5,525 $ 139 $ - $ 8,869 $ - $ - $ 8,869
Natural gas liquids revenue 613 - - - 613 - - 613
Natural gas revenue 146 - 811 - 957 - - 957
Sales of purchased oil and gas 2,275 111 - - 2,386 - - 2,386
Third-party services - - - - - 24 - 24
Intercompany revenue - - - - - 1,468 (1,468) -
Total sales (b) 6,239 5,636 950 - 12,825 1,492 (1,468) 12,849
Other operating revenues (c) 44 - - - 44 3 - 47
Total sales and other operating revenues $ 6,283 $ 5,636 $ 950 $ - $ 12,869 $ 1,495 $ (1,468) $ 12,896
Sales of net production volumes:
Crude oil revenue $ 3,058 $ 3,486 $ 144 $ - $ 6,688 $ - $ - $ 6,688
Natural gas liquids revenue 529 - - - 529 - - 529
Natural gas revenue 182 - 800 - 982 - - 982
Sales of purchased oil and gas 2,390 70 - - 2,460 - - 2,460
Third-party services - - - - - 8 - 8
Intercompany revenue - - - - - 1,338 (1,338) -
Total sales (b) 6,159 3,556 944 - 10,659 1,346 (1,338) 10,667
Other operating revenues (c) (78) (62) (19) - (159) 3 - (156)
Total sales and other operating revenues $ 6,081 $ 3,494 $ 925 $ - $ 10,500 $ 1,349 $ (1,338) $ 10,511
Sales of net production volumes:
Crude oil revenue $ 3,407 $ 2,771 $ 134 $ 509 $ 6,821 $ - $ - $ 6,821
Natural gas liquids revenue 703 - - - 703 - - 703
Natural gas revenue 438 - 739 21 1,198 - - 1,198
Sales of purchased oil and gas 2,978 53 - 112 3,143 - - 3,143
Intercompany revenue - - - - - 1,273 (1,273) -
Total sales (b) 7,526 2,824 873 642 11,865 1,273 (1,273) 11,865
Other operating revenues (c) (312) (188) - (41) (541) - - (541)
Total sales and other operating revenues $ 7,214 $ 2,636 $ 873 $ 601 $ 11,324 $ 1,273 $ (1,273) $ 11,324
(a)Other includes our interest in the Waha Concession in Libya, which was sold in November 2022.
(b)Guyana crude oil revenue includes $842 million of revenue from non-customers in 2024 (2023: $433 million; 2022: $230 million).
(c)Other operating revenues are not a component of revenues from contracts with customers. Included within other operating revenues are gains (losses) on commodity derivatives of nil in 2024 (2023: $(190) million; 2022: $(585) million).
11. Dispositions
2022: We completed the sale of our 8% interest in the Waha Concession in Libya for net cash consideration of $150 million and recognized a pre-tax gain of $76 million ($76 million after income taxes). We also completed the sale of real property related to our former downstream business for cash consideration of $24 million and recognized a pre-tax gain of $22 million ($22 million after income taxes).
12. Impairment
2024: We recorded a pre-tax charge of $92 million ($92 million after income taxes) to fully impair the net book value of our interests in Conger, a mature field in the Gulf of America, due to a mechanical issue on one of the main producing wells in the third quarter of 2024. Significant inputs used in determining future net cash flows at September 30, 2024 included future prices, estimated expenditures to remedy the mechanical issue, and projected production volumes using risk adjusted oil and gas reserves. Future pricing assumptions were based on forward strip crude oil prices as of September 30, 2024 to the end of field life. Estimated expenditures to remedy the mechanical issue reflect the use of a deepwater drilling rig, and the nature and scope of the work required to return the well to production. A pre-tax charge of $40 million ($38 million after income taxes) was also recorded which resulted from revisions to our estimated abandonment liabilities for uneconomic properties, primarily in the Gulf of America.
2023: We recorded a pre-tax charge of $82 million ($82 million after income taxes) that resulted from revisions to estimated costs to abandon certain wells, pipelines and production facilities in the West Delta Field in the Gulf of America. These abandonment obligations were assigned to us as a former owner after they were discharged from Fieldwood Energy LLC (Fieldwood) as part of its approved bankruptcy plan in 2021. See Note 8, Asset Retirement Obligations.
2022: We recorded a pre-tax charge of $28 million ($28 million after income taxes) that resulted from updates to our estimated abandonment liabilities for non-producing properties in the Gulf of America and $26 million ($26 million after income taxes) to fully impair the net book value of our interests in the Penn State Field in the Gulf of America due to a mechanical issue on the field’s remaining production well.
13. Share-based Compensation
We have established and maintain LTIP for the granting of restricted common shares, PSUs and stock options to our employees. At December 31, 2024, the total number of authorized common stock under the LTIP was 63.5 million shares, of which we have 18.4 million shares available for issuance. Share-based compensation expense consisted of the following:
2024 2023 2022
(In millions)
Restricted stock $ 88 $ 55 $ 52
Performance share units 8 21 20
Stock options 4 11 11
Share-based compensation expense before income taxes $ 100 $ 87 $ 83
Income tax benefit on share-based compensation expense $ - $ - $ -
Based on share-based compensation awards outstanding at December 31, 2024, unearned compensation expense, before income taxes, of $100 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 2024:
Shares of Restricted Common Stock Weighted - Average Price on Date of Grant
(In thousands, except per share amounts)
Outstanding at January 1, 2024 1,021 $ 113.47
Granted 827 142.77
Vested (a) (580) 104.66
Forfeited (39) 131.88
Outstanding at December 31, 2024 1,229 $ 136.76
(a)In 2024, restricted stock with a vesting date fair value of $83 million were vested (2023: $104 million; 2022: $86 million).
Performance share units:
PSUs generally vest three years from the date of grant and are valued using a Monte Carlo simulation on the date of grant.
For the PSUs granted in 2022, the number of shares of common stock to be issued under a PSU agreement is based on a comparison of the Corporation’s total shareholder return (TSR) to the TSR of a predetermined group of peer companies and the S&P 500 index over a three-year performance period ending December 31 of the year prior to settlement of the grant. Payouts of the performance share awards will range from 0% to 200% of the target awards based on the Corporation’s TSR ranking within the peer group. Dividend equivalents for the performance period will accrue on performance shares but will only be paid out on earned shares after the performance period.
For the PSUs granted in 2023, the number of shares of common stock to be issued under a PSU agreement is based on a comparison of the Corporation’s total shareholder return compound annual growth rate (TSR CAGR) to the TSR CAGR of the SPDR S&P Oil & Gas Exploration and Production ETF (XOP), with a modifier determined by comparing the Corporation’s TSR CAGR to the TSR CAGR of the S&P 500 index, over a three-year performance period ending December 31, 2025. Payout of the performance share awards will range from 0% to 200% of the target awards based on the comparison of the Corporation’s TSR CAGR to the XOP's
TSR CAGR. The modifier can only adjust the payout percentage by plus or minus 10%, up to a maximum of 210% or a minimum of 0%. Dividend equivalents for the performance period will accrue on performance shares but will only be paid out on earned shares after the performance period. There were no PSUs granted in 2024.
The following is a summary of PSU activity in 2024:
Performance Share Units Weighted - Average Fair Value on Date of Grant
(In thousands, except per share amounts)
Outstanding at January 1, 2024 512 $ 119.77
Granted - -
Vested (a) (205) 86.70
Forfeited (1) 155.62
Outstanding at December 31, 2024 306 $ 141.81
(a)In 2024, PSUs with a vesting date fair value of $20 million were vested (2023: $55 million; 2022: $37 million).
The following weighted average assumptions were utilized to estimate the fair value of PSU awards:
2024 2023 2022
Risk free interest rate - 4.61 % 1.59 %
Stock price volatility - 0.478 0.584
Contractual term in years - 3.0 3.0
Grant date price of Hess common stock - $ 141.95 $ 101.17
Stock options:
Stock options vest equally on an annual basis 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 2024:
Number of options
(In thousands) Weighted Average Exercise Price per Share Weighted Average Remaining Contractual Term
Outstanding at January 1, 2024 1,510 $ 78.85 6.1 years
Granted - -
Exercised (273) 75.48
Forfeited (3) 123.56
Outstanding at December 31, 2024 1,234 $ 79.49 6.0 years
At December 31, 2024, there were 1.2 million outstanding stock options (1.0 million exercisable) with a weighted average exercise price of $79.49 per share ($70.07 per share for exercisable options), a weighted average remaining contractual life of 6.0 years (5.6 years for exercisable options) and an aggregate intrinsic value of $68 million ($65 million for exercisable options). The intrinsic value of stock options exercised in 2024 was $19 million (2023: $13 million, 2022: $44 million).
The following weighted average assumptions were utilized to estimate the fair value of stock options:
2024 2023 2022
Risk free interest rate - 4.20 % 1.66 %
Stock price volatility - 0.469 0.457
Dividend yield - 1.24 % 1.48 %
Expected life in years - 6.0 6.0
Weighted average fair value per option granted - $ 63.45 $ 39.51
In estimating the fair value of PSUs and stock options, the risk-free interest rate is based on the expected term of the award and is obtained from published sources. The stock price volatility is determined from the historical stock prices of the Corporation using the expected term.
14. Income Taxes
The provision (benefit) for income taxes consisted of:
2024 2023 2022
(In millions)
United States
Federal
Current $ - $ - $ -
Deferred taxes and other accruals 59 31 22
State 13 7 5
72 38 27
Foreign
Current (a) 934 537 789
Deferred taxes and other accruals 196 158 283
1,130 695 1,072
Provision (Benefit) For Income Taxes $ 1,202 $ 733 $ 1,099
(a)Primarily comprised of Guyana in 2024 and 2023, and Guyana and Libya in 2022.
Income (loss) before income taxes consisted of the following:
2024 2023 2022
(In millions)
United States (a) $ (68) $ (191) $ 569
Foreign 4,422 2,662 2,977
Income (Loss) Before Income Taxes $ 4,354 $ 2,471 $ 3,546
(a)Includes substantially all of our interest expense, corporate expense, the results of commodity hedging activities, and amounts attributable to noncontrolling interests.
The difference between our effective income tax rate and the U.S. statutory rate is reconciled below:
2024 2023 2022
U.S. statutory rate 21.0 % 21.0 % 21.0 %
Effect of foreign operations (a) 6.3 7.5 16.5
State income taxes, net of federal income tax 0.2 0.2 0.1
Valuation allowance on current year operations 0.8 4.5 (4.8)
Release of valuation allowance - (1.3) -
Noncontrolling interests in Midstream (0.8) (2.0) (1.6)
Other 0.1 (0.2) (0.2)
Total 27.6 % 29.7 % 31.0 %
(a)The variance in effective income tax rates attributable to the effect of foreign operations is primarily driven by Guyana in 2024 and 2023, and Libya in 2022.
The components of deferred tax liabilities and deferred tax assets at December 31, were as follows:
2024 2023
(In millions)
Deferred Tax Liabilities
Property, plant and equipment and investments $ (2,320) $ (2,117)
Other (101) (108)
Total Deferred Tax Liabilities (2,421) (2,225)
Deferred Tax Assets
Net operating loss carryforwards 4,432 4,406
Tax credit carryforwards 109 109
Property, plant and equipment and investments 641 413
Accrued compensation, deferred credits and other liabilities 101 109
Asset retirement obligations 313 296
Other 339 256
Total Deferred Tax Assets 5,935 5,589
Valuation allowances (a) (3,719) (3,652)
Total deferred tax assets, net of valuation allowances 2,216 1,937
Net Deferred Tax Assets (Liabilities) $ (205) $ (288)
(a)In 2024, the valuation allowance increased by $67 million (2023: decrease of $6 million; 2022: decrease of $180 million).
In the Consolidated Balance Sheet, deferred tax assets and liabilities are netted by taxing jurisdiction and are recorded at December 31, as follows:
2024 2023
(In millions)
Deferred income taxes (long-term asset) $ 579 $ 320
Deferred income taxes (long-term liability) (784) (608)
Net Deferred Tax Assets (Liabilities) $ (205) $ (288)
At December 31, 2024, we have a gross deferred tax asset related to net operating loss carryforwards of $4,432 million before application of valuation allowances. The deferred tax asset is comprised of $129 million attributable to foreign net operating losses which will begin to expire in 2025, $3,796 million attributable to U.S. federal operating losses which will begin to expire in 2034, and $507 million attributable to losses in various U.S. states which will begin to expire in 2025. A full valuation allowance is established against the deferred tax asset attributable to U.S. federal and state net operating losses, except for $57 million of U.S. federal and $12 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, 2024, we have U.S. state tax credit carryforwards of $27 million, which will begin to expire in 2034, $82 million of other U.S. federal business credit carryforwards, which will begin to expire in 2036. A full valuation allowance is established against the deferred tax asset attributable to these credits.
At December 31, 2024, the Consolidated Balance Sheet reflects a $3,719 million (2023: $3,652 million) valuation allowance against the net deferred tax assets for multiple jurisdictions based on application of the relevant accounting standards. Hess continues to maintain a full valuation allowance against its deferred tax assets in the U.S. (non-Midstream) and certain other jurisdictions. The increase in valuation allowance year over year is primarily due to an increase in deferred tax asset balances in the U.S. (non-Midstream). 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 U.S. is in a cumulative loss position which constitutes significant objective negative evidence. Until we see a significant and sustained pattern of objectively verifiable income, we do not assign significant weight to subjective long-term projections of future income and thus maintain a full valuation allowance against our U.S. (non-Midstream) federal and state deferred tax assets. If anticipated future earnings are exceeded, sufficient positive evidence may become available to support the release of valuation allowance in the future. This would result in the recognition of certain deferred tax assets on the balance sheet and a decrease to income tax expense for the period in which the release is recognized.
Below is a reconciliation of the gross beginning and ending amounts of unrecognized tax benefits:
2024 2023 2022
(In millions)
Balance at January 1 $ 111 $ 120 $ 133
Additions based on tax positions taken in the current year - - 17
Additions based on tax positions of prior years - - -
Reductions based on tax positions of prior years - (9) (30)
Balance at December 31 $ 111 $ 111 $ 120
There is no balance at December 31, 2024 for unrecognized tax benefits that, if recognized would impact our effective income tax rate. Over the next 12 months, we have no unrecognized benefit that is reasonably possible to decrease due to settlements with taxing authorities or other resolutions, as well as lapses in statutes of limitation. At December 31, 2024, we have no accrued interest and penalties related to unrecognized tax benefits (2023: $0 million).
We file income tax returns in the U.S. and various foreign jurisdictions. We are no longer subject to examinations by income tax authorities in most jurisdictions for years prior to 2009.
15. Outstanding and Weighted Average Common Shares
Net income and weighted average number of common shares used in the basic and diluted earnings per share computations were as follows:
2024 2023 2022
(In millions except per share amounts)
Net Income Attributable to Hess Corporation:
Net income $ 3,152 $ 1,738 $ 2,447
Less: Net income attributable to noncontrolling interests 383 356 351
Net income attributable to Hess Corporation $ 2,769 $ 1,382 $ 2,096
Weighted Average Number of Common Shares Outstanding:
Basic 306.8 305.9 308.1
Effect of dilutive securities
Restricted common stock 0.5 0.5 0.7
Stock options 0.6 0.7 0.6
Performance share units 0.4 0.5 0.2
Diluted 308.3 307.6 309.6
Net Income Attributable to Hess Corporation per Common Share:
Basic $ 9.03 $ 4.52 $ 6.80
Diluted $ 8.98 $ 4.49 $ 6.77
Antidilutive shares excluded from the computation of diluted shares:
Restricted common stock - - -
Stock options 0.2 0.2 0.2
Performance share units - - -
The following table provides the changes in our outstanding common shares:
2024 2023 2022
(In millions)
Balance at January 1 307.2 306.2 309.7
Activity related to restricted stock awards, net 0.7 0.4 0.5
Stock options exercised 0.3 0.2 0.9
PSUs vested 0.1 0.4 0.5
Shares repurchased - - (5.4)
Balance at December 31 308.3 307.2 306.2
Common Stock Repurchase Plan:
On March 1, 2023, our Board of Directors approved a new authorization for the repurchase of our common stock in an aggregate amount of up to $1 billion. This new authorization replaced our previous repurchase authorization which was fully utilized at the end of 2022. There were no shares of our common stock repurchased during 2024 or 2023. During 2022, we repurchased approximately 5.4 million shares of our common stock for $650 million ($20 million was paid subsequent to December 31, 2022). Shares of common stock repurchased are retired upon settlement of the trade.
Common Stock Dividends:
Cash dividends declared on common stock totaled $1.875 per share in 2024 (2023: $1.75 per share; 2022: $1.50 per share).
16. Supplementary Cash Flow Information
The following information supplements the Statement of Consolidated Cash Flows:
2024 2023 2022
(In millions)
Cash Flows From Operating Activities
Interest paid $ (408) $ (470) $ (486)
Net income taxes (paid) refunded (a) (78) (71) (1,036)
Cash Flows From Investing Activities
Additions to property, plant and equipment - E&P:
Capital expenditures incurred - E&P $ (4,714) $ (4,033) $ (2,589)
Increase (decrease) in related liabilities 74 149 102
Additions to property, plant and equipment - E&P $ (4,640) $ (3,884) $ (2,487)
Additions to property, plant and equipment - Midstream:
Capital expenditures incurred - Midstream $ (288) $ (246) $ (232)
Increase (decrease) in related liabilities (18) 22 (6)
Additions to property, plant and equipment - Midstream $ (306) $ (224) $ (238)
(a)Does not include the value of the portion of gross production from the Stabroek block used to satisfy the Guyana income tax liability.
17. Guarantees, Contingencies and Commitments
Guarantees and Contingencies
We are subject to loss contingencies with respect to various claims, lawsuits and other proceedings. A liability is recognized in our consolidated financial statements when it is probable that a loss has been incurred and the amount can be reasonably estimated. If the risk of loss is probable, but the amount cannot be reasonably estimated or the risk of loss is only reasonably possible, a liability is not accrued; however, we disclose the nature of those contingencies. We cannot predict with certainty if, how or when existing claims, lawsuits and proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages.
We, along with many companies that have been or continue to be engaged in refining and marketing of gasoline, have been a party to lawsuits and claims related to the use of MTBE in gasoline. A series of similar lawsuits, many involving water utilities or governmental entities, were filed in jurisdictions across the United States against producers of MTBE and petroleum refiners who produced gasoline containing MTBE, including us. The principal allegation in all cases was that gasoline containing MTBE was a defective product and that these producers and refiners are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE. The majority of the cases asserted against us have been settled. There are two remaining active cases, filed by Pennsylvania and Maryland. In June 2014, the Commonwealth of Pennsylvania filed a lawsuit alleging that we and all major oil companies with operations in Pennsylvania, have damaged the groundwater by introducing thereto gasoline with MTBE. The Pennsylvania suit has been forwarded to the existing MTBE multidistrict litigation pending in the Southern District of New York. In December 2017, the State of Maryland filed a lawsuit alleging that we and other major oil companies damaged the groundwater in Maryland by introducing thereto gasoline with MTBE. The suit, filed in Maryland state court, was served on us in January 2018 and has been removed to federal court by the defendants.
In March 2014, we received an Administrative Order from the EPA requiring us and 26 other parties to undertake the Remedial Design for the remedy selected by the EPA for the Gowanus Canal Superfund Site in Brooklyn, New York. Our alleged liability derives from our former ownership and operation of a fuel oil terminal and connected shipbuilding and repair facility adjacent to the
Canal. The remedy selected by the EPA includes dredging of surface sediments and the placement of a cap over the deeper sediments throughout the Canal and in-situ stabilization of certain contaminated sediments that will remain in place below the cap. The EPA’s original estimate was that this remedy would cost $506 million; however, the ultimate costs that will be incurred in connection with the design and implementation of the remedy remain uncertain. We have complied with the EPA’s March 2014 Administrative Order and contributed funding for the Remedial Design based on an allocation of costs among the parties determined by a third-party expert. In January 2020, we received an additional Administrative Order from the EPA requiring us and several other parties to begin Remedial Action along the uppermost portion of the Canal. We intend to comply with this Administrative Order. The remediation work began in the fourth quarter of 2020. Based on currently known facts and circumstances, we do not believe that this matter will result in a significant liability to us, and the costs will continue to be allocated amongst the parties, as they were for the Remedial Design.
From time to time, we are involved in other judicial and administrative proceedings relating to environmental matters. We periodically receive notices from the EPA that we are a “potential responsible party” under the Superfund legislation with respect to various waste disposal sites. Under this legislation, all potentially responsible parties may be jointly and severally liable. For any site for which we have received such a notice, the EPA’s claims or assertions of liability against us relating to these sites have not been fully developed, or the EPA’s claims have been settled or a settlement is under consideration, in all cases for amounts that are not material. Beginning in 2017, certain states, municipalities and private associations in California, Delaware, Maryland, Rhode Island and South Carolina separately filed lawsuits against oil, gas and coal producers, including us, for alleged damages purportedly caused by climate change. These proceedings include claims for monetary damages and injunctive relief. Beginning in 2013, various parishes in Louisiana filed suit against approximately 100 oil and gas companies, including us, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. The ultimate impact of such climate and other aforementioned environmental proceedings, and of any related proceedings by private parties, on our business or accounts cannot be predicted at this time due to the large number of other potentially responsible parties and the speculative nature of clean-up cost estimates.
We are also involved in six claims in federal and state courts in North Dakota related to post-production deductions from royalty and working interest payments. The plaintiffs in these cases assert that we take unauthorized or excessive post-production deductions from royalty or working interest payments for various oil and gas processing and transportation related costs and expenses. These plaintiffs seek reimbursement for allegedly underpaid revenue. It is our position that these costs and expenses are actual, reasonable, necessary, and authorized by the respective leases and North Dakota law. We believe that based on the facts and circumstances of these claims and because we have viable defenses, loss is not probable and the ultimate impact of these claims on our business or accounts cannot be estimated at this stage of the proceedings due to the speculative and indeterminate damages.
We may also be exposed to future decommissioning liabilities for divested assets in the event the current or future owners of facilities previously owned by us are determined to be unable to perform such actions, whether due to bankruptcy or otherwise. We cannot predict with certainty if, how or when such proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages. Numerous issues may need to be resolved, including through potentially lengthy discovery and determination of important factual matters before a loss or range of loss can be reasonably estimated for any proceeding.
Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of lawsuits, claims and proceedings, including the matters disclosed above, is not expected to have a material adverse effect on our financial condition, results of operations or cash flows. However, we could incur judgments, enter into settlements, or revise our opinion regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations in the period in which the amounts are accrued and our cash flows in the period in which the amounts are paid.
Unconditional Purchase Obligations and Commitments
The following table shows aggregate information for certain unconditional purchase obligations and commitments at December 31, 2024, which are not included elsewhere within these Consolidated Financial Statements:
Payments Due by Period
Total 2025 2026 2027 2028 2029 Thereafter
(In millions)
Capital expenditures $ 7,936 $ 2,337 $ 2,364 $ 1,904 $ 711 $ 393 $ 227
Operating expenses 673 254 56 50 63 63 187
Transportation and related contracts 1,948 258 281 266 259 255 629
18. Segment Information
We 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, 2024 were in Guyana, the U.S., Malaysia and the JDA and Libya (sold in November 2022). The Midstream operating segment provides fee-based services, including gathering, compressing and processing natural gas and fractionating NGL; gathering, terminaling, loading and transporting crude oil and NGL; storing and terminaling propane, and water handling services primarily in the Bakken shale play of North Dakota. All unallocated costs are reflected under Corporate, Interest and Other.
Our Chief Executive Officer is our Chief Operating Decision Maker ("CODM"). The CODM oversees the drafting of the budget, which is submitted to the board of directors each year for approval, and allocates resources during the budgeting process to our operating segments based on various factors, including project economics and contractual commitments. The CODM assesses performance by monitoring significant changes to the forecast and net income attributable to Hess Corporation for each operating segment.
The following table presents operating segment financial data (in millions):
Exploration and Production Midstream Corporate, Interest and Other Eliminations Total
Sales and other operating revenues $ 12,869 $ 27 $ - $ - $ 12,896
Intersegment revenues - 1,468 - (1,468) -
Total sales and other operating revenues 12,869 1,495 - (1,468) 12,896
Less:
Marketing expenses, including purchased oil and gas 2,695 - - (75) 2,620
Operating costs and expenses 1,631 347 - (17) 1,961
Production and severance taxes 234 - - - 234
Midstream tariffs 1,376 - - (1,376) -
Exploration expenses, excluding dry holes 167 - - - 167
General and administrative expenses 321 26 145 - 492
Depreciation, depletion and amortization 2,282 203 2 - 2,487
Provision for income taxes 1,130 72 - - 1,202
Other segment items (a) 253 571 140 - 964
Net income (loss) attributable to Hess Corporation $ 2,780 $ 276 $ (287) $ - $ 2,769
Sales and other operating revenues $ 10,500 $ 11 $ - $ - $ 10,511
Intersegment revenues - 1,338 - (1,338) -
Total sales and other operating revenues 10,500 1,349 - (1,338) 10,511
Less:
Marketing expenses, including purchased oil and gas 2,809 - - (77) 2,732
Operating costs and expenses 1,479 313 - (16) 1,776
Production and severance taxes 216 - - - 216
Midstream tariffs 1,245 - - (1,245) -
Exploration expenses, excluding dry holes 170 - - - 170
General and administrative expenses 254 26 247 - 527
Depreciation, depletion and amortization 1,852 193 1 - 2,046
Provision for income taxes 695 38 - - 733
Other segment items (a) 179 527 223 - 929
Net income (loss) attributable to Hess Corporation $ 1,601 $ 252 $ (471) $ - $ 1,382
Exploration and Production Midstream Corporate, Interest and Other Eliminations Total
Sales and other operating revenues $ 11,324 $ - $ - $ - $ 11,324
Intersegment revenues - 1,273 - (1,273) -
Total sales and other operating revenues 11,324 1,273 - (1,273) 11,324
Less:
Marketing expenses, including purchased oil and gas 3,394 - - (66) 3,328
Operating costs and expenses 1,186 280 - (14) 1,452
Production and severance taxes 255 - - - 255
Midstream tariffs 1,193 - - (1,193) -
Exploration expenses, excluding dry holes 152 - - - 152
General and administrative expenses 224 23 284 - 531
Depreciation, depletion and amortization 1,520 181 2 - 1,703
Provision for income taxes 1,072 27 - - 1,099
Other segment items (a) (68) 493 283 - 708
Net income (loss) attributable to Hess Corporation $ 2,396 $ 269 $ (569) $ - $ 2,096
(a)Other segment items include gains on asset sales, other non-operating income, exploratory dry hole costs, interest expense, long-lived asset impairment, and net income (loss) attributable to noncontrolling interests.
The following table presents other segment disclosures (in millions):
Exploration and Production Midstream Corporate, Interest and Other Eliminations Total
Interest expense - 204 208 - 412
Impairment 132 - - - 132
Investment in affiliates 67 87 - - 154
Identifiable assets 20,593 4,343 1,615 - 26,551
Capital expenditures 4,714 288 - - 5,002
Interest expense - 179 299 - 478
Impairment 82 - - - 82
Investment in affiliates 76 90 - - 166
Identifiable assets 17,931 3,984 2,092 - 24,007
Capital expenditures 4,033 246 - - 4,279
Interest expense - 150 343 - 493
Impairment 54 - - - 54
Capital expenditures 2,589 232 - - 2,821
Corporate, Interest and Other had interest income of $65 million in 2024 (2023: $82 million, 2022: $32 million) which is included in Other, net in the Statement of Consolidated Income.
The following table presents financial information by major geographic area:
United States Guyana Malaysia and JDA Other (a) Corporate, Interest and Other Total
(In millions)
Sales and Other Operating Revenues $ 6,310 $ 5,636 $ 950 $ - $ - $ 12,896
Property, Plant and Equipment (Net) (b) 11,122 8,069 684 41 5 19,921
Sales and Other Operating Revenues $ 6,092 $ 3,494 $ 925 $ - $ - $ 10,511
Property, Plant and Equipment (Net) (b) 10,554 5,957 872 42 7 17,432
Sales and Other Operating Revenues $ 7,214 $ 2,636 $ 873 $ 601 $ - $ 11,324
(a)Other includes our interests in Libya (sold in November 2022) and Suriname.
(b)Property, plant and equipment in the United States in 2024 includes $7,797 million (2023: $7,325 million) attributable to the E&P segment and $3,325 million (2023: $3,229 million) attributable to the Midstream segment.
19. Financial Risk Management Activities
In the normal course of our business, we are exposed to commodity risks related to changes in the prices of crude oil and natural gas, as well as changes in interest rates and foreign currency values. In the disclosures that follow, corporate financial risk management activities refer to the mitigation of these risks through hedging activities. We maintain a control environment for all of our financial risk management activities under the direction of our Chief Risk Officer. Our Treasury department is responsible for administering foreign exchange rate and interest rate hedging programs using similar controls and processes, where applicable. Hedging strategies are reviewed annually by the Audit Committee of the Board of Directors.
Corporate Financial Risk Management Activities:
Financial risk management activities include transactions designed to reduce risk in the selling prices of crude oil or natural gas we produce or reduce our exposure to foreign currency or interest rate movements. Generally, futures, swaps or option strategies may be used to fix the forward selling price, or establish a floor price or a range banded with a floor and ceiling price, for a portion of our crude oil or natural gas production. Such strategies are subject to certain limitations under the Merger Agreement. Forward contracts or swaps may also be used to purchase certain currencies in which we conduct business with the intent of reducing exposure to foreign currency fluctuations. At December 31, 2024, these forward contracts and swaps relate to the British Pound and Malaysian Ringgit. Interest rate swaps may be used to convert interest payments on certain long-term debt from fixed to floating rates.
The notional amounts of outstanding financial risk management derivative contracts were as follows:
December 31, 2024 December 31, 2023
(In millions)
Foreign exchange forwards and swaps $ 189 $ 226
Interest rate swaps $ - $ 100
Derivative contracts designated as hedging instruments:
Crude oil derivatives designated as cash flow hedges: Crude oil hedging contracts decreased Sales and other operating revenues by $190 million in 2023 (2022: decrease of $585 million). There were no open crude oil hedging contracts during 2024.
Interest rate swaps designated as fair value hedges: At December 31, 2023, we had interest rate swaps with gross notional amounts totaling $100 million, which were designated as fair value hedges and relate to debt where we have converted interest payments from fixed to floating rates. These interest rate swaps expired in July 2024. 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. The fair value of our interest rate swaps was a liability of $2 million at December 31, 2023.
Derivative contracts not designated as hedging instruments:
Foreign exchange: Foreign exchange gains and losses, which are reported in Other, net in Revenues and non-operating income in the Statement of Consolidated Income, were gains of $3 million in 2024 (2023: $2 million gains; 2022: $2 million losses). A component of foreign exchange gains and losses is the result of foreign exchange derivative contracts that are not designated as hedges, which amounted to net losses of $1 million in 2024 (2023: $2 million losses; 2022: $14 million gains). The fair value of our foreign exchange forwards and swaps was an asset of less than $1 million at December 31, 2024 (2023: $6 million liability).
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, 2024, our accounts receivable were concentrated with the following counterparty industry segments: Integrated companies 42%, Independent E&P companies 36%, Refining and marketing companies 12%, Storage and transportation companies 3%, National oil companies 2%, and Others 5%. 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, 2024, we had outstanding letters of credit totaling $85 million (2023: $88 million).
Fair Value Measurement: At December 31, 2024, our total long-term debt, which was substantially comprised of fixed rate debt instruments, had a carrying value of $8,578 million and a fair value of $8,750 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, 2024 and December 31, 2023.
20. Subsequent Events
In January 2025, HESM Opco repurchased 2.6 million HESM Opco Class B units held by affiliates of Hess Corporation and GIP for $100 million. The unit repurchase was financed using borrowings under HESM Opco’s revolving credit facility. In February 2025, Hess Midstream LP completed an underwritten public equity offering of 12.7 million Hess Midstream LP Class A shares held by an affiliate of GIP. Hess Corporation did not receive any proceeds from the public equity offering. After giving effect to these transactions, public shareholders of Class A shares of Hess Midstream LP own approximately 54%, GIP owns approximately 8%, and Hess Corporation owns approximately 38% of the consolidated entity on an as-exchanged basis.
In February 2025, HESM Opco issued $800 million in aggregate principal amount of 5.875% fixed-rate senior unsecured notes due in 2028 in a private offering. HESM Opco intends to use the proceeds from issuance of the new senior unsecured notes, along with borrowings under its revolving credit facility, to redeem its outstanding 5.625% senior notes due in 2026.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED)
The Supplementary Oil and Gas Data that follows is presented in accordance with ASC 932, Disclosures about Oil and Gas Producing Activities, and includes (1) costs incurred, capitalized costs and results of operations relating to oil and gas producing activities, (2) net proved oil and gas reserves and (3) a standardized measure of discounted future net cash flows relating to proved oil and gas reserves, including a reconciliation of changes therein.
Costs Incurred in Oil and Gas Producing Activities
For the Years Ended December 31 Total United
States Guyana Malaysia and JDA Other (a)
(In millions)
Property acquisitions
Unproved $ 88 $ 88 $ - $ - $ -
Proved - - - - -
Exploration 480 203 254 - 23
Production and development capital expenditures (b) 4,516 1,628 2,725 158 5
Property acquisitions
Unproved $ 8 $ 8 $ - $ - $ -
Proved - - - - -
Exploration 484 167 271 5 41
Production and development capital expenditures (b) (c) 3,885 1,424 2,258 203 -
Property acquisitions
Unproved $ 1 $ 1 $ - $ - $ -
Proved - - - - -
Exploration 489 158 259 11 61
Production and development capital expenditures (b) 2,449 970 1,167 303 9
(a)Other includes our interests in Libya (sold in November 2022), Suriname and Canada.
(b)Includes an increase for net accruals and revisions of asset retirement obligations of $225 million in 2024 (2023: $201 million increase; 2022: $218 million increase).
(c)Net accruals for asset retirement obligations in the United States exclude a charge of $82 million in 2023 related to our former interests in the West Delta Field in the Gulf of America which we sold to a Fieldwood predecessor in 2004. See Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements.
Capitalized Costs Relating to Oil and Gas Producing Activities
At December 31,
2024 2023
(In millions)
Unproved properties $ 179 $ 103
Proved properties 2,638 2,660
Wells, equipment and related facilities 33,059 29,159
Total costs 35,876 31,922
Less: Reserve for depreciation, depletion, amortization and lease impairment 19,285 17,726
Net Capitalized Costs $ 16,591 $ 14,196
Results of Operations for Oil and Gas Producing Activities
The results of operations shown below exclude non-oil and gas producing activities, primarily gains (losses) on sales of oil and gas properties, sales of purchased crude oil, NGL and natural gas from third parties, interest expense and non-operating income. Revenue from net production volumes include crude oil hedging results and are net of payments for unutilized committed transportation capacity. Therefore, these results are on a different basis than the net income (loss) from E&P operations reported in Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 18, Segment Information in the Notes to Consolidated Financial Statements.
For the Years Ended December 31 Total United
States Guyana (a) Malaysia and JDA Other (b)
(In millions)
Revenue from net production volumes $ 10,220 $ 3,814 $ 5,456 $ 950 $ -
Costs and Expenses
Operating costs and expenses 1,631 955 458 218 -
Production and severance taxes 234 222 - 12 -
Midstream tariffs 1,376 1,376 - - -
Exploration expenses, including dry holes and lease impairment 326 219 36 48 23
General and administrative expenses 321 286 18 17 -
Depreciation, depletion and amortization 2,282 1,115 846 320 1
Impairment 132 127 - - 5
Total Costs and Expenses 6,302 4,300 1,358 615 29
Results of Operations Before Income Taxes 3,918 (486) 4,098 335 (29)
Provision (benefit) for income taxes 1,129 - 1,046 84 (1)
Results of Operations $ 2,789 $ (486) $ 3,052 $ 251 $ (28)
Revenue from net production volumes $ 7,761 $ 3,462 $ 3,374 $ 925 $ -
Costs and Expenses
Operating costs and expenses 1,479 901 402 176 -
Production and severance taxes 216 206 - 10 -
Midstream tariffs 1,245 1,245 - - -
Exploration expenses, including dry holes and lease impairment 317 170 97 1 49
General and administrative expenses 254 213 26 15 -
Depreciation, depletion and amortization 1,852 904 526 422 -
Impairment 82 82 - - -
Total Costs and Expenses 5,445 3,721 1,051 624 49
Results of Operations Before Income Taxes 2,316 (259) 2,323 301 (49)
Provision (benefit) for income taxes 696 - 628 67 1
Results of Operations $ 1,620 $ (259) $ 1,695 $ 234 $ (50)
Revenue from net production volumes $ 7,976 $ 4,076 $ 2,538 $ 873 $ 489
Costs and Expenses
Operating costs and expenses 1,186 706 320 143 17
Production and severance taxes 255 242 - 13 -
Midstream tariffs 1,193 1,193 - - -
Exploration expenses, including dry holes and lease impairment 208 122 63 4 19
General and administrative expenses 224 189 18 16 1
Depreciation, depletion and amortization 1,520 810 394 297 19
Impairment 54 54 - - -
Total Costs and Expenses 4,640 3,316 795 473 56
Results of Operations Before Income Taxes 3,336 760 1,743 400 433
Provision (benefit) for income taxes 991 - 514 32 445
Results of Operations $ 2,345 $ 760 $ 1,229 $ 368 $ (12)
(a)Production commenced from Liza Phase 1 in December 2019, Liza Phase 2 in February 2022 and Payara in November 2023. Operating costs and expenses also include pre-development costs from the operator for future phases of development and Hess internal costs.
(b)Other includes our interests in Libya (sold in November 2022), Suriname and Canada.
Proved Oil and Gas Reserves
Our proved oil and gas reserves are calculated in accordance with the Securities and Exchange Commission (SEC) regulations and the requirements of the Financial Accounting Standards Board. Proved oil and gas reserves are quantities, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. Our estimation of net recoverable quantities of liquid hydrocarbons and natural gas is a highly technical process performed by our internal teams of geoscience and reservoir engineering professionals. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of June 25, 2019).” The method or combination of methods used in the analysis of each reservoir is based on the maturity of the reservoir, the completeness of the subsurface data available at the time of the estimate, the stage of reservoir development and the production history. Subsurface data used included well logs, reservoir core and fluid samples, production and pressure testing, static and dynamic pressure information, and reservoir surveillance. Where applicable, reliable technologies may be used in reserve estimation, as defined in the SEC regulations. These technologies, including computational methods, must have been field tested and demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In some cases, where appropriate, use of empirical and analytical methods, combined with analog data were used. Analytic tools, including reservoir simulation, geologic modeling and seismic processing, have been used in the interpretation of the subsurface data. These technologies were used to increase the quality and confidence in the reserves estimates.
In order for reserves to be classified as proved, any required government approvals must be obtained and depending on the cost of the project, either senior management or the Board of Directors must commit to fund the development. Our proved reserves are subject to certain risks and uncertainties, which are discussed in Part 1, Item 1A. Risk Factors of this Form 10-K.
Internal Controls
The Corporation maintains internal controls over its oil and gas reserve estimation processes, which are administered by our Global Reserves group and our Chief Financial Officer. Estimates of reserves are prepared by technical staff who work directly with the oil and gas properties using industry standard reserve estimation principles, definitions and methodologies. Each year, reserve estimates of the Corporation’s assets are subject to internal technical audits and reviews. In addition, an independent third-party reserve engineer reviews and audits a significant portion of the Corporation’s reported reserves (see pages 95 through 99). Reserve estimates are reviewed by senior management and the Board of Directors.
Qualifications
The person primarily responsible for overseeing the preparation of the Corporation’s oil and gas reserves during 2024 was the Director, Global Reserves. He is a member of the Society of Petroleum Engineers and has over 20 years of experience in the oil and gas industry with a MSc degree in Petroleum Engineering. His experience has been primarily focused on oil and gas subsurface understanding and reserves estimation in both domestic and international areas. He is also responsible for the Corporation’s Global Reserves group, which is the internal organization that establishes the policies and processes used within the operating units to estimate reserves and perform internal technical reserve audits and reviews.
Reserves Audit
We engaged the consulting firm of DeGolyer and MacNaughton (D&M) to perform an audit of the internally prepared reserve estimates on certain fields aggregating approximately 85% of 2024 year-end reported reserve quantities on a barrel of oil equivalent basis (2023: 89%). The purpose of this audit was to provide additional assurance on the reasonableness of internally prepared reserve estimates and compliance with SEC regulations. The D&M report, dated February 5, 2025, on the Corporation’s estimated oil and gas reserves was prepared using standard geological and engineering methods generally recognized in the petroleum industry. D&M is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years. D&M’s letter report on the Corporation’s December 31, 2024 oil and gas reserves is included as an exhibit to this Form 10-K. While the D&M report should be read in its entirety, the report concludes that for the properties reviewed by D&M, the total net proved reserve estimates prepared by Hess and independently evaluated by D&M, in the aggregate, differed by approximately 2.6% (2023: approximately 1.3%) of total audited net proved reserves on a barrel of oil equivalent basis. The report also includes among other information, the qualifications of the technical person primarily responsible for overseeing the reserve audit.
Crude Oil Prices Used to Estimate Proved Reserves
Proved reserves are calculated using the average price during the twelve-month period before December 31 determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices are defined by contractual agreements, excluding escalations based on future conditions. Crude oil prices used in the determination of proved reserves at December 31, 2024 were $74.88 per barrel for WTI (2023: $78.10; 2022: $94.13) and $78.81 per barrel for Brent (2023:
$82.51; 2022: $97.98). New York Mercantile Exchange (NYMEX) natural gas prices used were $2.37 per mcf in 2024 (2023: $2.75; 2022: $6.44).
At December 31, 2024, spot prices closed at $71.72 per barrel for WTI and $74.64 per barrel for Brent. If crude oil prices in 2025 are at levels below that used in determining 2024 proved reserves, we may recognize negative revisions to our December 31, 2025 proved undeveloped reserves. In addition, we may recognize negative revisions to proved developed reserves, which can vary significantly by asset due to differing operating cost structures. Conversely, price increases in 2025 above those used in determining 2024 proved reserves could result in positive revisions to proved developed and proved undeveloped reserves at December 31, 2025. It is difficult to estimate the magnitude of any potential net negative or positive change in proved reserves at December 31, 2025, due to numerous currently unknown factors, including 2025 crude oil prices, the amount of any additions to proved reserves, positive or negative revisions in proved reserves related to 2025 reservoir performance, the levels to which industry costs will change in response to 2025 crude oil prices, and management’s plans as of December 31, 2025 for developing proved undeveloped reserves.
Following are the Corporation’s proved reserves:
Crude Oil & Condensate Natural Gas Liquids
United
States Guyana Malaysia and
JDA Other (a) Total United
States Total
(Millions of bbls) (Millions of bbls)
Net Proved Reserves
At January 1, 2022 498 205 5 100 808 233 233
Revisions of previous estimates (35) 4 (1) (1) (33) 10 10
Extensions, discoveries and other additions 55 100 - - 155 22 22
Sales of minerals in place - - - (93) (93) - -
Production (35) (29) (1) (6) (71) (20) (20)
At December 31, 2022 483 280 3 - 766 245 245
Revisions of previous estimates (19) 71 1 - 53 26 26
Extensions, discoveries and other additions 43 78 1 - 122 16 16
Production (38) (42) (2) - (82) (25) (25)
At December 31, 2023 469 387 3 - 859 262 262
Revisions of previous estimates (54) 53 1 - - 18 18
Extensions, discoveries and other additions 79 65 - - 144 40 40
Production (42) (68) (2) - (112) (28) (28)
At December 31, 2024 452 437 2 - 891 292 292
Net Proved Developed Reserves
At January 1, 2022 283 65 3 100 451 138 138
At December 31, 2022 277 116 3 - 396 156 156
At December 31, 2023 265 201 3 - 469 173 173
At December 31, 2024 258 209 2 - 469 191 191
Net Proved Undeveloped Reserves
At January 1, 2022 215 140 2 - 357 95 95
At December 31, 2022 206 164 - - 370 89 89
At December 31, 2023 204 186 - - 390 89 89
At December 31, 2024 194 228 - - 422 101 101
(a)Other includes our interests in Libya (sold in November 2022).
Natural Gas Total
United
States Guyana (b) Malaysia and
JDA Other (c) Total United
States Guyana Malaysia and
JDA Other (c) Total
(Millions of mcf) (Millions of boe)
Net Proved Reserves
At January 1, 2022 935 48 525 98 1,606 887 213 93 116 1,309
Revisions of previous estimates 57 17 (15) (1) 58 (16) 7 (3) (1) (13)
Extensions, discoveries and other additions 92 29 1 - 122 92 105 - - 197
Sales of minerals in place - - - (94) (94) - - - (109) (109)
Production (a) (80) (3) (136) (3) (222) (68) (30) (24) (6) (128)
At December 31, 2022 (d) 1,004 91 375 - 1,470 895 295 66 - 1,256
Revisions of previous estimates 16 18 41 - 75 10 74 8 - 92
Extensions, discoveries and other additions 65 81 38 - 184 70 92 7 - 169
Production (a) (93) (5) (139) - (237) (79) (43) (25) - (147)
At December 31, 2023 (d) 992 185 315 - 1,492 896 418 56 - 1,370
Revisions of previous estimates 59 1 14 - 74 (26) 53 3 - 30
Extensions, discoveries and other additions 159 27 12 - 198 145 70 2 - 217
Production (a) (104) (6) (126) - (236) (87) (69) (23) - (179)
At December 31, 2024 (d) 1,106 207 215 - 1,528 928 472 38 - 1,438
Net Proved Developed Reserves
At January 1, 2022 568 17 394 98 1,077 516 68 69 116 769
At December 31, 2022 648 37 304 - 989 541 122 54 - 717
At December 31, 2023 656 71 288 - 1,015 547 213 51 - 811
At December 31, 2024 727 88 208 - 1,023 570 224 37 - 831
Net Proved Undeveloped Reserves
At January 1, 2022 367 31 131 - 529 371 145 24 - 540
At December 31, 2022 356 54 71 - 481 354 173 12 - 539
At December 31, 2023 336 114 27 - 477 349 205 5 - 559
At December 31, 2024 379 119 7 - 505 358 248 1 - 607
(a)Natural gas production in 2024 includes 17 million mcf used for fuel (2023: 17 million mcf; 2022: 14 million mcf).
(b)Guyana natural gas reserves at December 31, 2024 and 2023 reflect natural gas to be sold from the Liza Field to supply the 300 megawatt onshore power plant that will be constructed and operated by the Government of Guyana, and natural gas that will be consumed for fuel. Guyana natural gas reserves at December 31, 2022 reflect natural gas that will be consumed for fuel.
(c)Other includes our interests in Libya (sold in November 2022).
(d)Natural gas to be consumed as fuel represents less than 3% of total proved reserves on a barrel of oil equivalent basis at December 31, 2024, 2023 and 2022.
Extensions, discoveries and other additions (‘Additions’)
2024: Total Additions were 217 million boe, of which 38 million boe (26 million barrels of crude oil, 4 million barrels of NGL and 47 million mcf of natural gas) related to proved developed reserves. Additions to proved developed reserves primarily resulted from drilling activity at the Stabroek Block, offshore Guyana, the Bakken shale play in North Dakota and one well drilled in the Gulf of America. Additions to proved undeveloped reserves were 179 million boe (118 million barrels of crude oil, 36 million barrels of NGL and 151 million mcf of natural gas) and are discussed in further detail on page 99.
2023: Total Additions were 169 million boe, of which 15 million boe (5 million barrels of crude oil, 2 million barrels of NGL and 48 million mcf of natural gas) related to proved developed reserves. Additions to proved developed reserves primarily resulted from drilling activity in the Bakken shale play in North Dakota and North Malay Basin, offshore Peninsula Malaysia. Additions to proved undeveloped reserves were 154 million boe (117 million barrels of crude oil, 14 million barrels of NGL and 136 million mcf of natural gas) and are discussed in further detail on page 99.
2022: Total Additions were 197 million boe, of which 14 million boe (9 million barrels of crude oil, 3 million barrels of NGL and 14 million mcf of natural gas) related to proved developed reserves. Additions to proved developed reserves primarily resulted from drilling activity in the Bakken shale play in North Dakota and the Stabroek Block, offshore Guyana. Additions to proved undeveloped reserves were 183 million boe (146 million barrels of crude oil, 19 million barrels of NGL and 108 million mcf of natural gas) and are discussed in further detail on page 99.
Revisions of previous estimates
2024: Total revisions of previous estimates of proved reserves amounted to a net increase of 30 million boe, of which revisions of proved developed reserves amounted to a net increase of 64 million boe (27 million barrels of crude oil, 20 million barrels of NGL and 100 million mcf of natural gas). In Guyana, net positive revisions to proved developed reserves of 49 million boe, primarily resulted from increased recovery associated with water injection (60%), well performance (35%), and other positive revisions (5%). In the United States, net positive revisions to proved developed reserves from the Bakken of 3 million boe, primarily resulted from performance largely driven by an increase in gas volume estimates partially offset by an oil volume reduction. In the Gulf of America, net positive revisions to proved developed reserves of 7 million boe, primarily related to performance at the Stampede Field. In Malaysia and JDA, net positive revisions to proved developed reserves of 5 million boe, were primarily due to performance at North Malay Basin. Revisions associated with proved undeveloped reserves are discussed in further detail on page 99.
2023: Total revisions of previous estimates of proved reserves amounted to a net increase of 92 million boe, of which revisions of proved developed reserves amounted to a net increase of 80 million boe (45 million barrels of crude oil, 24 million barrels of NGL and 64 million mcf of natural gas). In the United States, net positive revisions to proved developed reserves from the Bakken were 13 million boe, comprised of positive revisions of 19 million boe and negative price revisions of 6 million boe. The positive revisions resulted from performance largely driven by an increase in gas volume estimates partially offset by an oil volume reduction, including updated shrinkage and yield factors (55%), and the capture of additional gas volumes (45%). In Guyana, net positive revisions to proved developed reserves of 66 million boe, primarily related to the Liza Field, resulted from improved recovery associated with water injection (60%), well performance (30%), and other positive revisions (10%), primarily increased natural gas for consumption. Revisions associated with proved undeveloped reserves are discussed in further detail on page 99.
2022: Total revisions of previous estimates of proved reserves amounted to a net decrease of 13 million boe, of which revisions of proved developed reserves amounted to a net increase of 20 million boe (20 million barrels of NGL and 82 million mcf of natural gas offset by a decrease of 14 million barrels of crude oil). In the United States, net positive revisions to proved developed reserves from the Bakken were 17 million boe relating to the capture of additional gas volumes (50%), well performance largely driven by an increase in gas volume estimates partially offset by an oil volume reduction (30%), and the impact of higher commodity prices (20%). In Guyana, net positive revisions to proved developed reserves totaled 2 million boe due to increased recovery based on performance and other positive revisions (7 million boe), partially offset by the impact of higher commodity prices on entitlement allocations in the PSC (5 million boe). Revisions associated with proved undeveloped reserves are discussed in further detail on page 99.
Sales of minerals in place (‘Asset sales’)
2022: Asset sales relate to the divestiture of our working interest in the Waha Concession in Libya.
Proved Undeveloped Reserves
Following are the Corporation’s proved undeveloped reserves:
United
States Guyana Malaysia and
JDA Total
(Millions of boe)
Net Proved Undeveloped Reserves
At January 1, 2022 371 145 24 540
Revisions of previous estimates (35) 5 (3) (33)
Extensions, discoveries and other additions 81 102 - 183
Transfers to proved developed reserves (63) (79) (9) (151)
At December 31, 2022 354 173 12 539
Revisions of previous estimates (1) 8 5 12
Extensions, discoveries and other additions 61 92 1 154
Transfers to proved developed reserves (65) (68) (13) (146)
At December 31, 2023 349 205 5 559
Revisions of previous estimates (36) 4 (2) (34)
Extensions, discoveries and other additions 127 52 - 179
Transfers to proved developed reserves (82) (13) (2) (97)
At December 31, 2024 358 248 1 607
Extensions, discoveries and other additions (‘Additions’)
2024: In the United States, Additions in the Bakken shale play in North Dakota from new wells planned to be drilled in the next five years were 126 million boe, including the development of three-mile laterals for approximately 45% of these new wells. In Guyana, Additions of 52 million boe were due to the sanctioning of the Whiptail Field development (46 million boe) and other additions primarily related to the Payara and Uaru Fields (6 million boe).
2023: In the United States, Additions in the Bakken shale play in North Dakota from new wells planned to be drilled in the next five years were 61 million boe. In Guyana, Additions of 92 million boe were due to the sanctioning of the Uaru Field development (63 million boe), extension of the proved area of the Yellowtail and Payara Fields (19 million boe) and approval of the gas to energy project (10 million boe).
2022: In the United States, Additions in the Bakken shale play in North Dakota from new wells planned to be drilled in the next five years were 79 million boe. In Guyana, Additions of 102 million boe were due to the sanctioning of the Yellowtail Field development (94 million boe), and extension of the proved area of the Payara Field (8 million boe).
Revisions of previous estimates
2024: In the United States, net negative reserve revisions of 36 million boe were from the Bakken, which included a net decrease of 32 million boe related to wells moved outside the five-year development plan, and other negative revisions of 4 million boe primarily related to performance. In Guyana, net positive reserve revisions were 4 million boe, primarily from increased recovery based on performance.
2023: In the United States, net negative reserve revisions of 1 million boe were primarily from the Bakken, which included a net decrease of 12 million boe related to wells moved outside the five-year development plan, partially offset by net positive revisions of 11 million boe primarily related to performance and updates to ownership interests. In Guyana, net positive reserve revisions of 8 million boe were primarily due to the impact of lower crude oil prices on entitlement allocations in the PSC. In Malaysia and JDA, net positive revisions of 5 million boe primarily related to incorporating the latest drilling results.
2022: In the United States, net negative reserve revisions of 35 million boe were primarily from the Bakken, which included a net decrease of 26 million boe related to wells moved outside the five-year development plan, and other negative revisions of 9 million boe primarily related to performance and updates to ownership interests. In Guyana, net positive reserve revisions were 5 million boe, which included a net increase of 13 million boe primarily from increased recovery based on performance partially offset by negative revisions of 8 million boe related to the impact of higher crude oil prices on entitlement allocations in the PSC.
Transfers to proved developed reserves (‘Transfers’)
2024: Transfers from proved undeveloped reserves totaled 82 million boe in the United States resulted from drilling activity in the Bakken. In Guyana, Transfers of 13 million boe resulted from drilling activity at the Payara Field. Transfers in 2024 were consistent with the development plan used to determine proved reserves at December 31, 2023, and in the Bakken we plan to continue to operate four rigs going forward. In Malaysia and JDA, Transfers of 2 million boe resulted from drilling activity.
2023: Transfers from proved undeveloped reserves totaled 68 million boe in Guyana primarily related to the startup of production from the Payara Field development in November 2023 (61 million boe) and drilling activity (7 million boe). In the United States, Transfers of 65 million boe resulted from drilling activity in the Bakken. Transfers in 2023 were consistent with the development plan used to determine proved reserves at December 31, 2022, and in the Bakken we plan to continue to operate four rigs going forward. In Malaysia and JDA, Transfers of 13 million boe resulted from drilling activity.
2022: Transfers from proved undeveloped reserves totaled 79 million boe in Guyana primarily related to the startup of production from the Liza Phase 2 development in February 2022. In the United States, Transfers were 59 million boe in the Bakken and 4 million boe in the Gulf of America resulting from drilling activity. Transfers in the United States for 2022 were consistent with the development plan used to determine proved reserves at December 31, 2021. In the Bakken, we added a fourth rig in July 2022, and we plan to operate four rigs going forward. In Malaysia and JDA, Transfers of 9 million boe resulted from drilling activity.
In 2024, capital expenditures of $1,324 million were incurred to convert proved undeveloped reserves to proved developed reserves (2023: $2,198 million; 2022: $1,780 million).
At December 31, 2024, there are no projects that have proved reserves that have been classified as undeveloped for a period in excess of five years.
Production Sharing Contracts
The Corporation’s proved reserves include crude oil and natural gas reserves relating to long-term agreements with governments or authorities in which the Corporation has the legal right to produce or has a revenue interest in the production. The Corporation’s
operations with these production sharing arrangements include those in Guyana, Malaysia, and the JDA. In these production sharing arrangements, if other economic factors remain stable, reserves estimates which are attributable to recovery of costs will change inversely to changes in commodity prices. For example, if prices decrease, the Corporation’s net reserves estimates will increase. Proved reserves for each of the three years ended December 31, 2024, as well as volumes produced and received during 2024, 2023 and 2022 from these PSCs are presented in the proved reserve tables on pages 96 and 97. Revisions resulting from the entitlement impact of price changes in PSCs increased proved reserves by 2 million boe in 2024 (2023: 10 million boe increase; 2022: 14 million boe decrease).
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Future net cash flows are calculated by applying prescribed oil and gas selling prices used in determining year-end reserve estimates (adjusted for price changes provided by contractual arrangements) to estimated future production of proved oil and gas reserves, less estimated future development costs (including future abandonment expenditures) and future production costs, which are based on year-end costs and existing economic assumptions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the pre-tax net cash flows, as well as including the effect of tax deductions and tax credits and allowances relating to the Corporation’s proved oil and gas reserves. Future net cash flows are discounted at the prescribed rate of 10%.
The prices used for the discounted future net cash flows in 2024 were $74.88 per barrel for WTI (2023: $78.10; 2022: $94.13) and $78.81 per barrel for Brent (2023: $82.51; 2022: $97.98) and do not include the effects of commodity hedges. NYMEX natural gas prices used were $2.37 per mcf in 2024 (2023: $2.75; 2022: $6.44). Selling prices have in the past, and can in the future, fluctuate significantly. As a result, selling prices used in the disclosure of future net cash flows may not be representative of future selling prices. The discounted future net cash flow estimates do not include exploration expenses, interest expense or corporate general and administrative expenses. The amount of tax deductions, credits, and allowances relating to the Corporation’s proved oil and gas reserves can change year to year due to factors including changes in proved reserves, variances in actual pre-tax cash flows from forecasted pre-tax cash flows in historical periods, and the impact to year-end carryforward tax attributes associated with deducting in the Corporation’s income tax returns exploration expenses, interest expense, and corporate general and administrative expenses that are not contemplated in the standardized measure computations. The future net cash flow estimates could be materially different if other assumptions were used.
At December 31 Total United
States Guyana Malaysia and
JDA
(In millions)
Future revenues $ 67,598 $ 30,722 $ 35,483 $ 1,393
Less:
Future production costs 20,430 14,715 5,083 632
Future development costs 14,480 6,295 7,925 260
Future income tax expenses 6,440 1,742 4,624 74
41,350 22,752 17,632 966
Future net cash flows 26,248 7,970 17,851 427
Less: Discount at 10% annual rate 11,616 5,291 6,294 31
Standardized Measure of Discounted Future Net Cash Flows $ 14,632 $ 2,679 $ 11,557 $ 396
Future revenues $ 68,167 $ 33,514 $ 32,691 $ 1,962
Less:
Future production costs 20,607 14,083 5,750 774
Future development costs 13,324 5,866 7,096 362
Future income tax expenses 7,373 2,953 4,299 121
41,304 22,902 17,145 1,257
Future net cash flows 26,863 10,612 15,546 705
Less: Discount at 10% annual rate 12,130 6,254 5,817 59
Standardized Measure of Discounted Future Net Cash Flows $ 14,733 $ 4,358 $ 9,729 $ 646
Future revenues $ 80,822 $ 50,373 $ 28,060 $ 2,389
Less:
Future production costs 19,640 14,141 4,687 812
Future development costs 11,088 5,186 5,430 472
Future income tax expenses 11,795 7,308 4,307 180
42,523 26,635 14,424 1,464
Future net cash flows 38,299 23,738 13,636 925
Less: Discount at 10% annual rate 17,382 12,677 4,589 116
Standardized Measure of Discounted Future Net Cash Flows $ 20,917 $ 11,061 $ 9,047 $ 809
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
For the Years Ended December 31 2024 2023 2022
(In millions)
Standardized Measure of Discounted Future Net Cash Flows at January 1 $ 14,733 $ 20,917 $ 11,253
Changes during the year:
Sales and transfers of oil and gas produced during the year, net of production costs (6,979) (4,821) (5,342)
Development costs incurred during the year 4,291 3,684 2,231
Net changes in prices and production costs (2,088) (13,815) 11,649
Net change in estimated future development costs (1,096) (2,039) (2,156)
Extensions and discoveries (including improved recovery) of oil and gas reserves, less related costs 1,592 3,202 5,655
Revisions of previous oil and gas reserve estimates 1,800 2,510 (188)
Net purchases (sales) of minerals in place, before income taxes - - (3,099)
Accretion of discount 1,855 2,716 1,338
Net change in income taxes 543 2,425 (450)
Revision in rate or timing of future production and other changes (19) (46) 26
Total (101) (6,184) 9,664
Standardized Measure of Discounted Future Net Cash Flows at December 31 $ 14,632 $ 14,733 $ 20,917

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Based upon their evaluation of the Corporation’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2024, John B. Hess, Chief Executive Officer, and John P. Rielly, Chief Financial Officer, concluded that these disclosure controls and procedures were effective as of December 31, 2024.
There was no change in internal controls over financial reporting identified in the evaluation required by paragraph (d) of Rules 13a-15 or 15d-15 in the quarter ended December 31, 2024 that has materially affected, or is reasonably likely to materially affect, internal controls over financial reporting.
Management’s report on internal control over financial reporting and the attestation report on the Corporation’s internal controls over financial reporting are included in Item 8. Financial Statements and Supplementary Data of this annual report on Form 10-K.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
During the three months ended December 31, 2024, none of our directors or officers (as defined in Rule 16a-1(f) under the Exchange Act) adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance
For information regarding our executive officers, see Part I of this Annual Report on Form 10-K. Additional information required by this item will be included under the caption “Proposal 1: Election of Directors” in our definitive proxy statement for the 2025 annual meeting of stockholders to be filed with the SEC (2025 Proxy Statement) and is incorporated herein by reference.
The Corporation has adopted a Code of Business Conduct and Ethics applicable to the Corporation’s directors, officers (including the Corporation’s principal executive officer and principal financial officer) and employees. The Code of Business Conduct and Ethics is available on the Corporation’s website. In the event that we amend or waive any of the provisions of the Code of Business Conduct and Ethics that relate to any element of the code of ethics definition enumerated in Item 406(b) of Regulation S-K, we intend to disclose the same on the Corporation’s website at www.hess.com.
Information regarding our insider trading policy governing the purchase, sale and other dispositions of the registrant’s securities by directors, senior management, and employees will be included under sub-caption “Proposal 1: Election of Directors-Insider Trading Policy” in our 2025 Proxy Statement. A copy of the insider trading policy is filed as an exhibit to this Annual Report.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
Information relating to executive compensation will be included under the caption “Executive Compensation” in our 2025 Proxy Statement and is incorporated herein by reference.
Information relating to director compensation will be included under the sub-caption “Proposal 1: Election of Directors-Director Compensation” in our 2025 Proxy Statement and is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information pertaining to security ownership of certain beneficial owners and management will be included under the sub-captions “Proposal 1: Election of Directors-Ownership of Voting Securities by Certain Beneficial Owners” and “Proposal 1: Election of Directors-Ownership of Equity Securities by Management” in our 2025 Proxy Statement and is incorporated herein by reference.
See Equity Compensation Plans in Item 5. Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities for information pertaining to securities authorized for issuance under equity compensation plans.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information relating to this item will be included under the sub-captions “Proposal 1: Election of Directors-Related Party Transactions” and “Proposal 1: Election of Directors-Director and Nominee Independence” in our 2025 Proxy Statement and is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services
Information relating to this item will be included under the caption “Proposal 3: Ratification of the Selection of Ernst & Young LLP as Our Independent Registered Public Accountants” in our 2025 Proxy Statement and is incorporated herein by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are made a part of this Annual Report on Form 10-K:
1. and 2. Financial statements and financial statement schedules
The financial statements filed as part of this Annual Report on Form 10-K are listed in the accompanying index to financial statements and schedules in Item 8. Financial Statements and Supplementary Data.
All other financial statement schedules required under SEC rules that are not included in this Annual Report on Form 10-K, are omitted either because they are not applicable or the required information is contained in Item 8. Financial Statements and Supplementary Data.
3. Exhibits
The exhibits required to be filed pursuant to Item 15(b) of Form 10-K are listed in the Exhibit Index filed herewith, which Exhibit Index is incorporated herein by reference.
2(1)†
Agreement and Plan of Merger, dated as of October 22, 2023, among Chevron Corporation, Yankee Merger Sub Inc. and Hess Corporation incorporated by reference to Exhibit 2(1) of Registrant’s Form 10-K for the year ended December 31, 2023.
3(1)
Restated Certificate of Incorporation of Registrant, including amendment thereto dated May 3, 2006 incorporated by reference to Exhibit 3(1) of Registrant’s Form 10-Q for the three months ended June 30, 2006.
3(2)
Certificate of Amendment to Restated Certificate of Incorporation of Registrant, dated May 22, 2013, incorporated by reference to Exhibit 3(1) of Form 8-K of Registrant filed on May 22, 2013.
3(3)
Certificate of Amendment to Restated Certificate of Incorporation of Registrant, effective May 12, 2014, incorporated by reference to Exhibit 3(1) of Form 8-K of Registrant filed on May 13, 2014.
3(4)
Certificate of Elimination of 8.00% Series A Mandatory Convertible Preferred Stock of Registrant, incorporated by reference to Exhibit 3(4) of Form 10-K of Registrant for the year ended December 31, 2019.
3(5)
By-Laws of Hess Corporation (as amended effective May 6, 2020) incorporated by reference to Exhibit 3(1) of Form 10-Q of Registrant for the three months ended March 31, 2020.
3(6)
Amendment to the By-Laws of Hess Corporation (effective as of October 22, 2023) incorporated by reference to Exhibit 3(1) of Form 8-K of Registrant filed on October 23, 2023.
4(1)
Credit Agreement, dated as of July 14, 2022, among Hess Corporation, the subsidiary party thereto, the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent incorporated by reference to Exhibit 10(1) of Form 8-K of the Registrant, filed on July 15, 2022.
4(2)
Indenture dated as of October 1, 1999, between Registrant and The Chase Manhattan Bank, as Trustee, incorporated by reference to Exhibit 4(1) of Form 10-Q of Registrant for the three months ended September 30, 1999.
4(3)
First Supplemental Indenture, dated as of October 1, 1999, between Registrant and The Chase Manhattan Bank, as Trustee, relating to Registrant’s 73/8% Notes due 2009 and 77/8% Notes due 2029, incorporated by reference to Exhibit 4(2) of Form 10-Q of Registrant for the three months ended September 30, 1999.
4(4)
Prospectus Supplement, dated August 8, 2001, to Prospectus dated July 27, 2001 relating to Registrant’s 5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933, as amended, on August 9, 2001.
4(5)
Prospectus Supplement, dated February 28, 2002, to Prospectus dated July 27, 2001 relating to Registrant’s 7.125% Notes due 2033, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(4) under the Securities Act of 1933, as amended, on March 1, 2002.
4(6)
Indenture dated as of March 1, 2006, between Registrant and The Bank of New York Mellon, as successor to JP Morgan Chase Bank, N.A., as Trustee, including form of Note, incorporated by reference to Exhibit 4 to Registrant’s Form S-3ASR filed on March 1, 2006.
4(7)
Form of 6.00% Note due 2040, incorporated by reference to Exhibit 4(1) to Form 8-K of Registrant filed on December 15, 2009.
4(8)
Form of 5.60% Note due 2041, incorporated by reference to Exhibit 4(1) to Form 8-K of Registrant filed on August 12, 2010.
4(9)
Form of 4.30% Note due 2027, incorporated by reference to Exhibit 4(1) to Form 8-K of Registrant filed on September 28, 2016.
4(10)
Form of 5.80% Note due 2047, incorporated by reference to Exhibit 4(2) to Form 8-K of Registrant filed on September 28, 2016.
4(11)
Description of Hess Corporation’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 incorporated by reference to Exhibit 4(12) of Form 10-K of Registrant for the year ended December 31, 2019.
Other instruments defining the rights of holders of long-term debt of Registrant and its consolidated subsidiaries are not being filed since the total amount of securities authorized under each such instrument does not exceed 10% of the total assets of Registrant and its subsidiaries on a consolidated basis. Registrant agrees to furnish to the Securities and Exchange Commission a copy of any instruments defining the rights of holders of long-term debt of Registrant and its subsidiaries upon request.
10(1)*
Annual Cash Incentive Plan description incorporated by reference to Item 5.02 of Form 8-K of Registrant filed on March 8, 2024.
10(2)*
Financial Counseling Program description incorporated by reference to Exhibit 10(6) of Form 10-K of Registrant for the fiscal year ended December 31, 2004.
10(3)*
Hess Corporation Savings and Stock Bonus Plan incorporated by reference to Exhibit 10(7) of Form 10-K of Registrant for the fiscal year ended December 31, 2006.
10(4)*
Letter Agreement, dated May 17, 2001, between Registrant and John P. Rielly relating to Mr. Rielly’s participation in the Hess Corporation Pension Restoration Plan, incorporated by reference to Exhibit 10(18) of Form 10-K of Registrant for the fiscal year ended December 31, 2002.
10(5)*
Amended and Restated 2008 Long-term Incentive Plan, incorporated by reference to exhibit 10(1) of Form 8-K of the Registrant filed on May 12, 2015.
10(6)*
Forms of Awards under Registrant’s 2008 Long-term Incentive Plan, incorporated by reference to Exhibit 10(14) of Form 10-K of Registrant for the fiscal year ended December 31, 2009.
10(7)*
Form of Amended and Restated Change in Control Termination Benefits Agreement, dated as of May 29, 2009, incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended June 30, 2009. A substantially identical agreement (differing only in the signatories thereto) was entered into between Registrant and John B. Hess.
10(8)*
Amended and Restated Change in Control Termination Benefits Agreement, dated as of May 29, 2009, between Registrant and John P. Rielly, incorporated by reference to Exhibit 10(17) of Form 10-K of Registrant for the fiscal year ended December 31, 2009. Substantially identical agreements (differing only in the signatories thereto) were entered into between Registrant and other executive officers (including the named executive officers, other than Barbara Lowery-Yilmaz and John B. Hess).
10(9)*
Form of Change in Control Termination Benefits Agreement, dated as of August 3, 2015, between the Registrant and Barbara Lowery-Yilmaz, incorporated by reference to Exhibit 10(2) of Form 10-Q of Registrant for the three months ended June 30, 2021. Substantially identical agreements (differing only in the signatories thereto) were entered into between the Registrant and other senior officers.
10(10)*
Agreement between Registrant and Gregory P. Hill, relating to Mr. Hill’s compensation and other terms of employment, incorporated by reference to Item 5.02 of Form 8-K of Registrant filed January 7, 2009.
10(11)*
Agreement between Registrant and Timothy B. Goodell, relating to Mr. Goodell’s compensation and other terms of employment, incorporated by reference to Exhibit 10(20) of Registrant’s Form 10-K for the fiscal year ended December 31, 2009.
10(12)*
Deferred Compensation Plan of Registrant, dated December 1, 1999, incorporated by reference to Exhibit 10(16) of Form 10-K of Registrant for the fiscal year ended December 31, 1999.
10(13)*
Hess Corporation 2017 Long-Term Incentive Plan, incorporated by reference to Exhibit 10(1) of Form 8-K of Registrant filed on June 13, 2017.
10(14)*
Form of Restricted Stock Award Agreement under the 2017 Long-Term Incentive Plan incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended March 31, 2020.
10(15)*
Form of Stock Option Award Agreement under the 2017 Long-Term Incentive Plan incorporated by reference to Exhibit 10(2) of Form 10-Q of Registrant for the three months ended March 31, 2020.
10(16)*
Amendment No. 1 to the Hess Corporation 2017 Long-Term Incentive Plan incorporated by reference to Exhibit 10(1) of Form 8-K of the Registrant, filed on June 3, 2021.
10(17)*
Form of 2022 Performance Award Agreement under the 2017 Long-Term Incentive Plan incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended March 31, 2022.
10(18)*
Form of 2023 Performance Award Agreement under the 2017 Long-Term Incentive Plan incorporated by reference to Exhibit 10(1) of Form 10-Q of Registrant for the three months ended March 31, 2023.
10(19)
Voting and Support Agreement, dated October 22, 2023, by and among Chevron Corporation, Hess Corporation and John B. Hess incorporated by reference to Exhibit 10(1) of Form 8-K of Registrant filed on October 23, 2023.
10(20)*
Form of Restricted Stock Award Agreement under the 2017 Long-Term Incentive Plan incorporated by reference to Exhibit 10(1) of Form 8-K of Registrant filed on March 8, 2024.
Registrant’s Insider Trading Policy.
Subsidiaries of Registrant.
23(1)
Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm, dated February 27, 2025.
23(2)
Consent of DeGolyer and MacNaughton dated February 27, 2025.
Power of Attorney (included on the signatures page of this Annual Report on Form 10-K).
31(1)
Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
31(2)
Certification required by Rule 13a-14(a) (17 CFR 240.13a-14(a)) or Rule 15d-14(a) (17 CFR 240.15d-14(a)).
32(1)#
Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
32(2)#
Certification required by Rule 13a-14(b) (17 CFR 240.13a-14(b)) or Rule 15d-14(b) (17 CFR 240.15d-14(b)) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
97*
Registrant’s Compensation Recovery Policy incorporated by reference to Exhibit 97 of Registrant’s Form 10-K for the year ended December 31, 2023.
99(1)
Letter report of DeGolyer and MacNaughton, Independent Petroleum Engineering Consulting Firm, dated February 5, 2025, on proved reserves audit as of December 31, 2024 of certain properties attributable to Registrant.
101(INS)
Inline XBRL Instance Document
101(SCH)
Inline XBRL Schema Document
101(CAL)
Inline XBRL Calculation Linkbase Document
101(LAB)
Inline XBRL Labels Linkbase Document
101(PRE)
Inline XBRL Presentation Linkbase Document
101(DEF)
Inline XBRL Definition Linkbase Document
104 The cover page from the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024 has been formatted in Inline XBRL.
* These exhibits relate to executive compensation plans and arrangements.
† Schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K.
# Furnished herewith.