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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2021
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                 to                
Commission File Number 1-1204
Hess Corporation
(Exact name of Registrant as specified in its charter)
DELAWARE
 13-4921002
(State or other jurisdiction of
incorporation or organization)
 (I.R.S. Employer
Identification Number)
1185 AVENUE OF THE AMERICAS, 10036
NEW YORK,NY (Zip Code)
(Address of principal executive offices)  
Registrant’s telephone number, including area code (212997-8500
Securities registered pursuant to Section 12(b) of the Act:
Title of Each ClassTrading Symbol(s)Name of Each Exchange on Which Registered
Common Stock (par value $1.00)HESNew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  No 
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes  No 
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  No 
Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files). Yes  No 
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” - “smaller reporting company” and “emerging growth company” -  in Rule 12b-2 of the Exchange Act:
Large accelerated filer        
Accelerated filer               
Non-accelerated filer
Smaller reporting company
Emerging Growth Company
If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. Yes  No
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  No
The aggregate market value of voting stock held by non-affiliates of the Registrant amounted to $24,239,000,000, computed using the outstanding Common Stock and closing market price on June 30, 2021, the last business day of the Registrant’s most recently completed second fiscal quarter.
At January 31, 2022, there were 309,745,523 shares of Common Stock outstanding.
Part III is incorporated by reference from the Proxy Statement for the 2022 annual meeting of stockholders.



HESS CORPORATION
Form 10-K
TABLE OF CONTENTS
 
Item No.   Page
  PART I  
1 and 2.  
  
1A.  
1B.  
3.  
4.  
  PART II  
5.  
6.
7.  
7A.  
8.  
9.  
9A.  
9B.  
9C.
  PART III  
10.  
11.  
12.  
13.  
14.  
  PART IV  
15.  
   
Unless the context indicates otherwise, references to “Hess”, the “Corporation”, “Registrant”, “we”, “us”, “our” and “its” refer to the consolidated business operations of Hess Corporation and its subsidiaries.
2


CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K, including information incorporated by reference herein, contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Words such as “anticipate,” “estimate,” “expect,” “forecast,” “guidance,” “could,” “may,” “should,” “would,” “believe,” “intend,” “project,” “plan,” “predict,” “will,” “target” and similar expressions identify forward-looking statements, which are not historical in nature. Our forward-looking statements may include, without limitation: our future financial and operational results; our business strategy; estimates of our crude oil and natural gas reserves and levels of production; benchmark prices of crude oil, natural gas liquids and natural gas and our associated realized price differentials; our projected budget and capital and exploratory expenditures; expected timing and completion of our development projects; and future economic and market conditions in the oil and gas industry.
Forward-looking statements are based on our current understanding, assessments, estimates and projections of relevant factors and reasonable assumptions about the future. Forward-looking statements are subject to certain known and unknown risks and uncertainties that could cause actual results to differ materially from our historical experience and our current projections or expectations of future results expressed or implied by these forward-looking statements. The following important factors could cause actual results to differ materially from those in our forward-looking statements:
fluctuations in market prices of crude oil, natural gas liquids and natural gas and competition in the oil and gas exploration and production industry, including as a result of the global COVID-19 pandemic (COVID-19);
reduced demand for our products, including due to COVID-19, perceptions regarding the oil and gas industry, competing or alternative energy products and political conditions and events;
potential failures or delays in increasing oil and gas reserves, including as a result of unsuccessful exploration activity, drilling risks and unforeseen reservoir conditions, and in achieving expected production levels;
changes in tax, property, contract and other laws, regulations and governmental actions applicable to our business, including legislative and regulatory initiatives regarding environmental concerns, such as measures to limit greenhouse gas emissions and flaring, fracking bans as well as restrictions on oil and gas leases;
operational changes and expenditures due to climate change and sustainability related initiatives;
disruption or interruption of our operations due to catastrophic events, such as accidents, severe weather, geological events, shortages of skilled labor, cyber-attacks, health measures related to COVID-19, or climate change;
the ability of our contractual counterparties to satisfy their obligations to us, including the operation of joint ventures under which we may not control and exposure to decommissioning liabilities for divested assets in the event the current or future owners are unable to perform;
unexpected changes in technical requirements for constructing, modifying or operating exploration and production facilities and/or the inability to timely obtain or maintain necessary permits;
availability and costs of employees and other personnel, drilling rigs, equipment, supplies and other required services;
any limitations on our access to capital or increase in our cost of capital, including as a result of limitations on investment in oil and gas activities or negative outcomes within commodity and financial markets;
liability resulting from environmental obligations and litigation, including heightened risks associated with being a general partner of Hess Midstream LP; and
other factors described in Item 1A—Risk Factors in this Annual Report on Form 10-K and any additional risks described in our other filings with the Securities and Exchange Commission.
As and when made, we believe that our forward-looking statements are reasonable. However, given these risks and uncertainties, caution should be taken not to place undue reliance on any such forward-looking statements since such statements speak only as of the date when made and there can be no assurance that such forward-looking statements will occur and actual results may differ materially from those contained in any forward-looking statement we make. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether because of new information, future events or otherwise.
3


Glossary
Throughout this report, the following company or industry specific terms and abbreviations are used:
API – American Petroleum Institute.
Appraisal well – An exploration well drilled to confirm the results of a discovery well, or a well that is used to determine the boundaries of a productive formation.
Bbl – One stock tank barrel, which is 42 United States gallons liquid volume.
Barrel of oil equivalent or Boe – This reflects natural gas reserves converted on the basis of relative energy content of six mcf equals one barrel of oil equivalent (one mcf represents one thousand cubic feet).  Barrel of oil equivalence does not necessarily result in price equivalence, as the equivalent price of natural gas on a barrel of oil equivalent basis has been substantially lower than the corresponding price for crude oil over the recent past.
Boepd – Barrels of oil equivalent per day.
Bopd – Barrels of oil per day.
BSEE – Bureau of Safety and Environmental Enforcement.
CGA – Clean Gulf Associates.
Condensate – A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that when produced, is in the liquid phase at surface pressure and temperature.
DD&A – Depreciation, depletion and amortization.
DEI – Diversity, Equity and Inclusion.
Development well – A well drilled within the proved area of an oil and/or natural gas reservoir with the intent of producing oil and/or natural gas from that area of the reservoir.
Dry hole – An exploratory or development well that does not find oil or natural gas in commercial quantities.
EPA – Environmental Protection Agency.
EHS & SR – Environment, health, safety and social responsibility.
Exploratory well – A well drilled to find oil or natural gas in an unproved area or find a new reservoir in a field previously found to be productive by another reservoir.
E&P  – Exploration and production.
Field – An area consisting of a single reservoir or multiple reservoirs all grouped or related to the same individual geological structural feature and/or stratigraphic condition.
FPSO – Floating production, storage, and offloading vessel.
Fractionation – A process by which the mixture of natural gas liquids that results from natural gas processing is separated into the NGL components, such as ethane, propane, butane, isobutane, and natural gasoline, prior to their sale to various petrochemical and industrial end users.  Fractionation is accomplished by controlling the temperature of the stream of mixed liquids in order to take advantage of the difference in boiling points of separate products.
GHG – Greenhouse gas.
Gross acres Acreage in which a working interest is held by the Corporation.
Gross well – A well in which a working interest is held by the Corporation.
ICE – Integrity critical equipment.
IEA International Energy Agency.
JOA – Joint operating agreement.
LIBOR – The London Interbank Offered Rate.
Mcf – One thousand cubic feet of natural gas.
Mmcfd – One thousand mcf of natural gas per day.
MSRC – Marine Spill Response Corporation.
MTBE – Methyl tertiary butyl ether.
4


MWCC Marine Well Containment Company.
Net acreage or Net wells – The sum of the fractional working interests owned by the Corporation in gross acres or gross wells.
NGL or Natural gas liquids – Naturally occurring hydrocarbon substances that are separated and produced by fractionating natural gas, including ethane, butane, isobutane, propane and natural gasoline.  NGL do not sell at prices equivalent to crude oil.
NJDEP – New Jersey Department of Environmental Protection.
Non-operated – Projects in which the Corporation has a working interest but does not perform the role of Operator.
OPEC – Organization of Petroleum Exporting Countries.
Operator – The entity responsible for conducting and managing exploration, development, and/or production operations for an oil or gas project.
OSHA – Occupational Safety and Health Administration.
OSRL – Oil Spill Response Limited.
Participating interest – Reflects the proportion of exploration and production costs each party will bear as set out in an operating agreement.
Plug and perf completion – A well completion technique which involves creating perforations in the well casing that penetrate the hydrocarbon reservoir section between set plugs.
Production sharing contract – An agreement between a host government and the owners (or co-owners) of a well or field regarding the percentage of production each party will receive after the parties have recovered a specified amount of capital and operational expenses.
Productive well – A well that is capable of producing hydrocarbons in sufficient quantities to justify commercial exploitation.
Proved properties – Properties with proved reserves.
Proved reserves – In accordance with the Securities and Exchange Commission regulations and practices recognized in the publication of the Society of Petroleum Engineers entitled, “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information,” those quantities of crude oil and condensate, NGL and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Proved developed reserves – Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or for which the cost of the required equipment is relatively minor compared to the cost of a new well.
Proved undeveloped reserves – Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
ROD – Record of Decision.
SOFR – Secured Overnight Financing Rate.
Unproved properties – Properties with no proved reserves.
VLCC Very large crude carrier.
Working interest – An interest in an oil and gas property that provides the owner of the interest the right to participate in the drilling for and production of oil and gas on the relevant acreage and requires the owner to pay a share of the costs of drilling and production operations.
WWCC Wild Well Control Company.
5


PART I
Items 1 and 2.  Business and Properties
Hess Corporation, incorporated in the State of Delaware in 1920, is a global E&P company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located primarily in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA), and Malaysia. We conduct exploration activities primarily offshore Guyana, in the U.S. Gulf of Mexico, and offshore Suriname and Canada. 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. The Liza Phase 1 development achieved first production in December 2019, and has a nameplate production capacity of approximately 120,000 gross bopd. The Liza Phase 2 development achieved first production in February 2022, and is expected to reach its production capacity of approximately 220,000 gross bopd later in 2022 as operations are safely brought online. A third development, Payara, was sanctioned in the third quarter of 2020 and is expected to achieve first production in 2024, with production capacity of approximately 220,000 gross bopd. A fourth development, Yellowtail, was submitted to the government of Guyana for approval in the fourth quarter of 2021. Pending government approval and project sanctioning, the project is expected to have a capacity of approximately 250,000 gross bopd with first production anticipated in 2025. We currently plan to have six FPSOs with an aggregate expected production capacity of more than 1 million gross bopd on the Stabroek Block in 2027, and the potential for up to ten FPSOs to develop the current discovered recoverable resource base.
Our Midstream operating segment, which is comprised of Hess Corporation’s approximate 43.5% consolidated ownership interest in Hess Midstream LP at December 31, 2021, 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 12.
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, 2021 were $66.34 per barrel for West Texas Intermediate (WTI) (2020: $39.77) and $68.92 per barrel for Brent (2020: $43.43).  Our total proved developed and undeveloped reserves at December 31 were as follows:
 Crude Oil & CondensateNatural Gas LiquidsNatural GasTotal Barrels of Oil Equivalent (BOE)
 20212020202120202021202020212020
 (Millions of bbls)(Millions of bbls)(Millions of mcf)(Millions of bbls)
Developed        
United States283 282 138 120 568 490 516 484 
Guyana (a)65 72  — 17 36 68 78 
Malaysia and JDA3  — 394 543 69 94 
Other (b)100 134  — 98 165 116 162 
 451 492 138 120 1,077 1,234 769 818 
Undeveloped        
United States215 119 95 42 367 163 371 188 
Guyana (a)140 132  — 31 47 145 140 
Malaysia and JDA2  — 131 132 24 24 
 357 253 95 42 529 342 540 352 
Total        
United States498 401 233 162 935 653 887 672 
Guyana (a)205 204  — 48 83 213 218 
Malaysia and JDA5  — 525 675 93 118 
Other (b)100 134  — 98 165 116 162 
 808 745 233 162 1,606 1,576 1,309 1,170 
(a)Guyana natural gas reserves will be consumed for fuel.
(b)Other includes our interests in Denmark, which were sold in August 2021, and Libya. At December 31, 2020, total proved reserves for Denmark were 40 million boe.
Proved undeveloped reserves were 41% of our total proved reserves at December 31, 2021 on a boe basis (2020: 30%).  Proved reserves held under production sharing contracts totaled 26% of our crude oil reserves and 36% of our natural gas reserves at December 31, 2021 (2020: 28% and 48%, respectively).
6


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 89 through 98.
Production
Worldwide crude oil, NGL, and natural gas net production was as follows:
 202120202019
Crude oil – Thousands of barrels 
United States   
North Dakota29,176 39,047 34,299 
Offshore (a)10,451 13,961 16,628 
Total United States39,627 53,008 50,927 
Guyana10,920 7,457 67 
Malaysia and JDA1,264 1,287 1,479 
Other (b)7,791 3,358 9,161 
Total59,602 65,110 61,634 
Natural gas liquids – Thousands of barrels   
United States   
North Dakota17,889 20,514 15,150 
Offshore (a)1,517 1,878 1,942 
Total United States19,406 22,392 17,092 
Natural gas – Thousands of mcf 
United States   
North Dakota59,013 65,786 40,222 
Offshore (a)26,276 27,985 33,212 
Total United States85,289 93,771 73,434 
Malaysia and JDA126,743 106,618 128,071 
Other (b)3,557 2,540 7,144 
Total215,589 202,929 208,649 
Total Barrels of Oil Equivalent (in millions) (a) (b)114.9 121.3 113.5 
(a)In November 2020, we sold our working interest in the Shenzi Field in the deepwater Gulf of Mexico. Shenzi net production was 3.3 million boe in 2020 (2019: 4.5 million boe).
(b)Other includes our interests in Denmark, which were sold in August 2021, and Libya. Net production from Denmark was 1.2 million boe for 2021 (2020: 2.2 million boe; 2019: 2.6 million boe). Net production from Libya was 7.2 million boe for 2021 (2020: 1.6 million boe; 2019: 7.8 million boe).
E&P Operations
At December 31, 2021, our significant E&P assets included the following:
United States
Our production in the U.S. was from the Bakken shale play in the Williston Basin of North Dakota (Bakken) and from offshore properties in the Gulf of Mexico.
North Dakota:
Bakken:  At December 31, 2021, we held approximately 462,000 net acres in the Bakken with varying working interests.  Net production averaged 156,000 boepd in 2021.  Prior to COVID-19, we were operating six rigs in the Bakken, but reduced the rig count to one in May 2020 in response to the sharp decline in crude oil prices. We added a second operated rig in the Bakken in February 2021 and a third operated rig in September 2021. We drilled 63 wells and brought 51 wells on production in 2021, bringing the total operated production wells to 1,599 at December 31, 2021.  During 2022, we plan to operate three rigs, drill approximately 90 wells and bring approximately 85 wells on production.
Offshore:
Gulf of Mexico:  At December 31, 2021, we held approximately 61,000 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, 2021, we held approximately 267,000 net undeveloped acres, of which leases covering approximately 105,000 acres are due to expire in the next three years. In February 2022, we commenced drilling at the Huron exploration prospect (Hess 40%) located on Green Canyon Block 69.
7


Guyana
Stabroek Block:  The Stabroek Block (Hess 30%), offshore Guyana, covers approximately 6.6 million acres.  The operator, Esso Exploration and Production Guyana Limited, has made numerous discoveries since 2015, with the discovered resources to date on the block expected to underpin the potential for up to ten FPSOs. The first six FPSOs are expected to have an aggregate production capacity of more than 1 million gross bopd in 2027.
The Liza Phase 1 development, which was sanctioned in 2017, began producing oil in December 2019 utilizing the Liza Destiny FPSO, has a nameplate production capacity of approximately 120,000 gross bopd and in 2022 its production capacity is expected to increase to more than 140,000 gross bopd following production optimization work. The Liza Phase 2 development, which was sanctioned in 2019, began producing oil in February 2022 from the Liza Unity FPSO. The Liza Unity is expected to reach its production capacity of approximately 220,000 gross bopd later in 2022 as operations are safely brought online.
The Payara Field development was sanctioned in 2020 and will utilize the Prosperity FPSO, which will have the capacity to produce up to 220,000 gross bopd, with first production expected in 2024. Ten drill centers with a total of 41 wells are planned, including 20 production wells and 21 injection wells.
A fourth development, Yellowtail, was submitted to the government of Guyana for approval in the fourth quarter of 2021. Pending government approval and project sanctioning, the project is expected to have a capacity of 250,000 gross bopd with first production anticipated in 2025.
The operator is currently utilizing six drillships for exploration, appraisal and development drilling activities. In 2021, the following exploration and appraisal wells were drilled on the Stabroek Block (in chronological order):
Hassa: The Hassa-1 well encountered approximately 50 feet of oil bearing reservoir in deeper geologic intervals, although the well did not encounter oil in the primary target areas.
Koebi: The operator completed drilling of the Koebi-1 well which did not encounter commercial quantities of hydrocarbons.
Uaru:  The Uaru-2 well encountered 120 feet of high quality oil bearing sandstone reservoir, including newly identified intervals below the original Uaru-1 discovery. The well was drilled in 5,659 feet of water and is located approximately 6.8 miles south of the Uaru-1 well.
Longtail: The Longtail-2 well commenced drilling in March 2021 and drill stem testing was completed in the fourth quarter of 2021. In the second quarter of 2021, the Longtail-3 well encountered 230 feet of net pay, including newly identified, high quality hydrocarbon bearing reservoirs below the original Longtail-1 discovery intervals. The well was drilled in more than 6,100 feet of water and is located approximately 2 miles south of the Longtail-1 well.
Mako: The Mako-2 well confirmed the quality, thickness and areal extent of the reservoir. When integrated with the results at Uaru-2, the combined discovered resource at Mako and Uaru is expected to support a fifth FPSO on the Stabroek Block.
Whiptail: The Whiptail-1 well encountered 246 feet of net pay in high quality oil bearing sandstone reservoirs and was drilled in 5,889 feet of water. The Whiptail-2 well encountered 167 feet of net pay in high quality oil bearing sandstone reservoirs and was drilled in 6,217 feet of water. The Whiptail discovery is located approximately 4 miles southeast of the Uaru-1 discovery and approximately 3 miles west of the Yellowtail field.
Pinktail: The Pinktail-1 well encountered 220 feet of net pay in high quality oil bearing sandstone reservoirs. The well was drilled in 5,938 feet of water and is located approximately 21.7 miles southeast of the Liza Phase 1 development and approximately 3.7 miles southeast of the Yellowtail-1 well.
Turbot: The Turbot-2 well encountered 43 feet of net pay in a newly identified, high quality oil bearing sandstone reservoir separate from the 75 feet of high quality, oil bearing sandstone reservoir pay encountered in the original Turbot-1 discovery well. The well was drilled in 5,790 feet of water and is located approximately 37 miles to the southeast of the Liza Phase 1 development and 2.5 miles from the Turbot-1 well.
Cataback: The Cataback-1 well encountered 243 feet of net pay in high quality hydrocarbon bearing sandstone reservoirs of which 102 feet is oil bearing. The well was drilled in 5,928 feet of water and is located approximately 3.7 miles east of the Turbot-1 well.
Tripletail: The Tripletail-2 well was completed in the fourth quarter and was temporarily abandoned following completion of logging operations.
8


In the first quarter of 2022, the following exploration wells were completed on the Stabroek Block:
Fangtooth: The Fangtooth-1 well encountered 164 feet of net pay in high quality oil bearing sandstone reservoirs, and confirms the deeper exploration potential of the Stabroek Block. The well was drilled in 6,030 feet of water and is located approximately 11 miles northwest of the Liza Field.
Lau Lau: The Lau Lau-1 well encountered 315 feet of net pay in high quality hydrocarbon bearing sandstone reservoirs. The well was drilled in 4,793 feet of water and is located approximately 42 miles southeast of the Liza Field.
The operator plans to drill approximately 12 exploration and appraisal wells in 2022 that will target a variety of prospects and play types. These will include both lower risk wells near existing discoveries and higher risk step-out wells, and several penetrations that will test deeper Lower Campanian and Santonian intervals.
Kaieteur Block: In 2021, we acquired an additional 5% participating interest in the Kaieteur Block, which is adjacent to the Stabroek Block, increasing our total participating interest to 20%. Seismic evaluation and planning for the next exploration well are ongoing.
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 2022, the operator plans to drill approximately four development wells.
Malaysia:  Our production in Malaysia comes from our interest in Block PM302 (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 2022, we plan to continue drilling and development activities at NMB. In 2022, we plan to drill approximately five development wells.
Other
Libya:  At the onshore Waha concession in Libya, which includes the Defa, Faregh, Gialo, North Gialo and Belhedan fields (Hess 8%), net production averaged 20,000 boepd in 2021, 4,000 boepd in 2020 and 21,000 boepd in 2019. Production was shut-in by the operator between January 2020 and October 2020 due to force majeure caused by civil unrest.
Suriname:  We hold a 33% non-operated participating interest in Block 42, offshore Suriname.  The operator, a subsidiary of Royal Dutch Shell plc, plans to drill one exploration well in 2022 and one exploration well in 2023.  We also hold a 33% non-operated participating interest in Block 59, offshore Suriname, where the operator, ExxonMobil Exploration and Production Suriname B.V., is interpreting recently acquired 2D seismic and has completed the acquisition of a 3D seismic survey.
Canada:  We hold a 25% non-operated participating interest in three exploration licenses offshore Newfoundland.  In 2023, the operator, BP Canada, plans to drill one exploration well.
Sales Commitments
We have certain long-term contracts with fixed minimum sales volume commitments for natural gas and NGL production.  At the JDA in the Gulf of Thailand, we have annual minimum net sales commitments of approximately 70 billion cubic feet of natural gas per year through 2025 and approximately 30 billion cubic feet per year in 2026 and 2027.  At the North Malay Basin development project offshore Peninsular Malaysia, we have annual net sales commitments of approximately 55 billion cubic feet per year through 2024.  Our estimated total volume of production subject to these sales commitments is approximately 520 billion cubic feet of natural gas.  We also have multiple minimum delivery commitments in the Bakken for natural gas and NGL with various end dates up through 2032, with total commitments of approximately 90 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.
9


Selling Prices and Production Costs
The following table presents our average selling prices and average production costs:
202120202019
Average Selling Prices (a)
Crude Oil - Per Barrel (Including Hedging)
United States
North Dakota$55.57 $42.63 $53.19 
Offshore60.09 45.92 59.18 
Total United States56.64 43.56 55.15 
Guyana68.57 46.41 — 
Malaysia and JDA71.00 37.91 61.81 
Other (b)66.39 51.37 65.22 
Worldwide60.08 44.28 56.77 
Crude Oil - Per Barrel (Excluding Hedging)
United States
North Dakota$59.90 $33.87 $53.18 
Offshore64.77 36.55 59.17 
Total United States61.05 34.63 55.14 
Guyana71.07 37.40 — 
Malaysia and JDA71.00 37.91 61.81 
Other (b)69.25 43.42 65.22 
Worldwide63.90 35.52 56.76 
Natural Gas Liquids - Per Barrel
United States
North Dakota$30.74 $11.29 $13.20 
Offshore26.40 8.94 13.31 
Worldwide30.40 11.10 13.21 
Natural Gas - Per Mcf
United States
North Dakota$4.08 $1.27 $1.59 
Offshore3.25 1.23 2.12 
Total United States3.82 1.26 1.83 
Malaysia and JDA5.15 4.47 5.04 
Other (b)3.40 3.41 4.63 
Worldwide4.60 2.98 3.90 
Average production (lifting) costs per barrel of oil equivalent produced (c)   
United States   
North Dakota (d)$25.87 $17.67 $19.68 
Offshore12.88 11.27 11.27 
Total United States23.27 16.59 17.66 
Guyana (e)17.93 18.25 — 
Malaysia and JDA4.72 5.77 6.07 
Other (b)6.34 22.78 8.87 
Worldwide17.91 15.19 14.93 
(a)Includes intercompany transfers valued at approximate market prices, primarily onshore U.S., which include certain processing and distribution fees.
(b)Other includes our interests in Denmark, which were sold in August 2021, and Libya.
(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 $19.23 per boe in 2021 (2020: $13.42 per boe; 2019: $12.89 per boe).
(e)Includes pre-development costs from the operator for future phases of development and Hess internal costs totaling $5.76 per boe in 2021 (2020: $5.11 per boe).
10


Gross and Net Undeveloped Acreage
At December 31, 2021, gross and net undeveloped acreage amounted to:
Undeveloped
Acreage (a)
 GrossNet
 (In thousands)
United States333 279 
Guyana9,873 2,628 
Malaysia and JDA197 98 
Libya3,334 272 
Canada3,405 1,283 
Suriname4,363 1,454 
Total (b)21,505 6,014 
(a)Includes acreage held under production sharing contracts.
(b)At December 31, 2021, 65% of our net undeveloped acreage, primarily in Suriname, Canada, 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, 2021 gross and net developed acreage and productive wells amounted to:
 Developed Acreage Applicable to Productive WellsProductive Wells (a)
 OilGas
 GrossNetGrossNetGrossNet
 (In thousands)    
United States839 512 2,887 1,358 11 
Guyana95 29 — — 
Malaysia and JDA491 245 — — 121 58 
Libya9,564 782 1,134 93 10 
Total10,989 1,568 4,027 1,453 142 64 
(a)Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 33 gross wells and 29 net wells.
Exploratory and Development Wells
Net exploratory and net development wells completed during the years ended December 31 were:
 Net Exploratory WellsNet Development Wells
 202120202019202120202019
Productive wells      
United States4898140 
Guyana3123
Malaysia and JDA23
Libya1
 3 54 101 147 
Dry holes      
United States —  — — 
Guyana (a) — —  — — 
Denmark —  — — 
   — — 
Total3 54 101 147 
(a)Includes the Koebi-1 well at the Stabroek Block, offshore Guyana, in 2021 and the Tanager-1 well at the Kaieteur Block, offshore Guyana, in 2020.
11


Number of Wells in the Process of Being Drilled
At December 31, 2021, the number of wells in the process of drilling amounted to:
Gross
Wells
Net
Wells
United States115 20 
Guyana (a)15 
Malaysia and JDA
Total136 28 
(a)Includes five gross (and two net) water injection and gas injection wells in process at December 31, 2021.
Midstream
Prior to December 16, 2019, the Midstream segment was primarily comprised of Hess Infrastructure Partners LP (HIP), a 50/50 joint venture between Hess Corporation and Global Infrastructure Partners (GIP), formed to own, operate, develop and acquire a diverse set of midstream assets to provide fee-based services to Hess and third-party customers.  HIP was initially formed on May 21, 2015, with Hess selling 50% of HIP to GIP for approximately $2.6 billion on July 1, 2015.
On April 10, 2017, HIP completed an initial public offering (IPO) of 16,997,000 common units, representing 30.5% limited partnership interests in its subsidiary Hess Midstream Partners LP (Hess Midstream Partners), for net proceeds of approximately $365.5 million.  In connection with the IPO, HIP contributed a 20% controlling economic interest in each of Hess North Dakota Pipeline Operations LP, Hess TGP Operations LP, and Hess North Dakota Export Logistics Operations LP, and a 100% economic interest in Hess Mentor Storage Holdings LLC (collectively the “Contributed Businesses”).  In exchange for the contributed businesses, Hess and GIP each received common and subordinated units representing a direct 33.75% limited partner interest in Hess Midstream Partners and a 50% indirect ownership interest through HIP in Hess Midstream Partners’ general partner, which had a 2% economic interest in Hess Midstream Partners plus incentive distribution rights.
On December 16, 2019, Hess Midstream Partners acquired HIP, including HIP’s 80% interest in Hess Midstream Partners’ oil and gas midstream assets, HIP’s water services business and the outstanding economic general partner interest and incentive distribution rights in Hess Midstream Partners LP.  In addition, Hess Midstream Partners’ organizational structure converted from a master limited partnership into an “Up-C” structure in which Hess Midstream Partners’ public unitholders received newly issued Class A shares in a new public entity named Hess Midstream LP (Hess Midstream), which is taxed as a corporation for U.S. federal and state income tax purposes.  Hess Midstream Partners changed its name to “Hess Midstream Operations LP” (HESM Opco) and became a consolidated subsidiary of Hess Midstream, the new publicly listed entity.  As consideration for the acquisition, Hess received a cash payment of $301 million and approximately 115 million newly issued HESM Opco Class B units.  After giving effect to the acquisition and related transactions, public shareholders of Class A shares in Hess Midstream owned 6% of the consolidated entity on an as-exchanged basis and Hess and GIP each owned 47% of the consolidated entity on an as-exchanged basis, primarily through the sponsors’ ownership of Class B units in HESM Opco that are exchangeable into Class A shares of Hess Midstream on a one-for-one basis.
In March 2021, Hess Midstream completed an underwritten public equity offering of 6.9 million Class A shares held by Hess and GIP. These Class A shares of Hess Midstream were obtained by Hess and GIP through the exchange of 6.9 million of their Class B units of HESM Opco. In August 2021, HESM Opco repurchased 31.25 million Class B units held by Hess and GIP for $750 million. Hess received net proceeds of $375 million. HESM Opco issued $750 million in aggregate principal amount of 4.250% fixed-rate senior unsecured notes due 2030 in a private offering to finance the repurchase. In October 2021, Hess Midstream completed an underwritten public equity offering of approximately 8.6 million Class A Shares held by Hess and GIP. These Class A shares of Hess Midstream were obtained by Hess and GIP through the exchange of approximately 8.6 million of their Class B units of HESM Opco. After giving effect to the above transactions in 2021, public shareholders of Class A shares of Hess Midstream own approximately 13%, and Hess and GIP each own approximately 43.5%, of the consolidated entity on an as-exchanged basis at December 31, 2021.
At December 31, 2021, Midstream assets included the following:
Natural Gas Gathering and Compression: A natural gas gathering and compression system located primarily in McKenzie, Williams and Mountrail Counties, North Dakota connecting Hess and third-party owned or operated wells to the Tioga Gas Plant, Little Missouri 4 Gas Plant, and third-party pipeline facilities.  This gathering system consists of approximately 1,350 miles of high and low pressure natural gas and NGL gathering pipelines with a current capacity of up to approximately 450 mmcfd, including an aggregate compression capacity of approximately 325 mmcfd.
Crude Oil Gathering: A crude oil gathering system located primarily in McKenzie, Williams and Mountrail Counties, North Dakota, connecting Hess and third-party owned or operated wells to the Ramberg Terminal Facility, the Tioga Rail Terminal and the Johnson’s Corner Header System.  The crude oil gathering system consists of approximately 550 miles of crude oil gathering pipelines with a current capacity of up to approximately 240,000 bopd.
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Tioga Gas Plant: A natural gas processing and fractionation plant located in Tioga, North Dakota, with a current processing capacity of approximately 400 mmcfd, and cryogenic and fractionation capacity of approximately 80,000 boepd.  In 2020, facility construction for an expansion of the plant to 400 mmcfd from 250 mmcfd was completed. The incremental gas processing capacity was placed in service in the fourth quarter of 2021 following completion of a planned maintenance turnaround which included connecting the expansion and residue NGL takeaway pipelines to the plant. The total processing capacity of 400 mmcfd became available in February 2022.
Little Missouri 4: A natural gas processing plant in McKenzie County, North Dakota, with processing capacity of approximately 200 mmcfd, which was placed in service during 2019 and is operated by Targa Resources Corp.  Hess Midstream LP owns a 50% interest in Little Missouri 4 through a joint venture with Targa Resources Corp. and is entitled to half of the plant’s processing capacity.
Mentor Storage Terminal: A propane storage cavern and rail and truck loading and unloading facility located in Mentor, Minnesota, with approximately 330,000 boe of working storage capacity.
Ramberg Terminal Facility: A crude oil pipeline and truck receipt terminal located in Williams County, North Dakota with a delivery capacity of up to approximately 285,000 bopd of crude oil into an interconnecting pipeline for transportation to the Tioga Rail Terminal and to multiple 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 third-party interstate pipeline systems.  The facility has a delivery capacity of approximately 100,000 bopd of crude oil.
Produced Water Gathering and Disposal: A produced water gathering system located primarily in Williams and Mountrail Counties, North Dakota, that transports produced water from the wellsite by approximately 270 miles of pipeline in gathering systems or by third-party trucking to water handling facilities for disposal.
Hess Midstream has multiple long-term, fee-based commercial agreements effective January 1, 2014 with certain subsidiaries of Hess for gas gathering, crude oil gathering, gas processing and fractionation, storage services, and terminal and export services, each generally with an initial ten-year term that can be extended for an additional ten-year term at the unilateral right of Hess Midstream. These contracts have minimum volumes that the Hess subsidiaries are obligated to provide each calendar quarter. The minimum volume commitments are subject to fluctuation based on nominations covering substantially all of our E&P segment’s production and projected third-party volumes that will be purchased in the Bakken. On December 30, 2020, Hess Midstream exercised its renewal options to extend the terms of certain gas gathering, crude oil gathering, gas processing and fractionation, storage, and terminal and export commercial agreements for the secondary term through December 31, 2033. There were no changes to any provisions of the existing commercial agreements as a result of the exercise of the renewal options. Hess Midstream also has long-term, fee based commercial agreements for water handling services effective January 1, 2019 with a subsidiary of Hess, with an initial 14 year term that can be extended for an additional ten-year term at the unilateral right of Hess Midstream. Water handling services are provided for an agreed-upon fee per barrel or the reimbursement of third-party fees.
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, WWCC and OSRL.  CGA and MSRC are domestic spill response organizations
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and MWCC provides the equipment and personnel to contain underwater well control incidents in the Gulf of Mexico. WWCC 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, Technical Operations Committee of CGA and Oil Spill and Emergency 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 $400 million of coverage is provided through an industry mutual insurance group.  Above this $400 million threshold, insurance is carried which ranges in value up to $535 million in total, depending on the asset coverage level, as described above.  The decrease in the total value of insurance above the $400 million threshold from December 31, 2020 is primarily driven by the sale of our interests in Denmark in August 2021. 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 joint operating arrangement would be reduced to our participating interest.  Our insurance policies renew at various dates each year.  Future insurance coverage could increase in cost and may include higher deductibles or retentions, or additional exclusions or limitations.  In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are deemed economically acceptable.
Generally, our drilling contracts (and most of our other offshore services contracts) provide for a mutual hold harmless indemnity structure whereby each party to the contract (the Corporation and Contractor) indemnifies the other party for injuries or damages to their personnel and property (and, often, those of its contractors/subcontractors) regardless of fault.  Variations may include indemnity exclusions to the extent a claim is attributable to the gross negligence and/or willful misconduct of a party.  Third-party claims, on the other hand, are generally allocated on a fault basis.
We are customarily responsible for, and indemnify the Contractor against, all claims including those from third parties, to the extent attributable to pollution or contamination by substances originating from our reservoirs or other property and the Contractor is responsible for and indemnifies us for all claims attributable to pollution emanating from the Contractor’s property.  Variations may include indemnity exclusions to the extent a claim is attributable to the gross negligence and/or willful misconduct of a party.  Additionally, we are generally liable for all of our own losses and most third-party claims associated with catastrophic losses such as damage to reservoirs, blowouts, cratering and loss of hole, regardless of cause, although exceptions for losses attributable to gross negligence and/or willful misconduct do exist.  Lastly, some offshore services contracts include overall limitations of the Contractor’s liability equal to a fixed negotiated amount.  Variations may include exclusions of all contractual indemnities from the liability cap.
Under a standard JOA, each party is liable for all claims arising under the JOA, to the extent of its participating interest (operator or non-operator).  Variations include indemnity exclusions when the claim is based upon the gross negligence and/or willful misconduct of the operator, in which case the operator is solely liable.  The parties to the JOA may continue to be jointly and severally liable for claims made by third parties in some jurisdictions.  Further, under some production sharing contracts between a governmental entity and commercial parties, liability of the commercial parties to the government entity is joint and several.
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Government Regulations
The crude oil and natural gas industry is regulated at federal, state, local and foreign government levels. Regulations affecting elements of the energy sector are under continuous review for amendment or expansion over time, which may result in incremental costs of doing business and affect our profitability. See Regulatory, Legal and Environmental Risks in Item 1A. Risk Factors. Compliance with various existing environmental, health and safety regulations is not expected to have a material adverse effect on our financial condition or results of operations. However, increasingly stringent environmental regulations have resulted and will likely continue to result in higher capital expenditures and operating expenses for us and the oil and gas industry in general and may reduce demand for our products. We spent approximately $16 million in 2021 for environmental remediation. Additionally, we may be exposed to decommissioning liabilities, including for divested assets. For example, in June 2021, the U.S. Bankruptcy Court approved the bankruptcy plan for Fieldwood Energy LLC (Fieldwood) which includes transferring abandonment obligations of Fieldwood to predecessors in title of certain of its assets, including Hess, who are jointly and severally liable for the obligations. As a result, we recognized a charge of $147 million ($147 million after income taxes) in connection with total estimated abandonment obligations for seven leases in the West Delta Field in the Gulf of Mexico, which we sold to a Fieldwood predecessor in 2004. See Item 3. Legal Proceedings and Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements. The level of other expenditures to comply with federal, state, local and foreign country regulations is difficult to quantify as such costs are captured as mostly indistinguishable components of our capital expenditures and operating expenses. For further discussion of environmental, health and safety regulations affecting our business, see Environment, Health and Safety in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Human Capital Management
Corporate Culture and Overview
Our human capital strategy aims to attract, engage and retain our talent by investing in their professional development and providing them with challenging and rewarding opportunities for personal growth. Our workplace culture is guided by our Corporation’s values and reinforced by developing quality leadership, fostering DEI, emphasizing continuous learning, creating opportunities for engagement, driving innovation and embracing Lean processes. We are pursuing a Life at Hess initiative to optimize the work experience for our multigenerational 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, 2021, we had 1,545 employees globally, as detailed below.

United StatesGuyanaMalaysia and JDALibyaTotal
Job Category
Executives and Senior Officers31 — — 32 
First and Mid-Level Managers327 — 60 388 
Professionals699 — 78 779 
Other343 — — 346 
Total1,400  142 3 1,545 
Life at Hess
We prioritize the safety of our workforce. Our safety programs and practices are designed to help ensure that everyone, everywhere gets home safe every day. Our continued response to COVID-19 reflects this commitment. A multidisciplinary Hess emergency response team has been overseeing plans and precautions to reduce the risks of COVID-19 in the work environment while maintaining business continuity based on the most current recommendations by government and public health agencies. The Corporation has continued to utilize a variety of health and safety measures including enhanced cleaning procedures and modified work practices such as travel restrictions, health screenings, reduced personnel at offshore platforms and onshore work sites wherever this can be done safely, and remote working arrangements for office workers. We continue to adapt our work policies and benefits to prioritize emotional, mental and physical health and well-being. We are taking a deliberate and measured approach to returning to the physical work environment in each of our office locations.
During 2021, we evolved our Life at Hess initiative for managing culture in periods of change. Particularly in a hybrid remote working environment, the work experience has changed and continues to evolve through:
Virtual learning opportunities and training,
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Support for remote working effectiveness,
Mental well-being support, and
Leadership training and development to help leaders navigate the complex environment of remote working, societal changes, COVID-19 and market dynamics.
Diversity, Equity and Inclusion
In keeping with our values and purpose, we have a longstanding commitment to DEI and taking action to foster a sustainable culture of inclusion for everyone. DEI is a business imperative for improved performance and the innovation needed to accomplish our business goals now and in the future. Additionally, Hess is committed to providing a global workplace free from discrimination and harassment, where everyone can achieve their full potential. We provide equal employment opportunities for all employees and job candidates regardless of race, color, religion, gender, age, sexual orientation, gender identity, creed, national origin, genetic information, disability, veteran status or any other protected status.
Hess’ DEI Council provides executive leadership guidance to embed DEI into our culture and operations to drive progress throughout the organization. Our expectations for an inclusive and diverse workplace and our culture of mutual respect and trust are spelled out in our Code of Conduct and Ethics and related policies and reinforced regularly with employees at every level of our Corporation through regular communication and ongoing training. Additional information regarding our policies and practices, including training, employee engagement initiatives and workforce data, is included in our annual Sustainability Report and annual U.S. Equal Employment Opportunity reporting, which is available on our website at www.hess.com.
During 2021, Hess maintained or improved diversity across levels of our workforce. As detailed below, representation of women and minorities among all employees improved from 2020 to 2021. Overall, women increased by 1% and minorities increased by 2%, with notable improvements at the Executive and Professional levels. Our increased strategic focus on DEI including our talent practices and diversity outreach programs contributed to this improvement. In August 2021, we hired a DEI leader to develop a tailored, long-term strategy that defines our objectives and strategies to advance DEI now and in the future. Additionally, workforce activity and trends such as employee turnover, promotions, DEI and development metrics, along with qualitative information such as program development and progress, are shared with our Board of Directors annually, with more detailed reviews by the Compensation and Management Development Committee throughout the year.
Women
(U.S. and International)
Minorities (a)
(U.S. Based Employees)
202120202019202120202019
Job Category
Executives and Senior Officers16 %13 %16 %19 %13 %13 %
First and Mid-Level Managers23 %23 %22 %20 %20 %19 %
Professionals34 %32 %31 %30 %27 %26 %
Other19 %17 %18 %16 %16 %17 %
Total27 %26 %26 %24 %22 %22 %
(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 our compensation programs annually through industry specific surveys and conduct an annual review to identify and address compensation inequities. Our Corporation maintains an annual incentive plan that applies to all employees, including executive officers, that shares the same enterprise performance metrics for all participants. In addition, we provide a comprehensive wellness program that addresses physical wellness and focuses on the financial, social and emotional well-being of our employees.
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Information about our Executive Officers
The following table presents information as of March 1, 2022 regarding executive officers of the Corporation:
 Name
AgeOffice Held* and Business ExperienceYear Individual Became an Executive Officer
John B. Hess67
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 40 years of experience in the oil and gas industry.
1983
Gregory P. Hill60
President and Chief Operating Officer
Mr. Hill has been Chief Operating Officer since 2014 and President of the Corporation’s worldwide Exploration and Production business since joining the Corporation in January 2009.  Prior to joining the Corporation, Mr. Hill spent 25 years at Royal Dutch Shell and its affiliates in a variety of operations, engineering, technical and managerial roles in Asia-Pacific, Europe and the United States.
2009
Timothy B. Goodell64
Executive Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer
Mr. Goodell has been General Counsel of the Corporation since 2009, Corporate Secretary since 2016, Chief Compliance Officer since 2017 and Executive Vice President since 2020.  Prior to joining the Corporation in 2009, he was a partner at the law firm of White & Case, LLP where he spent 25 years.
2009
John P. Rielly59
Executive Vice President and Chief Financial Officer
Mr. Rielly has been Chief Financial Officer of the Corporation since 2004 and Executive Vice President since 2020.  Mr. Rielly previously served as Vice President and Controller of the Corporation from 2001 to 2004.  Prior to joining the Corporation in 2001, he was a Partner at Ernst & Young, LLP where he was employed for 17 years.
2002
Richard Lynch64
Senior Vice President, Technology and Services
Mr. Lynch has been Senior Vice President, Technology and Services of the Corporation since 2018.  Mr. Lynch previously was Senior Vice President Global Developments, Drilling and Completions from 2014.  Prior to joining the Corporation in 2014, Mr. Lynch spent over 30 years in well delivery and operations, as well as project and asset management, with BP plc and ARCO.
2018
Gerbert Schoonman56
Senior Vice President, Global Production
Mr. Schoonman has been Senior Vice President, Global Production of the Corporation since January 2020.  Since joining the Company in 2011, he served in various operational leadership roles, including as Vice President, Production – Asia Pacific, from January 2011 through August 2012; Vice President, Onshore – Bakken from September 2012 through December 2016; and most recently, as Vice President, Offshore since January 2017.  Prior to joining the Corporation, he spent 20 years with Royal Dutch Shell where he served in operational and leadership roles.
2020
Andrew Slentz60
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 25 years in human resources experience at large international public companies.
2016
Barbara Lowery-Yilmaz65
Senior Vice President and Chief Exploration Officer
Ms. Lowery-Yilmaz has been the Senior Vice President, Exploration of the Corporation since August 2014.  Ms. Lowery-Yilmaz has over 30 years of oil and gas industry experience in exploration and technology with BP plc and its affiliates including senior leadership roles.
2014
*All officers referred to herein hold office in accordance with the By-laws until the first meeting of directors in connection with the annual meeting of stockholders of the Registrant and until their successors shall have been duly chosen and qualified.  Each of said officers was elected to the office opposite their name on June 1, 2021.
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.

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Access to Our Reports
We make available free of charge through our website, www.hess.com, our annual report on Form 10‑K, quarterly reports on Form 10‑Q, current reports on Form 8‑K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission.  The information on our website is not incorporated by reference in this report.  Our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and the charters for the Audit Committee, Compensation and Management Development Committee, Corporate Governance and Nominating Committee and Environmental, Health and Safety Committee of the Board of Directors are available on our website and are also available free of charge upon request to Investor Relations at our principal executive office.  We also file with the New York Stock Exchange (NYSE) an annual certification that our Chief Executive Officer is unaware of any violation of the NYSE’s corporate governance standards.
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Item 1A.  Risk Factors
Our business activities and the value of our securities are subject to significant risks, including the risk factors described below. These risk factors could negatively affect our operations, financial condition, liquidity and results of operations, and as a result, holders and purchasers of our securities could lose part or all of their investments. It is possible that additional risks relating to our securities may be described in a prospectus supplement if we issue securities in the future.
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 and availability of alternative fuels or other forms of energy, the effect of energy conservation and environmental protection efforts and overall economic conditions globally.  The sentiment of commodities trading markets as well as other supply and demand factors, including COVID-19, may also influence the selling prices of crude oil, NGL and natural gas. Average benchmark prices for 2021 were $68.08 per barrel for WTI (2020: $39.34; 2019: $57.04) and $70.95 per barrel for Brent (2020: $43.21; 2019: $64.16).  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.
Our business and operations have been and may continue to be adversely affected by COVID-19 or other similar public health developments and related changes to demand for oil and natural gas. Since 2020, COVID-19 and related actions taken by governments and businesses, including voluntary and mandatory quarantines and travel and other restrictions, have significantly impacted economic activity. As a result of COVID-19, our operations, and those of our business partners, service companies and suppliers, have experienced and may continue to experience further adverse effects, including but not limited to: disruptions, delays or temporary suspensions of operations, including shut-ins of production; temporary inaccessibility or closures of facilities; supply chain issues; and workforce impacts from illness, school closures and other community response measures. We have implemented a variety of health and safety measures, including enhanced cleaning procedures and modified work practices, such as travel restrictions, health screenings, vaccination policies, reduced personnel at offshore platforms and onshore work sites, wherever such reduction can be done safely, and remote working arrangements for office workers. There is no certainty that these or any other future measures will be sufficient to mitigate the risks posed by the virus and its variants, including the risk of infection of key employees, and our ability to perform certain functions could be impaired by these new business practices. For example, our reliance on technology has necessarily increased due to our use of remote communications and other work-from-home practices, which could make us more vulnerable to cyber-attacks. To the extent we or our business partners, service companies or suppliers continue to experience restrictions or other effects, our financial condition, results of operations and future expansion projects may be adversely affected.
In addition to the global health concerns, COVID-19 negatively affected the U.S. and global economy and the demand for oil and natural gas. The prolonged continuation or amplification of the outbreak of COVID-19 could result in further economic downturn that may affect our operating results in the long-term. Furthermore, the effects of COVID-19 and concerns regarding the global spread of its variants negatively impacted the domestic and international demand for crude oil and natural gas, which has contributed to price volatility and adversely affected the demand for and marketability of crude oil, natural gas and NGL. Containment measures implemented to mitigate the spread of COVID-19 and its variants could continue to be widespread and lead to sustained adoption of certain behavioral changes, such as reduced travel and enhanced work-from-home policies, which could result in further reductions in demand for and consumption of energy commodities. A reduction in consumer demand for crude oil, natural gas and NGL could require further curtailments and shut-ins of production by the industry and further increase the costs of commercial storage and midstream contracts.
The timeline and potential magnitude of COVID-19 remains unknown and will depend on future developments, including, among others, the global availability of vaccines, the efficacy of vaccines against variants and the extent to which normal economic and operating conditions resume. In the event one or more of our business partners is adversely affected by COVID-19 or the current market environment, that may impact our costs and ability to conduct business with them. In addition, we may face an increased risk of changes in the regulation related to our business resulting from COVID-19, such as the imposition of limitations on our workforce's ability to access our facilities. We also are subject to litigation risk and possible loss contingencies related to COVID-19, including with respect to commercial contracts, employee matters and insurance arrangements. We may experience decreases in production and
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proved reserves, additional asset impairments, and other accounting charges if demand for crude oil, natural gas and NGL decreases. A sustained extension of the current market environment may make it more difficult to comply with covenants and other restrictions in agreements governing our debt, and a lack of confidence in our industry on the part of the financial markets may result in a lack of access to capital, any of which could lead to reduced liquidity.
As the impact from COVID-19 remains difficult to predict, the extent to which it may negatively affect our operating results is uncertain. Any impact will depend on future developments and new information that may emerge regarding the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control.
We do not always control decisions made under joint operating agreements and the parties under such agreements may fail to meet their obligations. We conduct many of our E&P operations through joint operating agreements with other parties under which we may not control decisions, either because we do not have a controlling interest or are not operator under the agreement. There is risk that these parties may at any time have economic, business, or legal interests or goals that are inconsistent with ours, and therefore decisions may be made which are not what we believe is in our best interest. Moreover, parties to these agreements may be unable to meet their economic or other obligations and we may be required to fulfill those obligations alone. For example, in June 2021, the U.S. Bankruptcy Court approved the bankruptcy plan for Fieldwood which includes transferring abandonment obligations of Fieldwood to us and other predecessors in title of certain of its assets, who are jointly and severally liable for the obligations. See Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements. As a result, actions of our contractual counterparties may adversely affect the value of our investments and result in increased costs or liabilities.
Our industry is highly competitive and many of our competitors are larger and have greater resources and more diverse portfolios than we have. The petroleum industry is highly competitive and very capital intensive. We encounter competition from numerous companies, including acquiring rights to explore for crude oil and natural gas. To a lesser extent, we are also in competition with producers of alternative fuels or other forms of energy, including wind, solar and electric power, and in the future, could face increasing competition due to the development and adoption of new technologies. Many competitors, including national oil companies, are larger and have substantially greater resources to acquire and develop oil and gas assets. 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, prevailing oil and gas prices, production sharing contracts, which may decrease reserves as crude oil and natural gas prices increase, and other factors. Crude oil prices declined in 2020 and 2019, relative to comparative periods, resulting in reductions to our reported proved reserves. In contrast, crude oil prices improved in 2021, relative to the preceding year, resulting in increases to our proved reserves. If crude oil prices in 2022 average below prices used to determine proved reserves at December 31, 2021, it could have an adverse effect on our estimates of proved reserve volumes and on the value of our business. See Crude Oil and Natural Gas Reserves in Critical Accounting Policies and Estimates in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
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
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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, cratering, pipeline interruptions and ruptures, hurricanes, severe weather, geological events, shortages in availability of skilled labor, cyber-attacks or health measures related to 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. 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 2021 and 2020, hurricane-related downtime reduced net production by 4,000 boepd and 8,000 boepd, respectively, and hurricane related maintenance and repair costs were approximately $7 million in both 2021 and 2020. Moreover, some forms of insurance may be unavailable in the future or be available only on terms that are deemed economically unacceptable. In addition, the frequency and severity of weather conditions which 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. 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, 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. As a result, we may encounter difficulties in obtaining required services or could face an increase in cost, including as a result of changes to our industry due to COVID-19, 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 cyber security breaches affecting or targeting computer, telecommunications systems, and infrastructure used by the Corporation or our business partners may materially impact our business and operations. Computers and telecommunication systems are an integral part of our exploration, development and production activities and the activities of our business partners. We use these systems to analyze and store financial and operating data and to communicate within our corporation and with outside business partners. Our reliance on technology has increased due to the increased use of remote communications and other work-from-home practices in response to COVID-19. Technical system flaws, power loss, cyber security risks, including cyber or phishing-attacks, unauthorized access, malicious software, data privacy breaches by employees or others with authorized access, ransomware, and other cyber security issues could compromise our computer and telecommunications systems or those of our business partners and result in disruptions to our business operations or the access, disclosure or loss of our data and proprietary information. In addition, computers control oil and gas production, processing equipment, and distribution systems globally and are necessary to deliver our production to market. A disruption, failure or a cyber breach of these operating systems, or of the networks and infrastructure on which they rely, could damage critical production, distribution and/or storage assets, delay or prevent delivery to markets, and make it difficult or impossible to accurately account for production and settle transactions. As a result, any such disruption, failure or cyber breach and any resulting investigation or remediation costs, litigation or regulatory action could have a material adverse impact on our cash flows and results of operations, reputation and competitiveness. We routinely experience attempts by external parties to penetrate and attack our networks and systems. Although such attempts to date have not resulted in any material breaches, disruptions, financial loss, or loss of business-critical information, our systems and procedures for protecting against such attacks and mitigating such risks may prove to be insufficient in the future and such attacks could have an adverse impact on our business and operations, including damage to our reputation and competitiveness, remediation costs, litigation or regulatory actions. In addition, as technologies evolve and these cyber security attacks become more sophisticated, we may incur significant costs to upgrade or enhance our security measures to protect against such attacks and we may face difficulties in fully anticipating or implementing adequate preventive measures or mitigating potential harm.


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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. Two of the three major credit rating agencies that rate our debt have assigned an investment grade rating. Although currently we do not have any borrowings under our long-term credit facility, a ratings downgrade, continued weakness in the oil and gas industry or negative outcomes within commodity and financial markets could adversely impact our access to capital markets by increasing the costs of financing, or by impacting our ability to obtain financing on satisfactory terms. In addition, a ratings downgrade may require that we issue letters of credit or provide other forms of collateral under certain contractual requirements. 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 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.
The alteration or discontinuation of LIBOR may adversely affect our borrowing costs. Certain borrowings on our credit facilities may use LIBOR as a benchmark for establishing the rate. LIBOR is the subject of recent national, international and other regulatory guidance and proposals for reform. These reforms and other pressures are expected to cause LIBOR to be discontinued after June 30, 2023 or to perform differently than in the past. In the U.S., the Alternative Reference Rates Committee, which was convened by the Federal Reserve Board and the Federal Reserve Bank of New York, has proposed SOFR as an alternative to LIBOR. At this time, the consequences of these developments cannot be entirely predicted, but could include fluctuations in interest rates or an increase in the cost of our credit facility borrowings.
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 and sustainability initiatives may result in significant operational changes and expenditures, reduced demand for our products and adversely affect our business. We recognize that climate change and sustainability is a growing global environmental concern. Continuing political and social attention to the issue of climate change and sustainability has resulted in both existing and pending international agreements and national, regional or local legislation and regulatory measures to limit GHG emissions. These agreements and measures may require, or could result in future legislation and regulatory measures that require, significant equipment modifications, operational changes, taxes, or purchase of emission credits to reduce emission of GHGs from our operations, which may result in substantial capital expenditures and compliance, operating, maintenance and remediation costs. In addition, 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. As a result of heightened public awareness and attention to climate change and sustainability as well as continued regulatory initiatives
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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. 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. Furthermore, increasing attention to climate change risks and sustainability has resulted in governmental investigations, and public and private litigation, which could increase our costs or otherwise adversely affect our business. For example, beginning in 2017, certain states, municipalities and private associations in California, Delaware, Maryland, Rhode Island and South Carolina separately filed lawsuits against oil, gas and coal producers, including us, for alleged damages purportedly caused by climate change. Such actions could adversely impact our business by distracting management and other personnel from their primary responsibilities, require us to incur increased costs, and/or result in reputational harm.
We are subject to changing laws and regulations and other governmental actions that can significantly and adversely affect our business. Political or regulatory developments and governmental actions, including federal, state, local, territorial and foreign laws and regulations may adversely affect our operations and those of our counterparties with whom we have contracted, which may affect our financial results. These actions could result in tax increases retroactively through tax claims or prospectively through changes to applicable statutory tax rates, modification of the tax base, or imposition of new tax types. Additionally, governmental actions could include 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; expropriation or nationalization of property; mandatory government participation, cancellation or amendment of contract rights; imposition of capital controls or blocking of funds; changes in import and export regulations; the imposition of tariffs; and anti-bribery or anti-corruption laws. In recent years, proposals for limitations on access to oil and gas exploration and development opportunities and related litigation have grown in certain areas and may include efforts to reduce access to public and private lands; restriction of exploration and production activities within government-owned and other lands; delaying or canceling permits for drilling or pipeline construction; restrictions or changes to existing pipeline easements; limiting or banning industry techniques such as hydraulic fracturing and/or adding restrictions on the use of water and associated disposal; imposition of set-backs on oil and gas sites; reduction of sulfur content in bunker fuel; delaying or denying air-quality or siting permits; advocating for increased regulations, punitive taxation, or citizen ballot initiatives or moratoriums on industry activity; and the use of social media channels to cause reputational harm. Costs associated with responding to these anti-development efforts or complying with any new legal or regulatory requirements could significantly and adversely affect our business, financial condition and results of operations.
Political instability in areas where we operate can adversely affect our business. Some of the international areas in which we operate are politically less stable than other areas and may be subject to civil unrest, conflict, insurgency, corruption, security risks and labor unrest. Political instability and civil unrest in North Africa, South America and the Middle East has affected and may continue to affect our interests in these areas as well as oil and gas markets generally. In addition, geographic territorial border disputes may affect our business in certain areas, such as the border dispute between Guyana and Venezuela over a portion of the Stabroek Block. Political instability exposes our operations to increased risks, including increased difficulty in obtaining required permits and government approvals, enforcing our agreements in those jurisdictions and potential adverse actions by local government authorities. The threat of terrorism around the world also poses additional risks to our operations and the operations of the oil and gas industry in general.
One of our subsidiaries is the general partner of a publicly traded limited partnership, Hess Midstream LP. The responsibilities associated with being a general partner expose us to a broader range of legal liabilities. Our control of Hess Midstream LP bestows upon us additional duties and obligations including, but not limited to, the obligations associated with managing potential conflicts of interests and additional reporting requirements from the Securities and Exchange Commission. These heightened duties expose us to additional potential for legal claims that may have a material negative economic impact on our stockholders. Moreover, these increased duties may lead to an increase in compliance costs.
Item 1B.  Unresolved Staff Comments
None.
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Item 3.  Legal Proceedings
We are subject to loss contingencies with respect to various claims, lawsuits and other proceedings. A liability is recognized in our consolidated financial statements when it is probable that a loss has been incurred and the amount can be reasonably estimated. If the risk of loss is probable, but the amount cannot be reasonably estimated or the risk of loss is only reasonably possible, a liability is not accrued; however, we disclose the nature of those contingencies. We cannot predict with certainty if, how or when existing claims, lawsuits and proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages.
We, along with many companies that have been or continue to be engaged in refining and marketing of gasoline, have been a party to lawsuits and claims related to the use of MTBE in gasoline. A series of similar lawsuits, many involving water utilities or governmental entities, were filed in jurisdictions across the U.S. against producers of MTBE and petroleum refiners who produced gasoline containing MTBE, including us. The principal allegation in all cases was that gasoline containing MTBE was a defective product and that these producers and refiners are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE. The majority of the cases asserted against us have been settled. There are two remaining active cases, filed by Pennsylvania and Maryland. In June 2014, the Commonwealth of Pennsylvania filed a lawsuit alleging that we and all major oil companies with operations in Pennsylvania, have damaged the groundwater by introducing thereto gasoline with MTBE. The Pennsylvania suit has been forwarded to the existing MTBE multidistrict litigation pending in the Southern District of New York. In December 2017, the State of Maryland filed a lawsuit alleging that we and other major oil companies damaged the groundwater in Maryland by introducing thereto gasoline with MTBE. The suit, filed in Maryland state court, was served on us in January 2018 and has been removed to federal court by the defendants.
In September 2003, we received a directive from the NJDEP to remediate contamination in the sediments of the Lower Passaic River. The NJDEP is also seeking natural resource damages. The directive, insofar as it affects us, relates to alleged releases from a petroleum bulk storage terminal in Newark, New Jersey we previously owned. We and over 70 companies entered into an Administrative Order on Consent with the EPA to study the same contamination; this work remains ongoing. We and other parties settled a cost recovery claim by the State of New Jersey and agreed with the EPA to fund remediation of a portion of the site. On March 4, 2016, the EPA issued a ROD in respect of the lower eight miles of the Lower Passaic River, selecting a remedy that includes bank-to-bank dredging at an estimated cost of $1.38 billion. The ROD does not address the upper nine miles of the Lower Passaic River or the Newark Bay, which may require additional remedial action. In addition, the federal trustees for natural resources have begun a separate assessment of damages to natural resources in the Passaic River. Given that the EPA has not selected a final remedy for the entirety of the Lower Passaic River or the Newark Bay, total remedial costs cannot be reliably estimated at this time. Based on currently known facts and circumstances, we do not believe that this matter will result in a significant liability to us because our former terminal did not store or use contaminants which are of concern in the river sediments and could not have contributed contamination along the river’s length. Further, there are numerous other parties who we expect will bear the cost of remediation and damages.
In March 2014, we received an Administrative Order from the EPA requiring us and 26 other parties to undertake the Remedial Design for the remedy selected by the EPA for the Gowanus Canal Superfund Site in Brooklyn, New York. Our alleged liability derives from our former ownership and operation of a fuel oil terminal and connected shipbuilding and repair facility adjacent to the Canal. The remedy selected by the EPA includes dredging of surface sediments and the placement of a cap over the deeper sediments throughout the Canal and in-situ stabilization of certain contaminated sediments that will remain in place below the cap. The EPA’s original estimate was that this remedy would cost $506 million; however, the ultimate costs that will be incurred in connection with the design and implementation of the remedy remain uncertain. We have complied with the EPA’s March 2014 Administrative Order and contributed funding for the Remedial Design based on an allocation of costs among the parties determined by a third-party expert. In January 2020, we received an additional Administrative Order from the EPA requiring us and several other parties to begin Remedial Action along the uppermost portion of the Canal. We intend to comply with this Administrative Order. The remediation work began in the fourth quarter of 2020. Based on currently known facts and circumstances, we do not believe that this matter will result in a significant liability to us, and the costs will continue to be allocated amongst the parties, as they were for the Remedial Design.
From time to time, we are involved in other judicial and administrative proceedings relating to environmental matters. We periodically receive notices from the EPA that we are a “potential responsible party” under the Superfund legislation with respect to various waste disposal sites. Under this legislation, all potentially responsible parties may be jointly and severally liable. For any site for which we have received such a notice, the EPA’s claims or assertions of liability against us relating to these sites have not been fully developed, or the EPA’s claims have been settled or a settlement is under consideration, in all cases for amounts that are not material. Beginning in 2017, certain states, municipalities and private associations in California, Delaware, Maryland, Rhode Island and South Carolina separately filed lawsuits against oil, gas and coal producers, including us, for alleged damages purportedly caused by climate change. These proceedings include claims for monetary damages and injunctive relief. Beginning in 2013, various parishes in Louisiana filed suit against approximately 100 oil and gas companies, including us, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused
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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.
In August 2020, Fieldwood and related entities filed for bankruptcy relief under Chapter 11 of the U.S. Bankruptcy Code. Fieldwood’s Bankruptcy Plan, which was approved by the U.S. Bankruptcy Court in June 2021, includes the abandonment of certain assets, including seven offshore Gulf of Mexico leases and related facilities in the West Delta Field that were formerly owned by us and sold to a Fieldwood predecessor in 2004, and the discharge of Fieldwood’s obligation to decommission these facilities. As a result, in October 2021 and February 2022, we received decommissioning orders from the BSEE requiring us to decommission certain wells and related facilities located on six of the seven West Delta leases. We expect to receive additional orders covering the remainder of the West Delta decommissioning obligations in the near future and are actively engaged with the BSEE to agree on the scope and timing of decommissioning activities. Our decommissioning obligation derives from our former ownership of the facilities. We are seeking contribution from other parties that owned an interest in the facilities. As of December 31, 2021, we have a liability of $147 million representing total estimated abandonment obligations in the West Delta Field. Potential recoveries from other parties that previously owned an interest in the West Delta Field have not been recognized as of December 31, 2021.
We are also involved in other judicial and administrative proceedings from time to time in addition to the matters described above, including claims related to post-production deductions from royalty payments. We may also be exposed to future decommissioning liabilities for divested assets in the event the current or future owners of facilities previously owned by us are determined to be unable to perform such actions, whether due to bankruptcy or otherwise. We cannot predict with certainty if, how or when such proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages. Numerous issues may need to be resolved, including through potentially lengthy discovery and determination of important factual matters before a loss or range of loss can be reasonably estimated for any proceeding.
Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of lawsuits, claims and proceedings, including the matters disclosed above, is not expected to have a material adverse effect on our financial condition, results of operations or cash flows. However, we could incur judgments, enter into settlements, or revise our opinion regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations in the period in which the amounts are accrued and our cash flows in the period in which the amounts are paid.
Item 4.  Mine Safety Disclosures
None.
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PART II
Item 5.  Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities
Stock Market Information, Holders and Dividends
Our common stock is traded principally on the New York Stock Exchange (ticker symbol: HES).  At January 31, 2022, there were 2,725 stockholders (based on the number of holders of record) who owned a total of 309,745,523 shares of common stock.  In 2021, 2020 and 2019, cash dividends on common stock totaled $1.00 per share per year ($0.25 per quarter).
Performance Graph
Set forth below is a line graph comparing the five-year shareholder returns on a $100 investment in our common stock assuming reinvestment of dividends, against the cumulative total returns for the following:
Standard & Poor’s (S&P) 500 Stock Index, which includes us.
2021 Proxy Peer Group comprising 12 oil and gas peer companies, including us, as disclosed in our 2021 Proxy Statement. In 2021, Cabot Oil & Gas Corporation merged with Cimarex Energy Company to form Coterra Energy, Inc.

Comparison of Five-Year Shareholder Returns
Years Ended December 31,

hes-20211231_g1.jpg
201620172018201920202021
hes-20211231_g2.jpgHess Corporation
$100.00$77.93$67.69$113.54$91.75$130.39
hes-20211231_g3.jpgS&P 500
$100.00$121.82$116.47$153.13$181.29$233.28
hes-20211231_g4.jpgProxy Peer Group
$100.00$101.02$88.84$92.59$60.57$113.53


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Share Repurchase Activities
Our Board of Directors have authorized common stock repurchases of up to $7.5 billion under our stock repurchase plan. There were no share repurchases for the year ended December 31, 2021. Since initiation of the buyback program in August 2013, total shares repurchased through December 31, 2021 amounted to 91.9 million at a total cost of $6.85 billion including transaction fees.
Equity Compensation Plans
Following is information related to our equity compensation plans at December 31, 2021.
Plan CategoryNumber 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 holders2,086,722 (a)$61.15 23,601,465 (b)
Equity compensation plans not approved by security holders—  — —  
(a)This amount includes 2,086,722 shares of common stock issuable upon exercise of outstanding stock options.  This amount excludes 733,586 performance share units (PSUs) for which the number of shares of common stock to be issued may range from 0% to 200% based on our total shareholder return (TSR) relative to the TSR of a predetermined group of peer companies over a three‑year performance period ending December 31 of the year prior to settlement of the grant.  Beginning with the PSUs granted in 2020, the Corporation's TSR is compared to the TSR of a predetermined group of peer companies and the S&P 500 index over the three-year performance period. In addition, this amount also excludes 1,616,316 shares of common stock issued as restricted stock pursuant to our equity compensation plans.
(b)These securities may be awarded as stock options, restricted stock, PSUs or other awards permitted under our equity compensation plan.
See Note 14, Share‑based Compensation in the Notes to Consolidated Financial Statements for further discussion of our equity compensation plans.
Item 6. [Reserved]

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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 Risk Factors under Item 1A.
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, 2020 compared with the year ended December 31, 2019, which can be found in Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2020 Annual Report on Form 10-K, which was filed with the Securities and Exchange Commission on March 1, 2021, 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 primarily in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA), and Malaysia. We conduct exploration activities primarily offshore Guyana, in the U.S. Gulf of Mexico, and offshore Suriname and Canada. 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. The Liza Phase 1 development achieved first production in December 2019, and has a nameplate production capacity of approximately 120,000 gross bopd. The Liza Phase 2 development achieved first production in February 2022, and is expected to reach its production capacity of approximately 220,000 gross bopd later in 2022 as operations are safely brought online. A third development, Payara, was sanctioned in the third quarter of 2020 and is expected to achieve first production in 2024, with production capacity of approximately 220,000 gross bopd. A fourth development, Yellowtail, was submitted to the government of Guyana for approval in the fourth quarter of 2021. Pending government approval and project sanctioning, the project is expected to have a capacity of approximately 250,000 gross bopd with first production anticipated in 2025. We currently plan to have six FPSOs with an aggregate expected production capacity of more than 1 million gross bopd on the Stabroek Block in 2027, and the potential for up to ten FPSOs to develop the current discovered recoverable resource base.
Our Midstream operating segment, which is comprised of Hess Corporation’s approximate 43.5% consolidated ownership interest in Hess Midstream LP at December 31, 2021, 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.
Climate Change, Energy Transition and Our Strategy
We believe climate risks can and should be addressed while at the same time providing safe, affordable and reliable energy necessary to ensure human welfare and global economic development in the context of the United Nations Sustainable Development Goals. The IEA's 2021 World Energy Outlook provides four 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 achieve the IEA's Sustainable Development Scenario, which reflects the major changes that would be required 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 also have an executive led task force to consider our medium and longer term climate strategy.
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In 2021, we announced our new five year GHG reduction targets for 2025, which are to reduce operated Scope 1 and 2 GHG emissions intensity by approximately 44% and methane emissions intensity by approximately 52% from 2017. In January 2022, we announced our plan to reduce routine flaring at Hess operated assets to zero by the end of 2025. Our business planning includes actions we expect to undertake to continue reducing our carbon footprint consistent with our targets. We also conduct annual scenario planning as a methodology to assess our portfolio’s resilience to differing scenarios of energy supply and demand over the longer term, and to inform our understanding of future risks and opportunities in relation to the potential evolution of energy demand, energy mix, the emergence of new technologies, and possible changes by policymakers with respect to greenhouse gas emissions and climate change.
2022 Outlook
Following the startup of the Liza Phase 2 project in February 2022, we repaid the remaining $500 million outstanding under our $1 billion term loan and we announced a 50 percent increase in our quarterly dividend on common stock. Our E&P capital and exploratory expenditures are projected to be approximately $2.6 billion in 2022.  Capital investment for our Midstream operations is expected to be approximately $235 million.  Oil and gas net production in 2022 is forecast to be in the range of 325,000 boepd to 330,000 boepd excluding Libya. For 2022, we have hedged 90,000 bopd with WTI collars with an average monthly floor price of $60 per barrel and an average monthly ceiling price of $100 per barrel, and 60,000 bopd with Brent collars with an average monthly floor price of $65 per barrel and an average monthly ceiling price of $105 per barrel.
Net cash provided by operating activities was $2,890 million in 2021, compared with $1,333 million in 2020, while net cash provided by operating activities before changes in operating assets and liabilities was $2,991 million in 2021 and $1,803 million in 2020.  In 2022, based on current forward strip crude oil prices, we expect cash flow from operating activities and cash and cash equivalents at December 31, 2021 will be sufficient to fund our capital investment program, dividends, and the recent repayment of the remaining $500 million outstanding under our $1 billion term loan. 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.
Consolidated Results
Net income attributable to Hess Corporation was $559 million in 2021 compared with a net loss of $3,093 million in 2020.  Excluding items affecting comparability of earnings between periods summarized on page 32, adjusted net income was $677 million in 2021 compared with an adjusted net loss of $894 million in 2020.  Annual net production averaged 315,000 boepd and 331,000 boepd in 2021 and 2020, respectively.  Total proved reserves were 1,309 million boe and 1,170 million boe at December 31, 2021 and December 31, 2020, respectively.
Significant 2021 Activities
The following is an update of significant E&P activities during 2021:
E&P assets:
In North Dakota, net production from the Bakken shale play averaged 156,000 boepd in 2021 (2020: 193,000 boepd), primarily due to the impact of lower drilling activity caused by a reduction in rig count from six to one during the first half of 2020, lower NGL and natural gas volumes received under percentage of proceeds contracts, curtailed production related to the planned Tioga Gas Plant maintenance turnaround completed in the third quarter of 2021, and the sale of our Little Knife and Murphy Creek nonstrategic acreage interests in the second quarter of 2021, which contributed net production of 2,000 boepd in 2021 (2020: 6,000 boepd). Net oil production was 80,000 bopd in 2021 compared with 107,000 bopd in 2020. NGL and natural gas volumes received under percentage of proceeds contracts were 11,000 boepd in 2021 compared with 21,000 boepd in 2020 as higher realized NGL prices in 2021 reduced the volumes received as consideration for gas processing fees.
Prior to COVID-19, we were operating six rigs in the Bakken, but reduced the rig count to one in May 2020 in response to the sharp decline in crude oil prices. We added a second operated rig in the Bakken in February 2021 and a third operated rig in September 2021. We drilled 63 wells and brought 51 wells on production in 2021, bringing the total operated production wells to 1,599 at December 31, 2021. We forecast net production from the Bakken to be in the range of 160,000 boepd to 165,000 boepd in 2022.
In the Gulf of Mexico, net production averaged 45,000 boepd in 2021 (2020: 56,000 boepd) primarily due to the sale of the Shenzi Field in November 2020. Net production from the Shenzi Field was 9,000 boepd in 2020.
At the Stabroek Block (Hess 30%), offshore Guyana, net production from the Liza Phase 1 development averaged 30,000 bopd in 2021 (2020: 20,000 bopd) following first production in December 2019 from the Liza Destiny FPSO. The Liza
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Destiny has a nameplate production capacity of approximately 120,000 gross bopd and in 2022 its production capacity is expected to increase to more than 140,000 gross bopd following production optimization work.
The Liza Phase 2 development, which was sanctioned in 2019, began producing oil in February 2022 from the Liza Unity FPSO. The Liza Unity is expected to reach its production capacity of approximately 220,000 gross bopd later in 2022 as operations are safely brought online.
For 2022, net production from Guyana is expected to be in the range of 65,000 bopd to 70,000 bopd, reflecting the ramp in production during the year from Liza Phase 2.
The Payara Field development was sanctioned in 2020 and will utilize the Prosperity FPSO, which will have the capacity to produce up to 220,000 gross bopd, with first production expected in 2024. Ten drill centers with a total of 41 wells are planned, including 20 production wells and 21 injection wells.
A fourth development, Yellowtail, was submitted to the government of Guyana for approval in the fourth quarter of 2021. Pending government approval and project sanctioning, the project is expected to have a capacity of 250,000 gross bopd with first production anticipated in 2025.
In addition to the first four developments, planning is underway for additional FPSOs.  The ultimate sizing and order of these potential developments will be a function of further exploration and appraisal drilling.
In 2021, four successful exploration wells and seven successful appraisal wells were drilled on the Stabroek Block.  For 2022, the operator plans to operate six drillships and drill approximately 12 exploration and appraisal wells during the year.
In the Gulf of Thailand, net production from Block A‑18 of the JDA averaged 36,000 boepd in 2021 (2020: 29,000 boepd), including contribution from unitized acreage in Malaysia, while net production from North Malay Basin averaged 25,000 boepd in 2021 (2020: 23,000 boepd).  During 2021, we continued the drilling program at North Malay Basin, and we commenced a multi-year drilling program at JDA in the first half of the year.
We completed the sale of our interests in Denmark in August for net cash consideration of approximately $130 million, after normal closing adjustments. Net production from Denmark was 3,000 boepd in 2021.
The following is an update of significant Midstream activities during 2021:
In March 2021, Hess Midstream completed an underwritten public offering of 6.9 million Class A shares held by Hess and GIP. As a result of this transaction, Hess received net proceeds of $70 million.
In August 2021, HESM Opco repurchased 31.25 million Class B units held by Hess and GIP for $750 million, with Hess receiving net proceeds of $375 million. HESM Opco issued $750 million in aggregate principal amount of 4.250% fixed-rate senior unsecured notes due 2030 in a private offering to finance the repurchase.
In October 2021, Hess Midstream completed an underwritten public offering of approximately 8.6 million Class A shares held by Hess and GIP. As a result of this transaction, Hess received net proceeds of $108 million.
Facility construction for an expansion of the Tioga Gas Plant to 400 mmcfd from 250 mmcfd was completed in 2020. The incremental gas processing capacity was placed in service in the fourth quarter of 2021 following completion of a planned maintenance turnaround which included connecting the expansion and residue NGL takeaway pipelines to the plant. The total processing capacity of 400 mmcfd became available in February 2022.


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Liquidity and Capital and Exploratory Expenditures
At December 31, 2021, cash and cash equivalents were $2,713 million (2020: $1,739 million), consolidated debt was $8,458 million (2020: $8,296 million), and our debt to capitalization ratio (as defined in the credit agreement for our revolving credit facility and the term loan agreement) was 42.3% (2020: 47.5%).  Hess Midstream debt, which is nonrecourse to Hess Corporation, was $2,564 million at December 31, 2021 (2020: $1,910 million).
Capital and exploratory expenditures were as follows (in millions):
 202120202019
E&P Capital and Exploratory Expenditures:   
United States   
North Dakota$522 $661 $1,312 
Offshore and other103 258 471 
Total United States625 919 1,783 
Guyana1,016 743 783 
Malaysia and JDA154 99 109 
Other (a)34 25 68 
E&P Capital and Exploratory Expenditures$1,829 $1,786 $2,743 
Exploration Expenses Charged to Income Included Above:   
United States$90 $91 $105 
International41 17 62 
Total Exploration Expenses Charged to Income included above$131 $108 $167 
Midstream Capital Expenditures:   
Midstream Capital Expenditures (b)$183 $253 $416 
(a)Other includes our interests in Denmark (which were sold in August 2021), Libya and certain non-producing countries.
(b)Excludes equity investments of $33 million in 2019.
In 2022, we project our E&P capital and exploratory expenditures will be approximately $2.6 billion and Midstream capital expenditures to be approximately $235 million.
Consolidated Results of Operations
Results by Segment:
The after-tax income (loss) by major operating activity is summarized below:
 202120202019
 (In millions, except per share amounts)
Net Income (Loss) Attributable to Hess Corporation:   
Exploration and Production$770 $(2,841)$53 
Midstream286 230 144 
Corporate, Interest and Other(497)(482)(605)
Total$559 $(3,093)$(408)
Net Income (Loss) Attributable to Hess Corporation Per Common Share - Diluted (a)$1.81 $(10.15)$(1.37)
(a)Calculated as net income (loss) attributable to Hess Corporation less preferred stock dividends, divided by weighted average number of diluted shares.
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.

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Items Affecting Comparability of Earnings Between Periods:
The following table summarizes items of income (expense) that are included in net income (loss) and affect comparability of earnings between periods.  The items in the table below are explained on pages 37 through 40.
 202120202019
 (In millions)
Items Affecting Comparability of Earnings Between Periods, After Income Taxes:   
Exploration and Production$(118)$(2,198)$63 
Midstream — (16)
Corporate, Interest and Other (1)(174)
Total$(118)$(2,199)$(127)
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 55.  The items in the table below are explained on pages 37 through 40.
 Before Income Taxes
 202120202019
 (In millions)
Gains on asset sales, net$29 $79 $22 
Other, net — (88)
Marketing, including purchased oil and gas (53)(21)
Operating costs and expenses (20)— 
Exploration expenses, including dry holes and lease impairment (153)— 
General and administrative expenses (6)(30)
Impairment and other(147)(2,126)— 
Total Items Affecting Comparability of Earnings Between Periods, Pre-Tax$(118)$(2,279)$(117)
Reconciliations of GAAP and Non-GAAP Measures:
The following table reconciles reported net income (loss) attributable to Hess Corporation and adjusted net income (loss) attributable to Hess Corporation:
 202120202019
 (In millions)
Adjusted Net Income (Loss) Attributable to Hess Corporation:   
Net income (loss) attributable to Hess Corporation$559 $(3,093)$(408)
Less: Total items affecting comparability of earnings between periods, after-tax(118)(2,199)(127)
Adjusted Net Income (Loss) Attributable to Hess Corporation$677 $(894)$(281)
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:
 202120202019
 (In millions)
Net cash provided by operating activities before changes in operating assets and liabilities:   
Net cash provided by (used in) operating activities$2,890 $1,333 $1,642 
Changes in operating assets and liabilities101 470 595 
Net cash provided by (used in) operating activities before changes in operating assets and liabilities$2,991 $1,803 $2,237 
Adjusted net income (loss) attributable to Hess Corporation is a non-GAAP financial measure, which we define as reported net income (loss) attributable to Hess Corporation excluding items identified as affecting comparability of earnings between periods, which are summarized on pages 37 through 40. Management uses adjusted net income (loss) 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
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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 U.S. GAAP net income (loss) 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:
 202120202019
 (In millions)
Revenues and Non-Operating Income   
Sales and other operating revenues$7,473 $4,667 $6,495 
Gains on asset sales, net29 79 22 
Other, net64 31 51 
Total revenues and non-operating income7,566 4,777 6,568 
Costs and Expenses   
Marketing, including purchased oil and gas2,119 1,067 1,849 
Operating costs and expenses965 895 971 
Production and severance taxes172 124 184 
Midstream tariffs1,094 946 722 
Exploration expenses, including dry holes and lease impairment162 351 233 
General and administrative expenses191 206 204 
Depreciation, depletion and amortization1,361 1,915 1,977 
Impairment and other147 2,126 — 
Total costs and expenses6,211 7,630 6,140 
Results of Operations Before Income Taxes1,355 (2,853)428 
Provision (benefit) for income taxes585 (12)375 
Net Income (Loss) Attributable to Hess Corporation$770 $(2,841)$53 
Excluding the E&P items affecting comparability of earnings between periods in the table on page 37, 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.

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Selling Prices: Average worldwide realized crude oil selling prices, including hedging, were 36% higher in 2021 compared with the prior year, primarily due to the increase in Brent and WTI crude oil prices.  In addition, realized worldwide selling prices for NGL increased in 2021 by 174% and worldwide natural gas prices increased in 2021 by 54%, compared with the prior year.  In total, higher realized selling prices improved after-tax results by approximately $1,430 million, compared with 2020.  Our average selling prices were as follows:
 202120202019
Average Selling Prices (a)
Crude Oil - Per Barrel (Including Hedging)   
United States   
North Dakota$55.57 $42.63 $53.19 
Offshore60.09 45.92