UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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,
20182021
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
(Exact name of Registrant as specified in its charter)
DELAWARE
| | 13-4921002
| | | | | | | | | |
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, N.Y. | NY |
| (Zip Code) |
(Address of principal executive offices) | | |
(
Registrant’s telephone number, including area code
is (212)
997-8500)997-8500
Securities registered pursuant to Section 12(b) of the Act:
| | | | | | | | | | | |
| Title of Each Class | Trading Symbol(s) | Name of Each Exchange on Which Registered |
Common Stock | (par value $1.00) | HES | New York Stock Exchange |
| | |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrantRegistrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐ Indicate by check mark if the registrantRegistrant 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 registrantRegistrant 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 registrantRegistrant was required to submit such files). Yes ☑ No ☐Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☑
Indicate by check mark whether the registrantRegistrant 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☐ | Smaller reporting company ☐
| | | |
If an emerging growth company, indicate by check mark if the registrantRegistrant 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
$17,510,000,000,$24,239,000,000, computed using the outstanding
common sharesCommon Stock and closing market price on June
29, 2018,30, 2021, the last business day of the Registrant’s most recently completed second fiscal quarter.
At January 31,
2019,2022, there were
303,034,262309,745,523 shares of Common Stock outstanding.
Part III is incorporated by reference from the Proxy Statement for the
20192022 annual meeting of stockholders.
| | | | | | | | | | | | | | |
| 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”
, the “Company”, “Registrant”, “we”, “us”, “our” and “its” refer to the consolidated business operations of Hess Corporation and its subsidiaries.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain sections in this
This Annual Report on Form 10-K, including information incorporated by reference herein, and those made undercontains “forward-looking statements” within the captions Business and Properties, Management’s Discussion and Analysismeaning of Financial Condition and ResultsSection 27A of Operations and Quantitative and Qualitative Disclosures about Market Risk contain “forward-looking” statements, as defined under the Private Securities Litigation Reform Act of 1995. Generally,1933, as amended, and Section 21E of the wordsSecurities 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 generally 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 related to our operations 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
theseour 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.
Risk factors that could materially impact future actual results are discussed under Item 1A. Risk Factors within this document.
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 or dry well – 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 – Fractionation is theA 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.Field
GHG – 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.
Greenhouse gas.
Gross acreage acres –Acreage in which a working interest is held by the Corporation. Gross well – Awell 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.
MWCC –Marine Well Containment Company.
Net acreage or Net wells – The sum of the fractional working interests owned by usthe Corporation in gross acres or gross wells.NGLs
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. NGLsNGL 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 explorationandproductioncosts each party will bear or the proportion of production each party will receive, as set out in an operating agreement.Production entitlement
Plug and perf completion – The share of gross productionA well completion technique which involves creating perforations in the Corporation is entitled to receive underwell casing that penetrate the terms of a production sharing contract.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.2
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 “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information,”those quantities of crude oil and condensate, NGLsNGL 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 drillparticipate in the drilling for and produceproduction of oil and gas on the relevant acreage and requires the owner to pay a share of the costs of drilling and production operations.3
WWCC –Wild Well Control Company.
Items 1 and 2. Business and Properties
Hess Corporation, incorporated in the State of Delaware in 1920, is a global
Exploration and Production (E&P)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.),
Denmark,Guyana, the Malaysia/Thailand Joint Development Area (JDA)
, and Malaysia.
We conduct exploration activities primarily offshore Guyana, Suriname, Canada and in the U.S. Gulf of Mexico.Mexico, and offshore Suriname and Canada. At the Stabroek Block (Hess 30%), offshore Guyana, we and our partners have participated in twelvediscovered a significant discoveries. resource base and are executing a multi-phased development of the Block. The Liza Phase 1 development
was sanctionedachieved first production in
2017December 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
startupreach its production capacity of approximately 220,000 gross bopd later in
early2022 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
reaching upcapacity of approximately 220,000 gross bopd. A fourth development, Yellowtail, was submitted to
120,000the 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
. The discovered resources with first production anticipated in 2025. We currently plan to datehave six FPSOs with an aggregate expected production capacity of more than 1 million gross bopd on the Stabroek Block are expected to underpinin 2027, and the potential for at least fiveup to ten FPSOs producing more than 750,000 gross bopd by 2025.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 NGLs;NGL; gathering, terminaling, loading and transporting crude oil and NGLs;NGL; storing and terminaling propane, and water handling services primarily in the Bakken and Three Forks Shale playsshale play in the Williston Basin area of North Dakota.SeeItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for further details. Midstreamon page 12. Exploration and Production
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,
20182021 were
$65.55$66.34 per barrel for West Texas Intermediate (WTI)
(2017: $51.19)(2020: $39.77) and
$72.08$68.92 per barrel for Brent
(2017: $54.87)(2020: $43.43). Our total proved developed and undeveloped reserves at December 31 were as follows:
| | Crude Oil & Condensate | | | Natural Gas Liquids | | | Natural Gas | | | Total Barrels of Oil Equivalent (BOE) | |
| | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | |
| | (Millions of bbls) | | | (Millions of bbls) | | | (Millions of mcf) | | | (Millions of bbls) | |
Developed | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
United States | | | 266 | | | | 239 | | | | 85 | | | | 87 | | | | 432 | | | | 526 | | | | 423 | | | | 414 | |
Europe | | | 38 | | | | 45 | | | | — | | | | — | | | | 77 | | | | 80 | | | | 51 | | | | 58 | |
Africa | | | 111 | | | | 112 | | | | — | | | | — | | | | 115 | | | | 117 | | | | 130 | | | | 132 | |
Asia and other | | | 4 | | | | 5 | | | | — | | | | — | | | | 585 | | | | 696 | | | | 102 | | | | 121 | |
| | | 419 | | | | 401 | | | | 85 | | | | 87 | | | | 1,209 | | | | 1,419 | | | | 706 | | | | 725 | |
Undeveloped | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
United States | | | 235 | | | | 194 | | | | 90 | | | | 84 | | | | 381 | | | | 354 | | | | 389 | | | | 337 | |
Europe | | | 1 | | | | 4 | | | | — | | | | — | | | | 1 | | | | 12 | | | | 1 | | | | 6 | |
Africa | | | 15 | | | | 16 | | | | — | | | | — | | | | 13 | | | | 7 | | | | 17 | | | | 17 | |
Asia and other (a) | | | 44 | | | | 44 | | | | — | | | | — | | | | 211 | | | | 149 | | | | 79 | | | | 69 | |
| | | 295 | | | | 258 | | | | 90 | | | | 84 | | | | 606 | | | | 522 | | | | 486 | | | | 429 | |
Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
United States | | | 501 | | | | 433 | | | | 175 | | | | 171 | | | | 813 | | | | 880 | | | | 812 | | | | 751 | |
Europe | | | 39 | | | | 49 | | | | — | | | | — | | | | 78 | | | | 92 | | | | 52 | | | | 64 | |
Africa | | | 126 | | | | 128 | | | | — | | | | — | | | | 128 | | | | 124 | | | | 147 | | | | 149 | |
Asia and other (a) | | | 48 | | | | 49 | | | | — | | | | — | | | | 796 | | | | 845 | | | | 181 | | | | 190 | |
| | | 714 | | | | 659 | | | | 175 | | | | 171 | | | | 1,815 | | | | 1,941 | | | | 1,192 | | | | 1,154 | |
(a)
| Asia and other includes proved undeveloped reserves in Guyana of 42 million boe at December 31, 2018 (2017: 45 million boe).
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Crude Oil & Condensate | | Natural Gas Liquids | | Natural Gas | | Total Barrels of Oil Equivalent (BOE) |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | | | | | | | | | |
| | (Millions of bbls) | | (Millions of bbls) | | (Millions of mcf) | | (Millions of bbls) |
| Developed | | | | | | | | | | | | | | | |
| United States | 283 | | | 282 | | | 138 | | | 120 | | | 568 | | | 490 | | | 516 | | | 484 | |
| Guyana (a) | 65 | | | 72 | | | — | | | — | | | 17 | | | 36 | | | 68 | | | 78 | |
| Malaysia and JDA | 3 | | | 4 | | | — | | | — | | | 394 | | | 543 | | | 69 | | | 94 | |
| Other (b) | 100 | | | 134 | | | — | | | — | | | 98 | | | 165 | | | 116 | | | 162 | |
| | 451 | | | 492 | | | 138 | | | 120 | | | 1,077 | | | 1,234 | | | 769 | | | 818 | |
| Undeveloped | | | | | | | | | | | | | | | |
| United States | 215 | | | 119 | | | 95 | | | 42 | | | 367 | | | 163 | | | 371 | | | 188 | |
| Guyana (a) | 140 | | | 132 | | | — | | | — | | | 31 | | | 47 | | | 145 | | | 140 | |
| Malaysia and JDA | 2 | | | 2 | | | — | | | — | | | 131 | | | 132 | | | 24 | | | 24 | |
| | | | | | | | | | | | | | | |
| | 357 | | | 253 | | | 95 | | | 42 | | | 529 | | | 342 | | | 540 | | | 352 | |
| Total | | | | | | | | | | | | | | | |
| United States | 498 | | | 401 | | | 233 | | | 162 | | | 935 | | | 653 | | | 887 | | | 672 | |
| Guyana (a) | 205 | | | 204 | | | — | | | — | | | 48 | | | 83 | | | 213 | | | 218 | |
| Malaysia and JDA | 5 | | | 6 | | | — | | | — | | | 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,
20182021 on a boe basis
(2017: 37%(2020: 30%). Proved reserves held under production sharing contracts totaled
7%26% of our crude oil reserves and
44%36% of our natural gas reserves at December 31,
2018 (2017: 7%2021 (2020: 28% and
44%48%, respectively).
For additional information regarding our proved oil and gas reserves, see the Supplementary Oil and Gas Data to the Consolidated Financial Statements presented on pages 8289 through 92.98.
Production
Production
Worldwide crude oil,
natural gas liquids,NGL, and natural gas net production was as follows:
| | 2018 | | | 2017 | | | 2016 | |
Crude oil - Thousands of barrels | | | |
United States | | | | | | | | | | | | |
Bakken | | | 27,663 | | | | 24,439 | | | | 24,881 | |
Other Onshore (a) | | | 389 | | | | 2,053 | | | | 3,209 | |
Total Onshore | | | 28,052 | | | | 26,492 | | | | 28,090 | |
Offshore | | | 15,026 | | | | 14,411 | | | | 16,649 | |
Total United States | | | 43,078 | | | | 40,903 | | | | 44,739 | |
Europe | | | | | | | | | | | | |
Norway (a) | | | — | | | | 7,236 | | | | 8,387 | |
Denmark | | | 2,231 | | | | 2,988 | | | | 3,636 | |
| | | 2,231 | | | | 10,224 | | | | 12,023 | |
Africa | | | | | | | | | | | | |
Equatorial Guinea (a) | | | — | | | | 9,201 | | | | 11,898 | |
Libya | | | 6,654 | | | | 3,542 | | | | 387 | |
| | | 6,654 | | | | 12,743 | | | | 12,285 | |
Asia | | | | | | | | | | | | |
JDA | | | 546 | | | | 586 | | | | 616 | |
Malaysia | | | 851 | | | | 289 | | | | 152 | |
| | | 1,397 | | | | 875 | | | | 768 | |
Total | | | 53,360 | | | | 64,745 | | | | 69,815 | |
Natural gas liquids - Thousands of barrels | | | | | | | | | | | | |
United States | | | | | | | | | | | | |
Bakken | | | 10,767 | | | | 10,107 | | | | 9,701 | |
Other Onshore (a) | | | 1,647 | | | | 2,972 | | | | 4,205 | |
Total Onshore | | | 12,414 | | | | 13,079 | | | | 13,906 | |
Offshore | | | 1,703 | | | | 1,733 | | | | 1,724 | |
Total United States | | | 14,117 | | | | 14,812 | | | | 15,630 | |
Europe - Norway (a) | | | — | | | | 340 | | | | 408 | |
Total | | | 14,117 | | | | 15,152 | | | | 16,038 | |
Natural gas - Thousands of mcf | | | |
United States | | | | | | | | | | | | |
Bakken | | | 25,625 | | | | 22,621 | | | | 22,312 | |
Other Onshore (a) | | | 16,167 | | | | 33,478 | | | | 48,597 | |
Total Onshore | | | 41,792 | | | | 56,099 | | | | 70,909 | |
Offshore | | | 24,452 | | | | 20,987 | | | | 23,603 | |
Total United States | | | 66,244 | | | | 77,086 | | | | 94,512 | |
Europe | | | | | | | | | | | | |
Norway (a) | | | — | | | | 6,739 | | | | 8,541 | |
Denmark | | | 2,958 | | | | 5,124 | | | | 7,128 | |
| | | 2,958 | | | | 11,863 | | | | 15,669 | |
Asia and Other | | | | | | | | | | | | |
JDA | | | 68,477 | | | | 73,444 | | | | 68,031 | |
Malaysia (b) | | | 59,995 | | | | 27,225 | | | | 13,151 | |
Other | | | 4,288 | | | | — | | | | — | |
| | | 132,760 | | | | 100,669 | | | | 81,182 | |
Total | | | 201,962 | | | | 189,618 | | | | 191,363 | |
| | | | | | | | | | | | |
Total Barrels of Oil Equivalent (in millions) (a) (b) | | | 101 | | | | 112 | | | | 118 | |
(a)
| In August 2018, the Corporation sold its Utica Assets, onshore U.S. Utica production averaged 9,000 boepd for calendar year 2018 (2017: 19,000 boepd; 2016: 29,000 boepd). In 2017, the Corporation sold its assets in Equatorial Guinea (November), Norway (December), and the Permian, onshore U.S. (August). Permian production averaged 4,000 boepd for calendar year 2017 (2016: 7,000 boepd).
|
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
| | | | | |
| Crude oil – Thousands of barrels | |
| United States | | | | | |
| North Dakota | 29,176 | | | 39,047 | | | 34,299 | |
| Offshore (a) | 10,451 | | | 13,961 | | | 16,628 | |
| Total United States | 39,627 | | | 53,008 | | | 50,927 | |
| Guyana | 10,920 | | | 7,457 | | | 67 | |
| | | | | |
| | | | | |
| | | | | |
| Malaysia and JDA | 1,264 | | | 1,287 | | | 1,479 | |
| | | | | |
| | | | | |
| | | | | |
| Other (b) | 7,791 | | | 3,358 | | | 9,161 | |
| Total | 59,602 | | | 65,110 | | | 61,634 | |
(b)
| Includes 6,442 thousand mcf of production for 2018 (2017: 4,256 thousand mcf; 2016: 3,624 thousand mcf) from Block PM301 which is unitized into Block A-18 of the JDA.
|
| | | | | | | | | | | | | | | | | |
| Natural gas liquids – Thousands of barrels | | | | | |
| United States | | | | | |
| North Dakota | 17,889 | | | 20,514 | | | 15,150 | |
| Offshore (a) | 1,517 | | | 1,878 | | | 1,942 | |
| Total United States | 19,406 | | | 22,392 | | | 17,092 | |
| | | | | | | | | | | | | | | | | |
| Natural gas – Thousands of mcf | |
| United States | | | | | |
| North Dakota | 59,013 | | | 65,786 | | | 40,222 | |
| Offshore (a) | 26,276 | | | 27,985 | | | 33,212 | |
| Total United States | 85,289 | | | 93,771 | | | 73,434 | |
| | | | | |
| | | | | |
| Malaysia and JDA | 126,743 | | | 106,618 | | | 128,071 | |
| | | | | |
| | | | | |
| | | | | |
| Other (b) | 3,557 | | | 2,540 | | | 7,144 | |
| Total | 215,589 | | | 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).
At December 31,
2018,2021, our significant E&P assets included the following:
Our production in the U.S. was from
onshore properties, principally in the Bakken
oil shale play in the Williston Basin of North Dakota (Bakken) and from offshore properties in the Gulf of Mexico.
Onshore:
North Dakota:
Bakken: At December 31, 2018,2021, we held approximately 543,000462,000 net acres in the Bakken with varying working interest percentages. During 2018,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 an average of 4.8 rigs,rig in the Bakken in February 2021 and a third operated rig in September 2021. We drilled 121 wells, completed 11863 wells and brought 10451 wells on production in 2021, bringing the total operated production wells to 1,414 by year-end.1,599 at December 31, 2021. During 2018, we transitioned from utilizing sliding sleeve completion designs to plug and perf completions. During 2019,2022, we plan to operate sixthree rigs, drill approximately 17090 wells and bring approximately 16085 wells on production. From 2019, all production wells will use plug and perf completions, which we expect will allow us to increase peak net production to approximately 200,000 boepd by 2021. We forecast net production for full year 2019 to be in the range of 135,000 boepd to 145,000 boepd, compared to production of 117,000 boepd in 2018. Gulf of Mexico: At December 31, 2018,2021, we held approximately 75,00061,000 net developed acres, with our production operations principally at the Baldpate (Hess 50%), Conger (Hess 38%), Hack Wilson (Hess 25%), Llano (Hess 50%), Penn State (Hess 50%), Shenzi (Hess 28%), Stampede (Hess 25%) and Tubular Bells (Hess 57%) Fields.fields. At December 31, 2018,2021, we held approximately 270,000267,000 net undeveloped acres, of which leases covering approximately 37,000105,000 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.
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 Baldpate, Conger, Llano,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 Penn State Fieldswill 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 shut-indrilled 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 a fire at the third-party operated Enchilada platform in November 2017. completion of logging operations.
In 2018, production restarted at the Baldpate, Llano, and Penn State Fields 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 atconfirms the Conger Fielddeeper 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 third quarter. AtKaieteur Block, which is adjacent to the Hess operated Stampede Field, production commenced in January 2018. In 2019, we planStabroek Block, increasing our total participating interest to drill one production well20%. Seismic evaluation and two water injection wells atplanning for the Stampede Field, one production well at the Llano Field, and onenext exploration well at the Esox prospect which, if successful, can be tied back into production facilities at the Tubular Bells Field.Asia
are ongoing.
Malaysia and JDA
Malaysia/Thailand Joint Development Area (JDA): At Production comes from the Carigali Hess operated offshore Block A-18 in the Malaysia/Thailand joint development area in the Gulf of Thailand (Hess(Hess 50%), no drilling is planned for 2019 as contracted volumes are expected. In 2022, the operator plans to be met from the booster compression project that came online in 2016.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 and our 50% interest in Block PM302 located in the North Malay Basin (NMB), offshore Peninsular Malaysia. Production from full-field development commenced in July 2017.JDA. In 2019,2022, we plan to continue the drilling program and development activities.Europe
Denmark: Production comes from our operated interest in the South Arne Field (Hess 62%).activities at NMB. In 2018, we decided to retain our interest in the field after offers received in a previously announced sale process did not meet our value expectations. During 2019,2022, we plan to drill an exploration well on License 06/16, located approximately 19 miles from South Arne.
Africa
five development wells.
Other
Libya: At the onshore Waha concession in Libya, which includes the Defa, Faregh, Gialo, North Gialo and Belhedan Fieldsfields (Hess 8%), net production averaged approximately 20,000 boepd in 2018, 10,0002021, 4,000 boepd in 2017,2020 and 1,00021,000 boepd in 2016.2019. Production was shut-in by the operator for extended periods in 2016between January 2020 and October 2020 due to force majeure caused by civil unrest. The Company’s net investment in Libya was approximately $55 million at December 31, 2018.
Other Non-Producing Countries
Guyana: At the Stabroek Block (Hess 30%), which covers approximately 6.6 million acres offshore Guyana, the operator Esso Exploration and Production Guyana Limited has made twelve significant discoveries to date. The first phase of the Liza Field development, which was sanctioned in 2017, is expected to begin producing oil by early 2020. Phase 1 will use the Liza Destiny FPSO to produce up to 120,000 gross bopd. Drilling of development wells in the Liza Field is continuing, subsea equipment is being prepared for installation, and the topside facilities modules have been installed on the Liza Destiny FPSO in Singapore, which is expected to arrive offshore Guyana in the third quarter of 2019. Preparations are also underway for the installation of subsea umbilicals, risers and flowlines at the Liza Field in the spring of 2019.
Phase 2 of the Liza Field development is expected to start production by mid-2022. Pending government and regulatory approvals, project sanction for Phase 2 is expected by the operator in the first quarter of 2019 and will include a second FPSO vessel designed to produce up to 220,000 gross bopd. Project sanction for a third phase of development at the Payara Field is expected in 2019 with first production expected to start up as early as 2023. In addition to the first three phases, development planning is underway for additional FPSOs. The ultimate sizing and timing will be a function of further exploration and appraisal drilling.
The operator is currently utilizing three drillships on the block. The Stena Carron and the Noble Tom Madden, which arrived in the third quarter of 2018, are involved in exploration and appraisal drilling. The Noble Bob Douglas is drilling development wells for Liza Phase 1. In 2018, the following explorations wells were drilled on the Stabroek Block (in chronological order):
Ranger-1: The well, located approximately 60 miles northwest of the Liza discovery, encountered approximately 230 feet of high-quality, oil-bearing carbonate reservoir.
Pacora-1: The well encountered approximately 65 feet of high-quality, oil-bearing sandstone reservoir, and is located approximately four miles west of the Payara-1 well, which was drilled in 2017. The operator plans to integrate this discovery into the Payara Field development.
Liza-5: The well encountered 77 feet of high-quality, oil-bearing sandstone reservoir and is located approximately six miles northwest of the Liza-1 well, which was drilled in 2016.
Sorubim-1: The well did not encounter commercial quantities of hydrocarbons.
Longtail-1: The well encountered approximately 256 feet of high-quality, oil-bearing sandstone reservoir and is located approximately five miles west of the Turbot-1 well, which was drilled in 2017.
Hammerhead-1: The well encountered approximately 197 feet of high-quality, oil-bearing sandstone reservoir and is located approximately 13 miles to the southwest of the Liza-1 well.
Pluma-1: The well encountered approximately 121 feet of high-quality, hydrocarbon-bearing sandstone reservoir and represents the tenth discovery on the Block. The well is located approximately 17 miles south of the Turbot-1 well.
In February 2019, the operator announced the eleventh and twelfth discoveries on the Stabroek Block at the Tilapia-1 and Haimara-1 wells. The Tilapia-1 well encountered approximately 305 feet of high-quality, oil-bearing sandstone reservoir, and is located approximately three miles west of the Longtail-1 well. The Haimara-1 well encountered approximately 207 feet of high-quality, gas condensate-bearing sandstone reservoir, and is located approximately 19 miles east of the Pluma-1 well.
In 2019, additional drilling is planned, including appraisal of the Hammerhead, Ranger and Turbot discoveries, as well as a wider exploration program that will target additional prospects and play types on the block.
In 2018, we acquired a participating interest in the Kaieteur Block (Hess 15%), which is adjacent to the Stabroek Block. The operator, Esso Exploration and Production Guyana Limited, expects to complete a 2D seismic shoot in 2019.
Suriname:Suriname: We hold a 33% non-operated participating interest inBlock 42, offshore Suriname. In 2018, theThe operator, Kosmos Energy Ltd., completed drilling operations on the Pontoenoe-1a subsidiary of Royal Dutch Shell plc, plans to drill one exploration well. Commercial quantities of hydrocarbons were not discoveredwell in 2022 and one exploration well results will be integrated into the ongoing evaluation for future exploration on the block.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. commenced, is interpreting recently acquired 2D seismic and has completed the acquisition of a 3D seismic program in 2018.
survey.
Canada: We hold a 50%25% non-operated participating interest in fourthree exploration licenses offshore Nova Scotia.Newfoundland. In 2018,2023, the operator, BP Canada, completed drilling of the Aspyplans to drill one exploration well, which did not encounter commercial quantities of hydrocarbons. In January 2019, the partnership relinquished 50% of the Nova Scotia acreage in accordance with the license agreement timeline. The retained acreage of approximately 1.75 million gross acres remains under evaluation. We also hold a 25% participating interest in three BP Canada operated exploration licenses offshore Newfoundland.well.
Sales Commitments
We have certain long-term contracts with fixed minimum sales volume commitments for natural gas and
NGLsNGL production. At the JDA in the Gulf of Thailand, we have annual minimum net sales commitments of approximately
8070 billion cubic feet of natural gas per year through 2025 and approximately
4030 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
950520 billion cubic feet of natural gas. We also have
NGLsmultiple minimum delivery commitments
primarily in the Bakken
for natural gas and NGL with various end dates up through
2023,2032, with total commitments of approximately
1090 million
barrels per year, or approximately 55 million barrelsboe 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,
andas well as projected third-party
supply.supply in the case of NGL.
Selling Prices and Production Costs
The following table presents our average selling prices and average production costs:
| | 2018 | | | 2017 | | | 2016 | |
Average selling prices (a) | | | | | | | | | | | | |
Crude oil - per barrel (including hedging) | | | | | | | | | | | | |
United States | | | | | | | | | | | | |
Onshore | | $ | 56.90 | | | $ | 46.04 | | | $ | 36.92 | |
Offshore | | | 62.02 | | | | 47.34 | | | | 37.47 | |
Total United States | | | 58.69 | | | | 46.50 | | | | 37.13 | |
Europe (b) | | | 70.08 | | | | 55.03 | | | | 43.33 | |
Africa | | | 69.64 | | | | 53.17 | | | | 41.88 | |
Asia | | | 70.42 | | | | 56.99 | | | | 42.98 | |
Worldwide | | | 60.77 | | | | 49.23 | | | | 39.20 | |
Crude oil - per barrel (excluding hedging) | | | | | | | | | | | | |
United States | | | | | | | | | | | | |
Onshore | | $ | 60.64 | | | $ | 46.76 | | | $ | 36.92 | |
Offshore | | | 65.73 | | | | 48.15 | | | | 37.47 | |
Total United States | | | 62.41 | | | | 47.25 | | | | 37.13 | |
Europe (b) | | | 70.08 | | | | 55.14 | | | | 43.33 | |
Africa | | | 69.64 | | | | 53.25 | | | | 41.88 | |
Asia | | | 70.42 | | | | 56.99 | | | | 42.98 | |
Worldwide | | | 63.80 | | | | 49.75 | | | | 39.20 | |
Natural gas liquids - per barrel | | | | | | | | | | | | |
United States | | | | | | | | | | | | |
Onshore | | $ | 21.29 | | | $ | 17.67 | | | $ | 9.18 | |
Offshore | | | 25.58 | | | | 21.34 | | | | 13.96 | |
Total United States | | | 21.81 | | | | 18.10 | | | | 9.71 | |
Europe (b) | | | — | | | | 29.04 | | | | 19.48 | |
Worldwide | | | 21.81 | | | | 18.35 | | | | 9.95 | |
Natural gas - per mcf | | | | | | | | | | | | |
United States | | | | | | | | | | | | |
Onshore | | $ | 2.29 | | | $ | 1.96 | | | $ | 1.48 | |
Offshore | | | 2.68 | | | | 2.22 | | | | 1.99 | |
Total United States | | | 2.43 | | | | 2.03 | | | | 1.61 | |
Europe (b) | | | 3.61 | | | | 4.42 | | | | 3.97 | |
Asia and other | | | 5.07 | | | | 4.27 | | | | 5.31 | |
Worldwide | | | 4.18 | | | | 3.37 | | | | 3.37 | |
Average production (lifting) costs per barrel of oil equivalent produced (c) | | | | | | | | | | | | |
United States | | | | | | | | | | | | |
Onshore (d) | | $ | 22.34 | | | $ | 19.64 | | | $ | 18.40 | |
Offshore | | | 13.80 | | | | 11.89 | | | | 18.88 | |
Total United States | | | 19.74 | | | | 17.42 | | | | 18.54 | |
Europe (b) | | | 26.23 | | | | 21.95 | | | | 21.28 | |
Africa | | | 4.42 | | | | 14.40 | | | | 20.53 | |
Asia and other | | | 6.16 | | | | 7.83 | | | | 11.91 | |
Worldwide | | | 15.73 | | | | 16.07 | | | | 18.29 | |
(a)
| Includes inter‑company transfers valued at approximate market prices, primarily onshore U.S., which include certain processing and distribution fees.
|
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
| Average Selling Prices (a) | | | | | |
| Crude Oil - Per Barrel (Including Hedging) | | | | | |
| United States | | | | | |
| North Dakota | $ | 55.57 | | | $ | 42.63 | | | $ | 53.19 | |
| Offshore | 60.09 | | | 45.92 | | | 59.18 | |
| Total United States | 56.64 | | | 43.56 | | | 55.15 | |
| Guyana | 68.57 | | | 46.41 | | | — | |
| Malaysia and JDA | 71.00 | | | 37.91 | | | 61.81 | |
| Other (b) | 66.39 | | | 51.37 | | | 65.22 | |
| Worldwide | 60.08 | | | 44.28 | | | 56.77 | |
| | | | | |
| Crude Oil - Per Barrel (Excluding Hedging) | | | | | |
| United States | | | | | |
| North Dakota | $ | 59.90 | | | $ | 33.87 | | | $ | 53.18 | |
| Offshore | 64.77 | | | 36.55 | | | 59.17 | |
| Total United States | 61.05 | | | 34.63 | | | 55.14 | |
| Guyana | 71.07 | | | 37.40 | | | — | |
| Malaysia and JDA | 71.00 | | | 37.91 | | | 61.81 | |
| Other (b) | 69.25 | | | 43.42 | | | 65.22 | |
| Worldwide | 63.90 | | | 35.52 | | | 56.76 | |
| | | | | |
| Natural Gas Liquids - Per Barrel | | | | | |
| United States | | | | | |
| North Dakota | $ | 30.74 | | | $ | 11.29 | | | $ | 13.20 | |
| Offshore | 26.40 | | | 8.94 | | | 13.31 | |
| Worldwide | 30.40 | | | 11.10 | | | 13.21 | |
| | | | | |
| Natural Gas - Per Mcf | | | | | |
| United States | | | | | |
| North Dakota | $ | 4.08 | | | $ | 1.27 | | | $ | 1.59 | |
| Offshore | 3.25 | | | 1.23 | | | 2.12 | |
| Total United States | 3.82 | | | 1.26 | | | 1.83 | |
| Malaysia and JDA | 5.15 | | | 4.47 | | | 5.04 | |
| Other (b) | 3.40 | | | 3.41 | | | 4.63 | |
| Worldwide | 4.60 | | | 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 | |
| Offshore | 12.88 | | | 11.27 | | | 11.27 | |
| Total United States | 23.27 | | | 16.59 | | | 17.66 | |
| Guyana (e) | 17.93 | | | 18.25 | | | — | |
| Malaysia and JDA | 4.72 | | | 5.77 | | | 6.07 | |
| Other (b) | 6.34 | | | 22.78 | | | 8.87 | |
| Worldwide | 17.91 | | | 15.19 | | | 14.93 | |
(b)
| In 2017, we sold our assets in Norway. See Note 3, Dispositions in the Notes to Consolidated Financial Statements. The average selling prices in Norway for 2016 were $43.32 per barrel for crude oil (including hedging), $43.32 per barrel for crude oil (excluding hedging), $19.48 per barrel for NGLs and $5.22 per mcf for natural gas. The average production (lifting) costs in Norway were $24.70 per boe in 2016.
|
(a)Includes intercompany transfers valued at approximate market prices, primarily onshore U.S., which include certain processing and distribution fees.(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.
|
(b)Other includes our interests in Denmark, which were sold in August 2021, and Libya.(d)
| Includes Midstream tariff expense of $13.69 per boe in 2018 (2017: $11.10 per boe; 2016: $9.24 per boe).
|
(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).
Gross and Net Undeveloped Acreage
At December 31,
2018,2021, gross and net undeveloped acreage amounted to:
| | Undeveloped | |
| | Acreage (a) | |
| | Gross | | | Net | |
| | (In thousands) | |
United States | | | 436 | | | | 383 | |
South America | | | 14,332 | | | | 3,943 | |
Europe | | | 169 | | | | 91 | |
Africa | | | 3,334 | | | | 272 | |
Asia and other (b) | | | 6,350 | | | | 2,755 | |
Total (c) | | | 24,621 | | | | 7,444 | |
(a)
| Includes acreage held under production sharing contracts.
|
| | | | | | | | | | | |
| Undeveloped
Acreage (a) |
| | | |
| | Gross | | Net |
| | | |
| | (In thousands) |
| United States | 333 | | | 279 | |
| Guyana | 9,873 | | | 2,628 | |
| Malaysia and JDA | 197 | | | 98 | |
| Libya | 3,334 | | | 272 | |
| Canada | 3,405 | | | 1,283 | |
| Suriname | 4,363 | | | 1,454 | |
| Total (b) | 21,505 | | | 6,014 | |
(b)
| Includes 5.1 million gross acres (2.1 million net acres) offshore Canada.
|
(a)Includes acreage held under production sharing contracts.(c)
| At December 31, 2018, 26% of our net undeveloped acreage is scheduled to expire during the next three years pending results of exploration activities. In addition, we relinquished 1.75 million gross acres (0.9 million net acres) offshore Nova Scotia, Canada in January 2019.
|
(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,
20182021 gross and net developed acreage and productive wells amounted to:
| | Developed Acreage | | | | | | | | | | | | | | | | | |
| | Applicable to | | | Productive Wells (a) | |
| | Productive Wells | | | Oil | | | Gas | |
| | Gross | | | Net | | | Gross | | | Net | | | Gross | | | Net | |
| | (In thousands) | | | | | | | | | | | | | | | | | |
United States | | | 953 | | | | 554 | | | | 2,693 | | | | 1,281 | | | | 29 | | | | 21 | |
Europe | | | 23 | | | | 14 | | | | 19 | | | | 12 | | | | — | | | | — | |
Africa | | | 9,564 | | | | 782 | | | | 1,032 | | | | 84 | | | | 9 | | | | 1 | |
Asia and other | | | 452 | | | | 226 | | | | — | | | | — | | | | 118 | | | | 60 | |
Total | | | 10,992 | | | | 1,576 | | | | 3,744 | | | | 1,377 | | | | 156 | | | | 82 | |
(a)
| Includes multiple completion wells (wells producing from different formations in the same bore hole) totaling 105 gross wells and 61 net wells.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Developed Acreage Applicable to Productive Wells | | Productive Wells (a) |
| | | Oil | | Gas |
| | Gross | | Net | | Gross | | Net | | Gross | | Net |
| | | | | | | | | | | |
| | (In thousands) | | | | | | | | |
| United States | 839 | | | 512 | | | 2,887 | | | 1,358 | | | 11 | | | 5 | |
| Guyana | 95 | | | 29 | | | 6 | | | 2 | | | — | | | — | |
| Malaysia and JDA | 491 | | | 245 | | | — | | | — | | | 121 | | | 58 | |
| Libya | 9,564 | | | 782 | | | 1,134 | | | 93 | | | 10 | | | 1 | |
| Total | 10,989 | | | 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 Wells | | | Net Development Wells | |
| 2018 | | | 2017 | | | 2016 | | | 2018 | | | 2017 | | | 2016 | |
Productive wells | | | | | | | | | | | | | | | | | | | | | | | |
United States | | — | | | | — | | | | — | | | | 92 | | | | 65 | | | | 83 | |
Europe | | — | | | | — | | | | — | | | | — | | | | 1 | | | | 1 | |
Asia and other | | 4 | | | | 2 | | | | 1 | | | | 1 | | | | 1 | | | | — | |
| | 4 | | | | 2 | | | | 1 | | | | 93 | | | | 67 | | | | 84 | |
Dry holes | | | | | | | | | | | | | | | | | | | | | | | |
United States | | — | | | | — | | | | 1 | | | | — | | | | — | | | | — | |
Africa (a) | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
Asia and other (b) | | 2 | | | | — | | | | 1 | | | | — | | | | — | | | | — | |
| | 2 | | | | — | | | | 2 | | | | — | | | | — | | | | — | |
Total | | 6 | | | | 2 | | | | 3 | | | | 93 | | | | 67 | | | | 84 | |
(a)
| In 2017, we expensed seven wells in our Deepwater Tano/Cape Three Points Block, offshore Ghana, which were drilled in prior years.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Net Exploratory Wells | | Net Development Wells |
| | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
| Productive wells | | | | | | | | | | | |
| United States | — | | — | | — | | 48 | | 98 | | 140 | |
| Guyana | 3 | | 1 | | 2 | | 3 | | — | | 2 | |
| Malaysia and JDA | — | | — | | — | | 2 | | 3 | | 3 | |
| Libya | — | | — | | — | | 1 | | — | | 2 | |
| | 3 | | | 1 | | | 2 | | | 54 | | | 101 | | | 147 | |
| Dry holes | | | | | | | | | | | |
| United States | — | | | 1 | | | — | | | — | | | — | | | — | |
| Guyana (a) | — | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | |
| Denmark | — | | | — | | | 1 | | | — | | | — | | | — | |
| | — | | | 1 | | | 1 | | | — | | | — | | | — | |
| Total | 3 | | | 2 | | | 3 | | | 54 | | | 101 | | | 147 | |
(b)
| In 2016, we expensed 18 wells relating to our Equus natural gas project, offshore Australia, which were drilled in prior years.
|
(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.
Number of Wells in the Process of Being Drilled
At December 31, 2018,2021, the number of wells in the process of drilling amounted to:
| | Gross | | | Net | | | | | | | | | | | |
| | Wells | | | Wells | | | Gross
Wells | | Net
Wells |
United States | | | 112 | | | | 35 | | United States | 115 | | | 20 | |
Asia and other | | | 11 | | | | 4 | | |
| Guyana (a) | | Guyana (a) | 15 | | | 5 | |
| Malaysia and JDA | | Malaysia and JDA | 6 | | | 3 | |
| Total | | | 123 | | | | 39 | | Total | 136 | | | 28 | |
(a)Includes five gross (and two net) water injection and gas injection wells in process at December 31, 2021.
Prior to December 16, 2019, the Midstream operating segment provides fee-based services, including gathering, compressing and processing natural gas and fractionating NGLs; gathering, terminaling, loading and transporting crude oil and NGLs; storing and terminaling propane, and water handling serviceswas primarily in the Bakken and Three Forks Shale plays in the Williston Basin areacomprised of North Dakota. In July 2015, we sold a 50% interest in Hess Infrastructure Partners LP (HIP) to, 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 net cash consideration of approximately $2.6 billion. Inbillion on July 1, 2015.
On April
10, 2017,
Hess Midstream Partners LP (the “Partnership”), sold 16,997,000 common units representing limited partner interests at a price of $23 per unit inHIP 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,million. In connection with the IPO, HIP contributed a 20% controlling economic interest in each of
which $350 million was distributed equally to Hess
CorporationNorth Dakota Pipeline Operations LP, Hess TGP Operations LP, and
GIP. At December 31, 2018, Hess CorporationNorth 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 ownedreceived common and subordinated units representing a direct 33.75% limited partner interest in the PartnershipHess Midstream Partners and a 50% indirect ownership interest through HIP in the Partnership’sHess Midstream Partners’ general partner, which hashad a 2% economic interest in the PartnershipHess Midstream Partners plus incentive distribution rights. The public unit holders own a 30.5% limited
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
Partnership. In turn,new publicly listed entity. As consideration for the
Partnership ownsacquisition, 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
approximate 20% controlling interest in the operating companies that comprise our midstream joint venture, while HIP, the 50/50 joint venture betweenas-exchanged basis and Hess
Corporation and GIP
ownseach owned 47% of the
remaining 80%. The Partnership, HIP and its affiliates, and other minor water handling services wholly-ownedconsolidated 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
compriseand GIP. These Class A shares of Hess Midstream were obtained by Hess and GIP through the
Midstream operating segment, which currently generates substantially allexchange of
its revenues under long-term, fee-based agreements with our E&P operating segment but intends to pursue additional throughput volumes from third-parties in the Williston Basin area. We operate the Midstream assets under various operational6.9 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 administrative services agreements. In December 2018, we entered into a MemorandumGIP for $750 million. Hess received net proceeds of Understanding with HIP to sell HIP our water handling business for $225$375 million. HESM Opco issued $750 million in cash, subjectaggregate principal amount of 4.250% fixed-rate senior unsecured notes due 2030 in a private offering to customary adjustments. The parties expectfinance 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 execute definitive agreementsthe above transactions in 2021, public shareholders of Class A shares of Hess Midstream own approximately 13%, and closeHess and GIP each own approximately 43.5%, of the transaction in the first quarter of 2019, subject to receipt of regulatory approvals.consolidated entity on an as-exchanged basis at December 31, 2021.
At December 31, 2018,2021, 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 1,2001,350 miles of high and low pressure natural gas and NGL gathering pipelines with a current capacity of up to approximately 370450 mmcfd, including an aggregate compression capacity of approximately 190325 mmcfd. The system also includes the Hawkeye Gas Facility, which contributes approximately 50 mmcfd of the system’s current compression capacity.
•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 400550 miles of crude oil gathering pipelines with a current capacity of up to approximately 160,000240,000 bopd. The system also includes the Hawkeye Oil Facility, which contributes approximately 75,000 bopd of the system’s current capacity.
•Tioga Gas Plant: A natural gas processing and fractionation plant located in Tioga, North Dakota, with a current processing capacity of approximately 250400 mmcfd, and cryogenic and fractionation capacity of approximately 60,00080,000 boepd.
•Little Missouri 4:A natural gas processing plant under construction in McKenzie County, North Dakota, with expected processing capacity of approximately 200 mmcfd. The operator,mmcfd, which was placed in service during 2019 and is operated by Targa Resources Corp., estimates the plant will be in service in the second quarter of 2019. The Partnership Hess Midstream LP owns a 50% interest in Little Missouri 4 through a joint venture with Targa Resources Corp. and will beis entitled to half of the plant’s processing capacity when completed.
•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 we operateare 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. In 2018, HIP sold all its remaining older specification crude oil rail cars.
•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-partiesthird 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 assets: Gathering and Disposal:A produced water gathering system located primarily in McKenzie, Williams and Mountrail Counties, North Dakota, consisting ofthat transports produced water from the wellsite by approximately 150270 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, pipelines.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.Other Items
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 Clean Gulf Associates (CGA), Marine Spill Response Corporation (MSRC), Marine Well Containment Company (MWCC), Wild Well Control (WWC), Subsea Well Intervention Service (SWIS)CGA, MSRC, MWCC, WWCC and Oil Spill Response Limited (OSRL).OSRL. CGA and MSRC are domestic spill response organizations
and MWCC provides the equipment and personnel to contain underwater well control incidents in the Gulf of Mexico.
WWCWWCC 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,
9nine 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
CommitteesCommittee 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
as well as the Board of Directors ofand 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
Atlantic Named Windstormwindstorm coverage for which we are
self‑insured,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
$1.11 billion$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
$1.08 billion,$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‑partyThird-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‑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‑partythird-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
joint operating agreement (JOA),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-partiesthird parties in some jurisdictions. Further, under some production sharing contracts between a governmental entity and commercial parties, liability of the commercial parties to the government entity is joint and several.
Government Regulations
The crude oil and natural gas industry is regulated at federal, state, local and foreign government levels. Regulations affecting elements of the energy sector are under continuous review for amendment or expansion over time, which may result in incremental costs of doing business and affect our profitability. See Regulatory, Legal and Environmental Risks
in Item 1A. Risk Factors. Compliance with various existing environmental, health and pollution controlsafety regulations imposed by federal, state, local and foreign governments is not expected to have a material adverse effect on our financial condition or results of operations butoperations. 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.general and may reduce demand for our products. We spent approximately $15$16 million in 20182021 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 environmental 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, mattershealth 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.NumberOperations.
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
EmployeesAt December 31, 2018,2021, we had 1,7081,545 employees globally, as detailed below.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | United States | | Guyana | | Malaysia and JDA | | Libya | | Total |
| Job Category | | | | | | | | | | |
| Executives and Senior Officers | | 31 | | | — | | | 1 | | | — | | | 32 | |
| First and Mid-Level Managers | | 327 | | | — | | | 60 | | | 1 | | | 388 | |
| Professionals | | 699 | | | — | | | 78 | | | 2 | | | 779 | |
| Other | | 343 | | | — | | | 3 | | | — | | | 346 | |
| Total | | 1,400 | | | — | | | 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,
•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) |
| | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
| Job Category | | | | | | | | | | | | |
| Executives and Senior Officers | | 16 | % | | 13 | % | | 16 | % | | 19 | % | | 13 | % | | 13 | % |
| First and Mid-Level Managers | | 23 | % | | 23 | % | | 22 | % | | 20 | % | | 20 | % | | 19 | % |
| Professionals | | 34 | % | | 32 | % | | 31 | % | | 30 | % | | 27 | % | | 26 | % |
| Other | | 19 | % | | 17 | % | | 18 | % | | 16 | % | | 16 | % | | 17 | % |
| Total | | 27 | % | | 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.
Website
Information about our Executive Officers
The following table presents information as of March 1, 2022 regarding executive officers of the Corporation:
| | | | | | | | | | | | | | | | | | | | |
Name | | Age | | Office Held* and Business Experience | | Year Individual Became an Executive Officer |
|
|
|
| John B. Hess | | 67 | | 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. Hill | | 60 | | President and Chief Operating Officer Mr. Hill has been Chief Operating Officer since 2014 and President of the Corporation’s worldwide Exploration and Production business since joining the Corporation in January 2009. Prior to joining the Corporation, Mr. Hill spent 25 years at Royal Dutch Shell and its affiliates in a variety of operations, engineering, technical and managerial roles in Asia-Pacific, Europe and the United States. | | 2009 |
| Timothy B. Goodell | | 64 | | Executive Vice President, General Counsel, Corporate Secretary and Chief Compliance Officer Mr. Goodell has been General Counsel of the Corporation since 2009, Corporate Secretary since 2016, Chief Compliance Officer since 2017 and Executive Vice President since 2020. Prior to joining the Corporation in 2009, he was a partner at the law firm of White & Case, LLP where he spent 25 years. | | 2009 |
| John P. Rielly | | 59 | | Executive Vice President and Chief Financial Officer Mr. Rielly has been Chief Financial Officer of the Corporation since 2004 and Executive Vice President since 2020. Mr. Rielly previously served as Vice President and Controller of the Corporation from 2001 to 2004. Prior to joining the Corporation in 2001, he was a Partner at Ernst & Young, LLP where he was employed for 17 years. | | 2002 |
| Richard Lynch | | 64 | | Senior Vice President, Technology and Services Mr. Lynch has been Senior Vice President, Technology and Services of the Corporation since 2018. Mr. Lynch previously was Senior Vice President Global Developments, Drilling and Completions from 2014. Prior to joining the Corporation in 2014, Mr. Lynch spent over 30 years in well delivery and operations, as well as project and asset management, with BP plc and ARCO. | | 2018 |
| Gerbert Schoonman | | 56 | | Senior Vice President, Global Production Mr. Schoonman has been Senior Vice President, Global Production of the Corporation since January 2020. Since joining the Company in 2011, he served in various operational leadership roles, including as Vice President, Production – Asia Pacific, from January 2011 through August 2012; Vice President, Onshore – Bakken from September 2012 through December 2016; and most recently, as Vice President, Offshore since January 2017. Prior to joining the Corporation, he spent 20 years with Royal Dutch Shell where he served in operational and leadership roles. | | 2020 |
| Andrew Slentz | | 60 | | 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-Yilmaz | | 65 | | 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.
We make available free of charge through our website,
at 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,
and 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.
ItemItem 1A. RiskRisk 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, NGLsNGL 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, NGLsNGL 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 or inability 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, NGLsNGL and natural gas, political conditions and events (including weather, instability, changes in governments, armed conflict, or economic sanctions)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, NGLsNGL 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, NGLsNGL and natural gas. Average benchmark prices for 20182021 were $64.90$68.08 per barrel for WTI (2017: $50.85; 2016: $43.47)(2020: $39.34; 2019: $57.04) and $71.69$70.95 per barrel for Brent (2017: $54.74; 2016: $45.13)(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.If Furthermore, from time to time we failhave entered into, and may in the future enter into or modify, commodity price hedging arrangements to successfully increasemanage 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 reserves,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, production will bewhich has contributed to price volatility and adversely impacted. We own or have access to a finite amount of oilaffected the demand for 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. Reserve replacement can also be achieved through acquisition. Similar risks, however, may be encountered in the production of oil and gas on properties acquired from others. In addition to the technical risks to reserve replacement, replacing reserves and developing future production is also influenced by the pricemarketability of crude oil, and 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 drillingcommercial storage and development activities. Lowermidstream 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
proved reserves, additional asset impairments, and other accounting charges if demand for crude oil, and natural gas prices,and NGL decreases. A sustained extension of the current market environment may havemake 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 effectpart of reducing capital available for exploration and development activity and may render certain development projects uneconomic or delay their completion andthe financial markets may result in negative revisionsa lack of access to existing reserves while increasing drilling and development costscapital, 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
expected economic returns.There are inherent uncertainties in estimating quantitiesour operating results is uncertain. Any impact will depend on future developments and new information that may emerge regarding the severity and duration 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 reservesCOVID-19 and the related future net revenues. In addition, reserve estimates may be subjectactions taken by authorities to downwardcontain it or upward changes based on production performance, purchases or salestreat its impact, all 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 2016, relative to preceding years, resulting in reductions toare beyond our reported proved reserves. In contrast, crude oil prices improved somewhat in 2017 and 2018 resulting in increases to our reported proved reserves. If crude oil prices in 2019 average below prices used to determine proved reserves at December 31, 2018, 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.
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. In either case,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 investment may be adversely affected.We are subject to changing lawsinvestments and regulations and other governmental actions that can significantly and adversely affect our business. Federal, state, local, territorial and foreign laws and regulations relating to tax increases and retroactive tax claims, disallowance of tax credits and deductions, 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, reduction of sulfur content in bunker fuel, the imposition of tariffs, limitations on access to exploration and development opportunities, anti-bribery or anti-corruption laws, as well as other political developments may affect our operations and financial results.
We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all. The exploration, development and production of crude oil and natural gas involves 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, or at all. In addition, a ratings downgrade may require that we issue letters of credit or provide other forms of collateral under certain contractual requirements. Any inability to access capital markets could adversely impact our financial adaptability and our ability to execute our strategy and may also expose us to heightened exposure to credit risk.
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 the operations of the oil and gas industry.
Our oil and gas operations are subject to environmental risks and environmental laws and regulations that can result in significant costs and liabilities. Our oil and gas operations, like those of the industry, 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 laws and regulations. Non‑compliance with these laws and regulations may subject us to administrative, civil or criminal penalties, remedial clean-ups and natural resource damages or 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 and the oil and gas industry in general. 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 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 initiatives may result in significant operational changes and expenditures, reduced demand for our products and adversely affect our business. We recognize that climate change is a global environmental concern. Continuing political and social attention to the issue of climate change has resulted in both existing and pending international agreements and national, regional or local legislation and regulatory measures to limit greenhouse gas 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 greenhouse gases 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 greenhouse gases. Regulatory initiatives to reduce the use of these fuels may reduce demand for crude oil and other hydrocarbons and have an adverse effect on our sales volumes, revenues and margins. The imposition and enforcement of stringent greenhouse gas emissions reduction targets could severely and adversely impact the oil and gas industry and significantly reduce the value of our business. Furthermore, increasing attention to climate change risks has
resulted in governmental investigations, and public and private litigation, which could increase ourincreased costs or otherwise adversely affect our business. For example, in 2017 certain municipalities and private associations in California, Rhode Island, and Maryland separately filed lawsuits against over 30 fossil fuel producers, including us, for alleged damages purportedly caused by climate change.
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. SeeCrude Oil and Natural Gas ReservesinCritical Accounting Policies and EstimatesinItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Catastrophic and other events, whether naturally occurring or man‑made,man-made, may materially affect our operations and financial conditions.condition. Our oil and gas operations are subject to unforeseen occurrences which have affected us from timenumerous risks and hazards inherent to timeoperating in the crude oil and natural gas industry, including catastrophic events, which may damage or destroy assets, interrupt operations, result in personal injury
and have other significant adverse effects.
Examples of catastrophicThese events include
hurricanes,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,
disputescyber-attacks or
cyber‑attacks.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 equipment failures. This may lead to delays and differences between estimated and actual timingoutbreaks of critical events.infectious diseases, such as COVID-19. These delays could impact our future results of operations and cash flows.Departures of key members from our senior management team, and/or 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 depends upon the continued service of key members of our senior management team, who play an important role in developing and implementing our strategy. The departure of key members of senior management or an
An inability to recruitsecure personnel, drilling rigs, equipment, supplies and other required services or to retain adequate numbers of experienced technical and professional personnelkey employees may result in the necessary locations may prevent us from executing our strategy in full or, in part, which could negatively impact our business.material negative economic consequences.
We are dependent on oilfield service companies for items including drilling rigs, equipment, supplies and skilled labor. An inability or significant delay in securing these services, or a high cost thereof, may result in material negative economic consequences. 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. These consequencescost, including as a result of changes to our industry due to COVID-19, which may impact our ability to run our operations and to deliver projects on time with the potential for material negative economic consequences.We manage commodity price In addition, difficulty in recruiting and other risks through our risk management function but such activities may impederetaining adequate numbers of experienced technical personnel could negatively impact our ability to benefit from commodity price increasesdeliver 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 can expose usimplementing our strategy. An inability to similar potential counterparty credit risk as amounts due fromrecruit and retain adequate numbers of experienced technical and professional personnel in the salenecessary locations or the loss or departure of hydrocarbons. Wekey members of senior management may enter into additional commodity price hedging arrangements to protectprevent 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 unableexecuting our strategy in full 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.
One ofpart, which could negatively impact our subsidiaries is the general partner of a publicly traded master limited partnership, Hess Midstream Partners LP. The responsibilities associated with being a general partner expose us to a broader range of legal liabilities. Our control of Hess Midstream Partners LP bestows upon us additional fiduciary duties including, but not limited to, the obligations associated with managing potential conflicts of interests, additional reporting requirements from the Securities and Exchange Commission and the provision of tax information to unit holders of Hess Midstream Partners LP. These heightened
business.
duties expose us to additional potential for legal claims that may have a material negative economic impact on our shareholders. Moreover, these increased duties may lead to an increase in compliance costs.
Disruption, failure or cyber security breaches affecting or targeting computer, telecommunications systems, and infrastructure used by the CompanyCorporation or our business partners may materially impact our business and operations. Computers and telecommunication systems are used to conductan integral part of our exploration, development and production activities and have become an integral partthe activities of our business.business partners. We use these systems to analyze and store financial and operating data and to communicate within our companycorporation 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, aany such disruption, failure or a cyber breach of these operating systems, or of the networks and infrastructure on which they rely 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.
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
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
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
methyl tertiary butyl ether (MTBE)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
threetwo remaining active cases, filed by Pennsylvania
Rhode Island, 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
September 2016, the State of Rhode Island also filed a lawsuit alleging that we and other major oil companies damaged the groundwater in Rhode Island by introducing thereto gasoline with MTBE. The suit filed in Rhode Island is proceeding in Federal court. 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
Federalfederal court by the defendants.
In September 2003, we received a directive from the
New Jersey Department of Environmental Protection (NJDEP)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
Environmental Protection Agency (EPA)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
also agreed with
the EPA to fund remediation of a portion of the site. On March 4, 2016, the EPA issued a
Record of Decision (ROD)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
Federalfederal 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. EPA has estimatedThe EPA’s original estimate was that this remedy willwould cost $506 million; however, the ultimate costs that will be incurred in connection with the design and implementation of the remedy remain uncertain. Our alleged liability derives from our former ownership and operation of a fuel oil terminal and connected ship-building and repair facility adjacent toWe have complied with the Canal. We indicated to EPA that we would comply with theEPA’s March 2014 Administrative Order and are currently contributingcontributed funding for the Remedial Design based on an interim allocation of costs among the parties. Atparties determined by a third-party expert. In January 2020, we received an additional Administrative Order from the sameEPA 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
participatinginvolved in
an allocation process whereby a neutral expert selected by the parties will determine the final shares of the Remedial Design costs to be paid by each of the participants. On September 28, 2017, we received a general notice letterother judicial and offer to settle from the U.S. Environmental Protection Agencyadministrative proceedings relating to Superfund claims for the Ector Drum, Inc. Superfund Site in Odessa, Texas. The EPA and Texas Commission on Environmental Quality (TCEQ) took clean-up and response action at the site commencing in 2014 and concluded in December 2015. The site was determined to have improperly stored industrial waste, including drums with oily liquids. The total clean-up cost incurred by the EPA was approximately $3.5 million. We were invited to negotiate a voluntary settlement for our purported share of the clean-up costs. Our share, if any, is undetermined.
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 certain sites,any site for which we have received such as those discussed above,a notice, the EPA’s claims or assertions of liability against us relating to these sites have not been fully developed. With respect to the remaining sites,developed, or the EPA’s claims have been settled or a proposed settlement is under consideration, in all cases for amounts that are not material. Beginning in 2017, certain states, municipalities and private associations in California, Delaware, Maryland, Rhode Island and South Carolina separately filed lawsuits against oil, gas and coal producers, including us, for alleged damages purportedly caused by climate change. These proceedings include claims for monetary damages and injunctive relief. Beginning in 2013, various parishes in Louisiana filed suit against approximately 100 oil and gas companies, including us, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused
contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. The ultimate impact of thesesuch 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, but isestimates.
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
expected to be material.From time to time, webeen 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
proceedings relatingclaims related to
other environmental matters.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
aforementioned proceedingsmatters 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
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).
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 1312 oil and gas peer companies, including us, as disclosed in our 20182021 Proxy Statement.
In 2021, Cabot Oil & Gas Corporation merged with Cimarex Energy Company to form Coterra Energy, Inc.
Comparison of
Five‑YearFive-Year Shareholder Returns
Years Ended December 31,
Holders
At January 31, 2019, there were 3,100 stockholders (based on the number
| | | | | | | | | | | | | | | | | | | | |
| 2016 | 2017 | 2018 | 2019 | 2020 | 2021 |
 Hess Corporation | $100.00 | $77.93 | $67.69 | $113.54 | $91.75 | $130.39 |
 S&P 500 | $100.00 | $121.82 | $116.47 | $153.13 | $181.29 | $233.28 |
 Proxy Peer Group | $100.00 | $101.02 | $88.84 | $92.59 | $60.57 | $113.53 |
Share Repurchase Activities
Our Board of
holders of record) who owned a total of 303,034,262 shares of common stock.Dividends
In 2018, 2017 and 2016, cash dividends onDirectors have authorized common stock totaled $1.00 perrepurchases of up to $7.5 billion under our stock repurchase plan. There were no share per year ($0.25 per quarter).
Share Repurchase Activities
Our share repurchases activities for the year ended December 31, 2018, were as follows:
2018 | | Total Number of Shares Purchased (a) (b) | | | Average Price Paid per Share (a) | | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (d) | | | Maximum Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs (e) (In millions) | |
January | | | 607,771 | | | $ | 52.30 | | | | 607,771 | | | $ | 998 | |
February | | | 3,670,578 | | | | 45.76 | | | | 3,670,578 | | | | 830 | |
March | | | 3,748,598 | | | | 48.57 | | | | 3,708,888 | | | | 1,650 | |
April (c) | | | 8,039,878 | | | | 58.49 | | | | 8,039,878 | | | | 1,150 | |
May | | | — | | | | — | | | | — | | | | 1,150 | |
June | | | 508,742 | | | | 58.49 | | | | 508,742 | | | | 1,150 | |
July (c) | | | 2,412,545 | | | | 63.98 | | | | 2,412,545 | | | | 950 | |
August | | | 729,203 | | | | 63.97 | | | | 729,203 | | | | 949 | |
September | | | 699,004 | | | | 70.10 | | | | 699,004 | | | | 900 | |
October | | | 505,740 | | | | 63.27 | | | | 505,740 | | | | 868 | |
November | | | 2,130,582 | | | | 56.79 | | | | 2,130,582 | | | | 747 | |
December | | | 2,145,786 | | | | 45.21 | | | | 2,145,786 | | | | 650 | |
Total for 2018 | | | 25,198,427 | | | $ | 54.84 | | | | 25,158,717 | | | | | |
(a)
| Repurchased in open‑market transactions. The average price paid per share was inclusive of transaction fees.
|
(b)
| Includes 39,710 common shares repurchased in March, all of which were subsequently granted to Directors in accordance with the Non-Employee Directors’ Stock Award Plan.
|
(c) In April 2018, we entered into an accelerated share repurchase2021. Since initiation of the buyback program (ASR) with a financial institution to repurchase $500 million of our common stock, in which we received an initial delivery of approximately 8 million shares and upon completion of this transaction in June, we received an additional delivery of approximately 0.5 million shares of our common stock. In July 2018, we entered into an ASR with a financial institution to repurchase $200 million of our common stock, in which we received an initial delivery of approximately 2.4 million shares and upon completion of this transaction in August we received an additional delivery2013, total shares repurchased through December 31, 2021 amounted to 91.9 million at a total cost of approximately 0.7 million shares of our common stock. The$6.85 billion including transaction price for each ASR was determined by the volume-weighted average price of the shares during the term less a negotiated discount.
(d)
| Since initiation of the buyback program in August 2013, total shares repurchased through December 31, 2018 amounted to 91.9 million at a total cost of $6.85 billion including transaction fees.
|
(e)
| In March 2013, we announced that our Board of Directors approved a stock repurchase program that authorized the purchase of common stock up to a value of $4.0 billion. In May 2014, the share repurchase program was increased to $6.5 billion and in March 2018, it was increased further to $7.5 billion.
|
Equity Compensation Plans
Following is information related to our equity compensation plans at December 31,
2018.Plan Category | | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights * | | Weighted Average Exercise Price of Outstanding Options, Warrants and Rights | | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column*) |
Equity compensation plans approved by security holders | | | 5,170,079 | | (a) | | $ | 61.91 | | | | | 19,036,450 | | (b) |
Equity compensation plans not approved by security holders (c) | | | — | | | | | — | | | | | — | | |
(a)
| This amount includes 5,170,079 shares of common stock issuable upon exercise of outstanding stock options. This amount excludes 1,063,118 performance share units (PSU) 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. In addition, this amount also excludes 2,881,204 shares of common stock issued as restricted stock pursuant to our equity compensation plans.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Plan Category | Number of Securities
to be Issued Upon Exercise of Outstanding Options, Warrants and Rights * | | Weighted Average
Exercise Price of
Outstanding Options,
Warrants and Rights | | Number of Securities
Remaining Available
for Future Issuance
Under Equity
Compensation Plans
(Excluding Securities
Reflected in
Column*) |
| Equity compensation plans approved by security holders | 2,086,722 | | (a) | | $ | 61.15 | | | 23,601,465 | | (b) |
| Equity compensation plans not approved by security holders | — | | | | — | | | — | | |
(b)
| These securities may be awarded as stock options, restricted stock, performance share units or other awards permitted under our equity compensation plan.
|
(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.(c)
| We have a Non-Employee Director’s Stock Award Plan pursuant to which each of our non-employee directors received $175,000 in value of our common stock. These awards are made from shares we have purchased in the open market.
|
(b)These securities may be awarded as stock options, restricted stock, PSUs or other awards permitted under our equity compensation plan.See Note 11,14, Share‑based Compensation in the Notes to Consolidated Financial Statements for further discussion of our equity compensation plans.
ItemItem 6.
Selected Financial DataThe following is a five‑year summary of selected financial data that should be read in conjunction with both our Consolidated Financial Statements and Accompanying Notes, and [Reserved]
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included elsewhere in this Annual Report: | | 2018 | | | 2017 | | | 2016 | | | 2015 | | | 2014 | | |
| | (In millions, except per share amounts) | | |
Income Statement Selected Financial Data | | | | | | | | | | | | | | | | | | | | | |
Sales and other operating revenues | | | | | | | | | | | | | | | | | | | | | |
Crude oil (a) | | $ | 4,960 | | | $ | 4,239 | | | $ | 3,639 | | | $ | 5,259 | | | $ | 9,058 | | |
Natural gas liquids (a) | | | 533 | | | | 457 | | | | 264 | | | | 244 | | | | 397 | | |
Natural gas (a) | | | 965 | | | | 750 | | | | 766 | | | | 1,052 | | | | 1,247 | | |
Other operating revenues (b) | | | (135 | ) | | | 20 | | | | 93 | | | | 81 | | | | 35 | | |
Total Sales and other operating revenues | | $ | 6,323 | | | $ | 5,466 | | | $ | 4,762 | | | $ | 6,636 | | | $ | 10,737 | | |
| | | | | | | | | | | | | | | | | | | | | |
Income (loss) from continuing operations | | $ | (115 | ) | | $ | (3,941 | ) | | $ | (6,076 | ) | | $ | (2,959 | ) | | $ | 1,692 | | |
Income (loss) from discontinued operations | | | — | | | | — | | | | — | | | | (48 | ) | | | 682 | | |
Net income (loss) | | $ | (115 | ) | | $ | (3,941 | ) | | $ | (6,076 | ) | | $ | (3,007 | ) | | $ | 2,374 | | |
Less: Net income (loss) attributable to noncontrolling interests | | | 167 | | | | 133 | | | | 56 | | | | 49 | | | | 57 | | |
Net income (loss) attributable to Hess Corporation | | $ | (282 | ) | (d) | $ | (4,074 | ) | (e) | $ | (6,132 | ) | (f) | $ | (3,056 | ) | (g) | $ | 2,317 | | (h) |
| | | | | | | | | | | | | | | | | | | | | |
Net Income (Loss) Attributable to Hess Corporation Per Common Share: |
Basic: | | | | | | | | | | | | | | | | | | | | | |
Continuing operations | | $ | (1.10 | ) | | $ | (13.12 | ) | | $ | (19.92 | ) | | $ | (10.61 | ) | | $ | 5.57 | | |
Discontinued operations | | | — | | | | — | | | | — | | | | (0.17 | ) | | | 2.06 | | |
Net income (loss) per share | | $ | (1.10 | ) | | $ | (13.12 | ) | | $ | (19.92 | ) | | $ | (10.78 | ) | | $ | 7.63 | | |
| | | | | | | | | | | | | | | | | | | | | |
Diluted: | | | | | | | | | | | | | | | | | | | | | |
Continuing operations | | $ | (1.10 | ) | | $ | (13.12 | ) | | $ | (19.92 | ) | | $ | (10.61 | ) | | $ | 5.50 | | |
Discontinued operations | | | — | | | | — | | | | — | | | | (0.17 | ) | | | 2.03 | | |
Net income (loss) per share | | $ | (1.10 | ) | | $ | (13.12 | ) | | $ | (19.92 | ) | | $ | (10.78 | ) | | $ | 7.53 | | |
| | | | | | | | | | | | | | | | | | | | | |
Balance Sheet Selected Financial Data | | | | | | | | | | | | | | | | | | | | | |
Total assets | | $ | 21,433 | | | $ | 23,112 | | | $ | 28,621 | | | $ | 34,157 | | | $ | 38,372 | | |
Total debt (c) | | $ | 6,672 | | | $ | 6,977 | | | $ | 6,806 | | | $ | 6,592 | | | $ | 5,952 | | |
Total equity | | $ | 10,888 | | | $ | 12,354 | | | $ | 15,591 | | | $ | 20,401 | | | $ | 22,320 | | |
| | | | | | | | | | | | | | | | | | | | | |
Dividends Per Share | | | | | | | | | | | | | | | | | | | | | |
Dividends per share of common stock | | $ | 1.00 | | | $ | 1.00 | | | $ | 1.00 | | | $ | 1.00 | | | $ | 1.00 | | |
(a)
| Represents sales of Hess net production and purchased third-party volumes.
|
Form 10-K in Item 8, and the information set forth in Risk Factors under Item 1A.(b)
| Commencing with the adoption of Accounting Standards Codification (ASC) 606, Revenue from Contracts with Customers, using the modified retrospective method effective January 1, 2018, gains (losses) on commodity derivatives are included within Other operating revenue. Prior to January 1, 2018, gains (losses) on commodity derivatives were included within Crude oil revenues. See Note 1, Nature of Operations, Basis of Presentation and Summary of Accounting Policies in the Notes to Consolidated Financial Statements.
|
(c)
| At December 31, 2018 includes debt from our Midstream operating segment of $981 million that is non-recourse to Hess Corporation (2017: $980 million; 2016: $733 million; 2015: $704 million; 2014: $0).
|
(d)
| Includes after-tax charges of $221 million related to exit costs, settlement of legal claims related to a former downstream interest, and a loss from debt extinguishment. These charges were, partially offset by a noncash $91 million income tax benefit primarily relating to intraperiod income tax allocation requirements resulting from changes in fair value of our 2019 crude oil hedging program, and gains totaling $24 million related to asset sales.
|
(e)
| Includes after-tax impairment charges of $2,250 million (Gulf of Mexico and Norway), an after-tax dry hole and lease impairment charge of $280 million (Ghana), a combined after-tax loss of $91 million related to asset sales (Norway, Equatorial Guinea and Permian), and after-tax charges of $52 million primarily for de-designated crude oil hedging contracts and other exit costs.
|
(f)
| Includes noncash charges of $3,749 million to establish valuation allowances on deferred tax assets following a three-year cumulative loss and after-tax charges of $894 million primarily for dry hole and other exploration expenses, loss on debt extinguishment, offshore rig costs, severance, and impairment of older specification rail cars.
|
(g)
| Includes total after-tax charges of $1,943 million, including noncash charges of $1,483 million to write-off all goodwill associated with our Exploration and production operating segment.
|
(h)
| Includes after‑tax income of $1,589 million relating to net gains on asset sales and income from the partial liquidation of last‑in, first‑out (LIFO) inventories, partially offset by after‑tax charges totaling $580 million for dry hole expenses, charges associated with termination of lease contracts, severance and other exit costs, income tax restructuring charges and other charges.
|
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 ItemItem 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read together
in our 2020 Annual Report on Form 10-K, which was filed with the Consolidated Financial StatementsSecurities and the Notes to Consolidated Financial Statements, whichExchange Commission on March 1, 2021, and such comparisons are included in this Form 10-K in Item 8, the information set forth in Risk Factors under Item 1A.incorporated herein by reference.
Hess Corporation
incorporated in the State of Delaware in 1920, is a global
Exploration and Production (E&P)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.),
Denmark,Guyana, the Malaysia/Thailand Joint Development Area (JDA)
, and Malaysia. We conduct exploration activities primarily offshore Guyana,
Suriname, Canada and in the U.S. Gulf of
Mexico.Mexico, and offshore Suriname and Canada. At the Stabroek Block (Hess 30%), offshore Guyana, we
and our partners have
participated in twelvediscovered a significant
discoveries.resource base and are executing a multi-phased development of the Block. The Liza Phase 1 development
was sanctionedachieved first production in
2017December 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
startupreach its production capacity of approximately 220,000 gross bopd later in
early2022 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
reaching up to 120,000capacity of approximately 220,000 gross bopd.
The discovered resourcesA fourth development, Yellowtail, was submitted to
datethe 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
are expected to underpinin 2027, and the potential for
at least fiveup to ten FPSOs
producing more than 750,000 gross bopd by 2025.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 NGLs;NGL; gathering, terminaling, loading and transporting crude oil and NGLs;NGL; storing and terminaling propane, and water handling services primarily in the Bakken and Three Forks Shale playsshale play in the Williston Basin area of North Dakota.In 2018, we completed
Climate Change, Energy Transition and Our Strategy
We believe climate risks can and should be addressed while at the sale of our joint venture interestssame time providing safe, affordable and reliable energy necessary to ensure human welfare and global economic development in the Utica shale playcontext of the United Nations Sustainable Development Goals. The IEA's 2021 World Energy Outlook provides four scenarios of global energy demand in eastern Ohio, onshore U.S.,2040 based on varying levels of global response to climate change. Under all of the IEA scenarios, oil and during 2017natural gas are expected to be needed for decades to come and we soldexpect 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 interestsresource 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 Equatorial Guinea, Norwayoverseeing 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 enhanced oil recoveryenvironmental, health and safety goals. We also have an executive led task force to consider our medium and longer term climate strategy.
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 into zero by the Permian Basin, onshore U.S. These sales, which generated total proceedsend of approximately $3.5 billion, are2025. Our business planning includes actions we expect to undertake to continue reducing our carbon footprint consistent with our strategytargets. We also conduct annual scenario planning as a methodology to high gradeassess our portfolio by divesting lower return, mature assetsportfolio’s resilience to invest in higher return assets, primarily in Guyanadiffering scenarios of energy supply and demand over the Bakken,longer term, and to provide returnsinform our understanding of future risks and opportunities in relation to shareholders. During 2018,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
repurchased $1.38repaid the remaining $500 million outstanding under our $1 billion
ofterm loan and we announced a 50 percent increase in our quarterly dividend on common
stock (2017: $120 million), repaid debt of $633 million, and paid dividends of $345 million. At December 31, 2018, we had cash and cash equivalents of $2.6 billion excluding Midstream.Outlook
We project ourstock. Our E&P capital and exploratory expenditures willare projected to be approximately $2.9$2.6 billion in 2019.2022. Capital investment for our Midstream operations is expected to be approximately $330$235 million. Oil and gas net production in 20192022 is forecast to be in the range of 270,000325,000 boepd to 280,000330,000 boepd excluding Libya, up from 248,000 boepd in 2018, excluding Libya and assets sold. WeLibya. For 2022, we have purchased crude oil put options for calendar year 2019 that establish ahedged 90,000 bopd with WTI collars with an average monthly floor price of $60 per barrel for 95,000 bopd.
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
$1,939$2,890 million in
2018,2021, compared
to $945with $1,333 million in
2017,2020, while
capital expenditures for 2018net cash provided by operating activities before changes in operating assets and
2017 were $2,180liabilities was $2,991 million
in 2021 and
$1,973$1,803 million
respectively. Basedin 2020. In 2022, based on current forward strip crude oil prices,
for 2019, we expect cash flow from operating activities and cash and cash equivalents
existing at December 31,
20182021 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,
through the end of 2019.pursue asset sales, borrow against our committed revolving credit facility, or issue debt or equity securities.
Net
lossincome attributable to Hess Corporation was
$282$559 million in
2018 (2017: $4,074 million; 2016: $6,132 million).2021 compared with a net loss of $3,093 million in 2020. Excluding items affecting comparability of earnings between periods summarized on page
26, the32, adjusted net income was $677 million in 2021 compared with an adjusted net loss
was $176of $894 million in
2018 (2017: $1,401 million; 2016: $1,489 million).2020. Annual
net production averaged
277,000315,000 boepd and 331,000 boepd in
2018 (2017: 306,000 boepd; 2016: 322,000 boepd).2021 and 2020, respectively. Total proved reserves were
1,1921,309 million boe and 1,170 million boe at December 31,
2018 (2017: 1,154 million boe; 2016: 1,109 million boe).
Significant 20182021 Activities
The following is an update of significant E&P activities during
2018:Producing 2021:
E&P assets:
•In North Dakota, net production from the Bakken oil shale play averaged 117,000156,000 boepd (2017: 105,000in 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). During 2018,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 an average of 4.8 rigs,rig in the Bakken in February 2021 and a third operated rig in September 2021. We drilled 121 wells, completed 11863 wells and brought 51 wells on production 104 wells. During 2018, we transitioned from utilizing sliding sleeve completion designs to plug and perf completions. During 2019, we plan to operate six rigs, drill approximately 170 wells and bring approximately 160 wells on production. From 2019, allin 2021, bringing the total operated production wells will use plug and perf completions, which we expect will allow us to increase peak net production to approximately 200,000 boepd by1,599 at December 31, 2021. We forecast net production for full year 2019from the Bakken to be in the range of 135,000160,000 boepd to 145,000 boepd.
165,000 boepd in 2022.•In the Gulf of Mexico, net production averaged 57,00045,000 boepd (2017: 54,000in 2021 (2020: 56,000 boepd). The increase in production was primarily due to the Stampede and Penn State Fields, partially offset bysale of the impact of downtimeShenzi Field in November 2020. Net production from a planned well workover at the Tubular BellsShenzi Field the shutdown at the third-party operated Enchilada platform, and natural field decline. We forecast Gulf of Mexico net production for full year 2019 to bewas 9,000 boepd in the range of 65,000 boepd to 70,000 boepd.
| •
| In the Gulf of Thailand, net production from Block A‑18 of the JDA averaged 36,000 boepd for the year (2017: 37,000 boepd), including contribution from unitized acreage in Malaysia, while net production from North Malay Basin averaged 27,000 boepd for the year (2017: 11,000 boepd). Production from the North Malay Basin full-field development project commenced in July 2017. During 2018 we drilled three production wells at North Malay Basin, and plan to continue the drilling program and development activities in 2019.
|
We forecast Gulf of Thailand net production for full year 2019 to be in the range of 60,000 boepd and 65,000 boepd.
In Denmark, we announced that we decided to retain our interest in the Hess operated offshore South Arne Field after offers received in a previously announced sale process did not meet our value expectations. During 2019, we plan to drill an exploration well on License 06/16, located approximately 19 miles from South Arne.
Other E&P assets:
Offshore Guyana, at•At the Stabroek Block (Hess 30%), the operator, Esso Exploration and Productionoffshore Guyana, Limited progressed the first phase ofnet production from the Liza FieldPhase 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
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 2017.2019, began producing oil in February 2022 from the Liza Unity FPSO. The Liza Phase 1 development, whichUnity is expected to begin producing oil by early 2020 will use the Liza Destiny FPSO to produce up to 120,000reach its production capacity of approximately 220,000 gross bopd. Drilling of development wellsbopd later in the Liza Field is continuing, subsea equipment is being prepared for installation, and the topside facilities modules have been installed on the Liza Destiny FPSO in Singapore, which2022 as operations are safely brought online.
For 2022, net production from Guyana is expected to arrive offshore Guyanabe in the third quarterrange of 2019. Preparations are also underway for65,000 bopd to 70,000 bopd, reflecting the installation of subsea umbilicals, risers and flowlines atramp in production during the year from Liza Field in the spring of 2019.
Phase 2 of the Liza2.
The Payara Field development is expected to start production by mid-2022. Pending government and regulatory approvals, project sanction for Phase 2 is expected by the operatorwas sanctioned in the first quarter of 20192020 and will include a secondutilize the Prosperity FPSO, vessel designedwhich will have the capacity to produce up to 220,000 gross bopd. Project sanction for a third phase of development at the Payara Field is expected in 2019bopd, 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 start up as early as 2023. 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
three phases, developmentfour developments, planning is underway for additional FPSOs. The ultimate sizing and
timingorder of these potential developments will be a function of further exploration and appraisal drilling.
The operator is currently utilizing three drillships on the block. The Stena Carron
In 2021, four successful exploration wells and
the Noble Tom Madden, which arrived in the third quarter of 2018, are involved in exploration andseven successful appraisal
drilling. The Noble Bob Douglas is drilling development wells for Liza Phase 1. In 2018, the following explorations wells were drilled on the Stabroek
Block (in chronological order):Ranger-1: The well, located approximately 60 miles northwest ofBlock. For 2022, the Liza discovery, encountered approximately 230 feet of high-quality, oil-bearing carbonate reservoir.
Pacora-1: The well encountered approximately 65 feet of high-quality, oil-bearing sandstone reservoir, and is located approximately four miles west of the Payara-1 well, which was drilled in 2017. The operator plans to integrate this discovery intooperate six drillships and drill approximately 12 exploration and appraisal wells during the Payara Field development.
Liza-5: The well encountered 77 feetyear.
•In the Gulf of high-quality, oil-bearing sandstone reservoir and is located approximately six miles northwestThailand, net production from Block A‑18 of the Liza-1 well, which was drilledJDA averaged 36,000 boepd in 2016.
Sorubim-1: The well did not encounter commercial quantities of hydrocarbons.
Longtail-1: The well encountered approximately 256 feet of high-quality, oil-bearing sandstone reservoir2021 (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 is located approximately five miles westwe commenced a
multi-year drilling program at JDA in the first half of the Turbot-1 well, whichyear. •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 drilled3,000 boepd in 2017. Hammerhead-1: The well encountered approximately 197 feet of high-quality, oil-bearing sandstone reservoir and is located approximately 13 miles to the southwest of the Liza-1 well.
Pluma-1: The well encountered approximately 121 feet of high-quality, hydrocarbon-bearing sandstone reservoir and represents the tenth discovery on the Block. The well is located approximately 17 miles south of the Turbot-1 well.
In February 2019, the operator announced the eleventh and twelfth discoveries on the Stabroek Block at the Tilapia-1 and Haimara-1 wells. The Tilapia-1 well encountered approximately 305 feet of high-quality, oil-bearing sandstone reservoir, and is located approximately three miles west of the Longtail-1 well. The Haimara-1 well encountered approximately 207 feet of high-quality, gas condensate-bearing sandstone reservoir, and is located approximately 19 miles east of the Pluma-1 well.
At Block 42 (Hess - 33%), offshore Suriname, the operator, Kosmos Energy Ltd., completed drilling operations on the Pontoenoe-1 exploration well. Commercial quantities of hydrocarbons were not discovered and well results will be integrated into the ongoing evaluation for future exploration on the block. Total well costs charged to exploration expenses were $33 million.
In Canada, offshore Nova Scotia (Hess - 50%), the operator, BP Canada, completed drilling of the Aspy exploration well, which did not encounter commercial quantities of hydrocarbons. Total well costs charged to exploration expenses were $120 million.
The following is an update of significant Midstream activities during 2018:
2021: •In December 2018, we entered intoMarch 2021, Hess Midstream completed an underwritten public offering of 6.9 million Class A shares held by Hess and GIP. As a Memorandumresult of Understandingthis 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 HIP to sell HIP our water handling business for $225Hess receiving net proceeds of $375 million. HESM Opco issued $750 million in cash, subjectaggregate principal amount of 4.250% fixed-rate senior unsecured notes due 2030 in a private offering to customary adjustments.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 parties expect to execute definitive agreements and close the transactionincremental gas processing capacity was placed in service in the firstfourth quarter of 2019, subject2021 following completion of a planned maintenance turnaround which included connecting the expansion and residue NGL takeaway pipelines to receiptthe plant. The total processing capacity of regulatory approvals.400 mmcfd became available in February 2022.
Liquidity and Capital and Exploratory Expenditures
In 2018, net cash provided by operating activities was $1,939 million (2017: $945 million; 2016: $795 million).
At December 31,
2018, consolidated2021, cash and cash equivalents were
$2,694$2,713 million
(2017: $4,847(2020: $1,739 million), consolidated debt was
$6,672$8,458 million
(2017: $6,977(2020: $8,296 million), and our
consolidated debt to capitalization ratio
(as defined in the credit agreement for our revolving credit facility and the term loan agreement) was
38.0% (2017: 36.1%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):
| | 2018 | | | 2017 | | | 2016 | |
E&P Capital and Exploratory Expenditures | | | | | | | | | | | | |
United States | | | | | | | | | | | | |
Bakken | | $ | 967 | | | $ | 624 | | | $ | 429 | |
Other Onshore | | | 43 | | | | 30 | | | | 46 | |
Total Onshore | | | 1,010 | | | | 654 | | | | 475 | |
Offshore | | | 368 | | | | 702 | | | | 735 | |
Total United States | | | 1,378 | | | | 1,356 | | | | 1,210 | |
South America | | | 423 | | | | 242 | | | | 144 | |
Europe | | | 8 | | | | 142 | | | | 65 | |
Asia and other | | | 260 | | | | 307 | | | | 452 | |
E&P - Capital and Exploratory Expenditures | | $ | 2,069 | | | $ | 2,047 | | | $ | 1,871 | |
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
| E&P Capital and Exploratory Expenditures: | | | | | |
| United States | | | | | |
| North Dakota | $ | 522 | | | $ | 661 | | | $ | 1,312 | |
| Offshore and other | 103 | | | 258 | | | 471 | |
| Total United States | 625 | | | 919 | | | 1,783 | |
| Guyana | 1,016 | | | 743 | | | 783 | |
| Malaysia and JDA | 154 | | | 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
| | | | | | | | | | | | | | | | | |
| Exploration Expenses Charged to Income Included Above: | | | | | |
| United States | $ | 90 | | | $ | 91 | | | $ | 105 | |
| International | 41 | | | 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 E&P capitalDenmark (which were sold in August 2021), Libya and exploratory expenditures above were: | | 2018 | | | 2017 | | | 2016 | |
United States | | $ | 106 | | | $ | 90 | | | $ | 93 | |
International | | | 54 | | | | 105 | | | | 140 | |
Total Exploration Expenses Charged to Income included above | | $ | 160 | | | $ | 195 | | | $ | 233 | |
| | 2018 | | | 2017 | | | 2016 | |
Midstream Capital Expenditures | | | | | | | | | | | | |
Midstream - Capital Expenditures (a) | | $ | 271 | | | $ | 121 | | | $ | 283 | |
| (a)
| Excludes equity investments of $67 million in 2018.
|
(b)Excludes equity investments of $33 million in 2019.In
2019,2022, we project our E&P capital and exploratory expenditures will be approximately
$2.9 billion.
$2.6 billion and Midstream capital expenditures to be approximately $235 million.
ConsolidatedConsolidated Results of Operations
The after-tax income (loss) by major operating activity is summarized below:
| | 2018 | | | 2017 | | | 2016 | |
| | (In millions, except per share amounts) | |
Net Income (Loss) Attributable to Hess Corporation: | | | | | | | | | | | | |
Exploration and Production | | $ | 51 | | | $ | (3,653 | ) | | $ | (4,964 | ) |
Midstream | | | 120 | | | | 42 | | | | 42 | |
Corporate, Interest and Other | | | (453 | ) | | | (463 | ) | | | (1,210 | ) |
Total | | $ | (282 | ) | | $ | (4,074 | ) | | $ | (6,132 | ) |
| | | | | | | | | | | | |
Net Income (Loss) Attributable to Hess Corporation Per Common Share - Diluted (a) | | $ | (1.10 | ) | | $ | (13.12 | ) | | $ | (19.92 | ) |
(a)
| Calculated as net income (loss) attributable to Hess Corporation less preferred stock dividends, divided by weighted average number of diluted shares.
|
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
| | | | | |
| | (In millions, except per share amounts) |
| Net Income (Loss) Attributable to Hess Corporation: | | | | | |
| Exploration and Production | $ | 770 | | | $ | (2,841) | | | $ | 53 | |
| Midstream | 286 | | | 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.
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 3137 through 35.40.
| | | | | 2021 | | 2020 | | 2019 |
| | 2018 | | | 2017 | | | 2016 | | | | | | | |
| | (In millions) | | | (In millions) |
Items Affecting Comparability of Earnings Between Periods, After Income Taxes: | | | | | | | | | | | | | Items Affecting Comparability of Earnings Between Periods, After Income Taxes: | | | | | |
Exploration and Production | | $ | (86 | ) | | $ | (2,609 | ) | | $ | (3,699 | ) | Exploration and Production | $ | (118) | | | $ | (2,198) | | | $ | 63 | |
Midstream | | | — | | | | (34 | ) | | | (21 | ) | Midstream | — | | | — | | | (16) | |
Corporate, Interest and Other | | | (20 | ) | | | (30 | ) | | | (923 | ) | Corporate, Interest and Other | — | | | (1) | | | (174) | |
Total | | $ | (106 | ) | | $ | (2,673 | ) | | $ | (4,643 | ) | 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 |
| | 2021 | | 2020 | | 2019 |
| | | | | |
| | (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:
| | 2018 | | | 2017 | | | 2016 | | | | | | | | | | | | | | | | |
| | (In millions) | | | 2021 | | 2020 | | 2019 |
| | | | | (In millions) |
| Adjusted Net Income (Loss) Attributable to Hess Corporation: | | Adjusted Net Income (Loss) Attributable to Hess Corporation: | | | | | |
Net income (loss) attributable to Hess Corporation | | $ | (282 | ) | | $ | (4,074 | ) | | $ | (6,132 | ) | Net income (loss) attributable to Hess Corporation | $ | 559 | | | $ | (3,093) | | | $ | (408) | |
Less: Total items affecting comparability of earnings between periods | | | (106 | ) | | | (2,673 | ) | | | (4,643 | ) | |
| Less: Total items affecting comparability of earnings between periods, after-tax | | Less: Total items affecting comparability of earnings between periods, after-tax | (118) | | | (2,199) | | | (127) | |
Adjusted Net Income (Loss) Attributable to Hess Corporation | | $ | (176 | ) | | $ | (1,401 | ) | | $ | (1,489 | ) | 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:
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
| | | | | |
| | (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 liabilities | 101 | | | 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 presented in this report 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.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. This
Net cash provided by (used in) operating activities before changes in operating assets and liabilities presented in this report is a non-GAAP measure, which we define as reported net cash provided by (used in) operating activities excluding changes in operating assets and liabilities. Management uses net cash provided by (used in) operating activities before changes in operating assets and
liabilities to evaluate the Corporation’s ability to internally fund capital expenditures, pay dividends and service debt and believes that investors’ understanding of our ability to generate cash to fund these items is enhanced by disclosing this measure, which excludes working capital and other movements that may distort assessment of our performance between periods.
These measures are not, and should not be viewed as,
a substitutesubstitutes for U.S. GAAP net income (loss)
.
The following table presents the pre-tax amount of items affecting comparability of income (expense) and net cash provided by financial statement line item in the Statement of Consolidated Income on page 48. The items in the table below are explained on pages 31 through 35.
(used in) operating activities. | | Before Income Taxes | |
| | 2018 | | | 2017 | | | 2016 | |
| | (In millions) | |
Total Items Affecting Comparability of Earnings Between Periods, Pre-Tax: | | | | | | | | | | | | |
Sales and other operating revenues | | $ | — | | | $ | (22 | ) | | $ | — | |
Gains (losses) on asset sales, net | | | 24 | | | | (98 | ) | | | 27 | |
Operating costs and expenses | | | (19 | ) | | | — | | | | (164 | ) |
Exploration expenses, including dry holes and lease impairment | | | (3 | ) | | | (280 | ) | | | (1,029 | ) |
General and administrative expenses | | | (130 | ) | | | (11 | ) | | | (1 | ) |
Loss on debt extinguishment | | | (53 | ) | | | — | | | | (148 | ) |
Depreciation, depletion and amortization | | | (16 | ) | | | (19 | ) | | | — | |
Impairment | | | — | | | | (4,203 | ) | | | (67 | ) |
Total | | $ | (197 | ) | | $ | (4,633 | ) | | $ | (1,382 | ) |
Comparison of Results
Exploration and Production
Following is a summarized statement of income for our E&P operations:
| | | | | 2021 | | 2020 | | 2019 |
| | 2018 | | | 2017 | | | 2016 | | | | | | | |
| | (In millions) | | | (In millions) |
Revenues and Non-Operating Income | | | | | | | | | | | | | Revenues and Non-Operating Income | | | | | |
Sales and other operating revenues | | $ | 6,323 | | | $ | 5,460 | | | $ | 4,755 | | Sales and other operating revenues | $ | 7,473 | | | $ | 4,667 | | | $ | 6,495 | |
Gains (losses) on asset sales, net | | | 27 | | | | (39 | ) | | | 27 | | |
| Gains on asset sales, net | | Gains on asset sales, net | 29 | | | 79 | | | 22 | |
Other, net | | | 53 | | | | (1 | ) | | | 16 | | Other, net | 64 | | | 31 | | | 51 | |
Total revenues and non-operating income | | | 6,403 | | | | 5,420 | | | | 4,798 | | Total revenues and non-operating income | 7,566 | | | 4,777 | | | 6,568 | |
Costs and Expenses | | | | | | | | | | | | | Costs and Expenses | | | | | |
Marketing, including purchased oil and gas | | | 1,833 | | | | 1,335 | | | | 1,128 | | Marketing, including purchased oil and gas | 2,119 | | | 1,067 | | | 1,849 | |
Operating costs and expenses | | | 941 | | | | 1,248 | | | | 1,658 | | Operating costs and expenses | 965 | | | 895 | | | 971 | |
Production and severance taxes | | | 171 | | | | 119 | | | | 101 | | Production and severance taxes | 172 | | | 124 | | | 184 | |
Midstream tariffs | | | 648 | | | | 543 | | | | 497 | | Midstream tariffs | 1,094 | | | 946 | | | 722 | |
Exploration expenses, including dry holes and lease impairment | | | 362 | | | | 507 | | | | 1,442 | | Exploration expenses, including dry holes and lease impairment | 162 | | | 351 | | | 233 | |
General and administrative expenses | | | 258 | | | | 224 | | | | 236 | | General and administrative expenses | 191 | | | 206 | | | 204 | |
Depreciation, depletion and amortization | | | 1,748 | | | | 2,736 | | | | 3,113 | | Depreciation, depletion and amortization | 1,361 | | | 1,915 | | | 1,977 | |
Impairment | | | — | | | | 4,203 | | | | — | | |
| Impairment and other | | Impairment and other | 147 | | | 2,126 | | | — | |
Total costs and expenses | | | 5,961 | | | | 10,915 | | | | 8,175 | | Total costs and expenses | 6,211 | | | 7,630 | | | 6,140 | |
Results of Operations Before Income Taxes | | | 442 | | | | (5,495 | ) | | | (3,377 | ) | Results of Operations Before Income Taxes | 1,355 | | | (2,853) | | | 428 | |
Provision (benefit) for income taxes | | | 391 | | | | (1,842 | ) | | | 1,587 | | Provision (benefit) for income taxes | 585 | | | (12) | | | 375 | |
Net Income (Loss) Attributable to Hess Corporation | | $ | 51 | | | $ | (3,653 | ) | | $ | (4,964 | ) | 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
31,37, 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,
depreciation, depletion and amortization,DD&A expense, exploration expenses and income taxes, as discussed below.
Selling Prices:Average worldwide realized crude oil selling prices, including hedging, were 23%36% higher in 20182021 compared towith the prior year, primarily due to the increase in Brent and WTI crude oil prices. In addition, realized worldwide selling prices for NGLsNGL increased in 20182021 by 19%174% and worldwide natural gas prices increased in 20182021 by 24%54%, compared towith the prior year. In total, higher realized selling prices improved 2018 financialafter-tax results by approximately $700$1,430 million, after income taxes, compared with 2017.2020. Our average selling prices were as follows: | | 2018 | | | 2017 | | | 2016 | |
Crude Oil - Per Barrel (Including Hedging) | | | | | | | | | | | | |
United States | | | | | | | | | | | | |
Onshore | | $ | 56.90 | | | $ | 46.04 | | | $ | 36.92 | |
Offshore | | | 62.02 | | | | 47.34 | | | | 37.47 | |
Total United States | | | 58.69 | | | | 46.50 | | | | 37.13 | |
Europe | | | 70.08 | | | | 55.03 | | | | 43.33 | |
Africa | | | 69.64 | | | | 53.17 | | | | 41.88 | |
Asia | | | 70.42 | | | | 56.99 | | | | 42.98 | |
Worldwide | | | 60.77 | | | | 49.23 | | | | 39.20 | |
| | | | | | | | | | | | |
Crude Oil - Per Barrel (Excluding Hedging) | | | | | | | | | | | | |
United States | | | | | | | | | | | | |
Onshore | | $ | 60.64 | | | $ | 46.76 | | | $ | 36.92 | |
Offshore | | | 65.73 | | | | 48.15 | | | | 37.47 | |
Total United States | | | 62.41 | | | | 47.25 | | | | 37.13 | |
Europe | | | 70.08 | | | | 55.14 | | | | 43.33 | |
Africa | | | 69.64 | | | | 53.25 | | | | 41.88 | |
Asia | | | 70.42 | | | | 56.99 | | | | 42.98 | |
Worldwide | | | 63.80 | | | | 49.75 | | | | 39.20 | |
| | | | | | | | | | | | |
Natural Gas Liquids - Per Barrel | | | | | | | | | | | | |
United States | | | | | | | | | | | | |
Onshore | | $ | 21.29 | | | $ | 17.67 | | | $ | 9.18 | |
Offshore | | | 25.58 | | | | 21.34 | | | | 13.96 | |
Total United States | | | 21.81 | | | | 18.10 | | | | 9.71 | |
Europe | | | — | | | | 29.04 | | | | 19.48 | |
Worldwide | | | 21.81 | | | | 18.35 | | | | 9.95 | |
| | | | | | | | | | | | |
Natural Gas - Per Mcf | | | | | | | | | | | | |
United States | | | | | | | | | | | | |
Onshore | | $ | 2.29 | | | $ | 1.96 | | | $ | 1.48 | |
Offshore | | | 2.68 | | | | 2.22 | | | | 1.99 | |
Total United States | | | 2.43 | | | | 2.03 | | | | 1.61 | |
Europe | | | 3.61 | | | | 4.42 | | | | 3.97 | |
Asia and other | | | 5.07 | | | | 4.27 | | | | 5.31 | |
Worldwide | | | 4.18 | | | | 3.37 | | | | 3.37 | |
(a)
| Selling prices in the United States are adjusted for certain processing and distribution fees included in Marketing expenses. Excluding these fees Worldwide selling prices for 2018 would be $63.77 | | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | 2019 | | Average Selling Prices (a) | | | | | | | Crude Oil - Per Barrel (Including Hedging) | | | | | | | United States | | | | | | | North Dakota | $ | 55.57 | | | $ | 42.63 | | | $ | 53.19 | | | Offshore | 60.09 | | | 45.92 | | | 59.18 | | | Total United States | 56.64 | | | 43.56 | | | 55.15 | | | Guyana | 68.57 | | | 46.41 | | | — | | | Malaysia and JDA | 71.00 | | | 37.91 | | | 61.81 | | | Other (b) | 66.39 | | | 51.37 | | | 65.22 | | | Worldwide | 60.08 | | | 44.28 | | | 56.77 | | | | | | | | | Crude Oil - Per Barrel (Excluding Hedging) | | | | | | | United States | | | | | | | North Dakota | $ | 59.90 | | | $ | 33.87 | | | $ | 53.18 | | | Offshore | 64.77 | | | 36.55 | | | 59.17 | | | Total United States | 61.05 | | | 34.63 | | | 55.14 | | | Guyana | 71.07 | | | 37.40 | | | — | | | Malaysia and JDA | 71.00 | | | 37.91 | | | 61.81 | | | Other (b) | 69.25 | | | 43.42 | | | 65.22 | | | Worldwide | 63.90 | | | 35.52 | | | 56.76 | | | | | | | | | Natural Gas Liquids - Per Barrel | | | | | | | United States | | | | | | | North Dakota | $ | 30.74 | | | $ | 11.29 | | | $ | 13.20 | | | Offshore | 26.40 | | | 8.94 | | | 13.31 | | | Worldwide | 30.40 | | | 11.10 | | | 13.21 | | | | | | | | | Natural Gas - Per Mcf | | | | | | | United States | | | | | | | North Dakota | $ | 4.08 | | | $ | 1.27 | | | $ | 1.59 | | | Offshore | 3.25 | | | 1.23 | | | 2.12 | | | Total United States | 3.82 | | | 1.26 | | | 1.83 | | | Malaysia and JDA | 5.15 | | | 4.47 | | | 5.04 | | | Other (b) | 3.40 | | | 3.41 | | | 4.63 | | | Worldwide | 4.60 | | | 2.98 | | | 3.90 | |
(a)Selling prices in the United States are adjusted for certain processing and distribution fees included in Marketing expenses. Excluding these fees worldwide selling prices for 2021 would be $64.25 per barrel for crude oil (including hedging), $66.80 per barrel for crude oil (excluding hedging), $22.00 per barrel for NGLs and $4.25 per mcf for natural gas. |
Net realized losses from crude oil (including hedging) (2020:
$47.54; 2019: $59.95), $68.07 per barrel for crude oil (excluding hedging) (2020: $38.78; 2019: $59.94), $30.61 per barrel for NGL (2020: $11.29; 2019: $13.40) and $4.71 per mcf for natural gas (2020: $3.11; 2019: $3.97). (b)Other includes our interests in Denmark, which were sold in August 2021, and Libya.
Crude oil hedging
contracts reduced Salesactivities in 2021 were a net loss of $243 million before and
other operating revenues by $183 million ($183 million after income
taxes) in 2018,taxes, and
$59a net gain of $547 million
($59 millionbefore and after income
taxes)taxes in
2017. There were no crude oil hedge contracts in 2016. We have purchased crude oil put options for2020. For calendar year
2019 that establish a2022, we have WTI
collars with an average monthly floor price of $60 per barrel
on 95,000and an average monthly ceiling price of $100 per barrel for 90,000 bopd,
and Brent collars with an average monthly floor price of $65 per barrel and an average monthly ceiling price of $105 per barrel for
$116 million,60,000 bopd. We expect premium amortization, which will be
amortized on a straight-line basis during 2019.reflected in realized selling prices, to reduce our 2022 results by approximately $225 million.
Production Volumes: Our daily worldwide net production was as follows:
| | 2018 | | | 2017 | | | 2016 | |
| | (In thousands) | |
Crude Oil - Barrels | | | | | | | | | | | | |
United States | | | | | | | | | | | | |
Bakken | | | 76 | | | | 67 | | | | 68 | |
Other Onshore | | | 1 | | | | 6 | | | | 9 | |
Total Onshore | | | 77 | | | | 73 | | | | 77 | |
Offshore | | | 41 | | | | 39 | | | | 45 | |
Total United States | | | 118 | | | | 112 | | | | 122 | |
Europe | | | 6 | | | | 28 | | | | 33 | |
Africa | | | 18 | | | | 35 | | | | 34 | |
Asia | | | 4 | | | | 2 | | | | 2 | |
Worldwide | | | 146 | | | | 177 | | | | 191 | |
| | | | | | | | | | | | |
Natural Gas Liquids - Barrels | | | | | | | | | | | | |
United States | | | | | | | | | | | | |
Bakken | | | 29 | | | | 28 | | | | 27 | |
Other Onshore | | | 5 | | | | 8 | | | | 11 | |
Total Onshore | | | 34 | | | | 36 | | | | 38 | |
Offshore | | | 5 | | | | 5 | | | | 5 | |
Total United States | | | 39 | | | | 41 | | | | 43 | |
Europe | | | — | | | | 1 | | | | 1 | |
Worldwide | | | 39 | | | | 42 | | | | 44 | |
| | | | | | | | | | | | |
Natural Gas - Mcf | | | | | | | | | | | | |
United States | | | | | | | | | | | | |
Bakken | | | 70 | | | | 62 | | | | 61 | |
Other Onshore | | | 44 | | | | 92 | | | | 133 | |
Total Onshore | | | 114 | | | | 154 | | | | 194 | |
Offshore | | | 67 | | | | 57 | | | | 64 | |
Total United States | | | 181 | | | | 211 | | | | 258 | |
Europe | | | 8 | | | | 33 | | | | 43 | |
Asia and other | | | 364 | | | | 276 | | | | 222 | |
Worldwide | | | 553 | | | | 520 | | | | 523 | |
| | | | | | | | | | | | |
Barrels of Oil Equivalent | | | 277 | | | | 306 | | | | 322 | |
| | | | | | | | | | | | |
Crude oil and natural gas liquids as a share of total production | | | 67 | % | | | 72 | % | | | 73 | % |
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
| | | | | |
| | (In thousands) |
| Crude Oil - Barrels | | | | | |
| United States | | | | | |
| North Dakota | 80 | | | 107 | | | 94 | |
| Offshore (a) | 29 | | | 38 | | | 46 | |
| Total United States | 109 | | | 145 | | | 140 | |
| Guyana | 30 | | | 20 | | | — | |
| Malaysia and JDA | 3 | | | 4 | | | 4 | |
| Other (b) | 21 | | | 9 | | | 25 | |
| Total | 163 | | | 178 | | | 169 | |
| Natural Gas Liquids - Barrels | | | | | |
| United States | | | | | |
| North Dakota | 49 | | | 56 | | | 42 | |
| Offshore (a) | 4 | | | 5 | | | 5 | |
| Total United States | 53 | | | 61 | | | 47 | |
| | | | | |
| Natural Gas - Mcf | | | | | |
| United States | | | | | |
| North Dakota | 162 | | | 180 | | | 110 | |
| Offshore (a) | 72 | | | 76 | | | 91 | |
| Total United States | 234 | | | 256 | | | 201 | |
| Malaysia and JDA | 347 | | | 291 | | | 351 | |
| Other (b) | 10 | | | 7 | | | 20 | |
| Total | 591 | | | 554 | | | 572 | |
| | | | | |
| Barrels of Oil Equivalent | 315 | | | 331 | | | 311 | |
| | | | | |
| Crude oil and natural gas liquids as a share of total production | 69 | % | | 72 | % | | 69 | % |
(a)In 2019,November 2020, we sold our working interest in the Shenzi Field in the deepwater Gulf of Mexico. Net production from the Shenzi Field was 9,000 boepd for the year ended December 31, 2020 (2019: 12,000 boepd).
(b)Other includes our interests in Denmark, which were sold in August 2021, and Libya. Net production from Denmark was 3,000 boepd for 2021 (2020: 6,000 boepd; 2019: 7,000 boepd). Net production from Libya was 20,000 boepd for 2021 (2020: 4,000 boepd; 2019: 21,000 boepd).
In 2022, we expect net production, excluding Libya, to
average between 270,000be in the range of 325,000 boepd
and 280,000to 330,000 boepd, compared
to full year pro forma 2018with 2021 net production, excluding Libya and assets sold, of
248,000290,000 boepd.
Production
Net production variances related to
2018, 20172021 and
20162020 are summarized as follows:
United States:Bakken North Dakota net production was higherlower in 2018, compared to 2017,2021, primarily due to increasedthe 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 improved well performancenatural gas volumes received under percentage of proceeds contracts due to higher commodity prices, curtailed production related to the planned Tioga Gas Plant maintenance turnaround completed in the current year. The year-on-year decline in U.S. other onshore production in 2018 and 2017 reflects the salethird quarter of our interests in the Utica shale play in August 20182021, and the sale of our Permian assetsLittle Knife and Murphy Creek nonstrategic acreage interests in August 2017.the second quarter of 2021. Total U.S. offshore oil production was higher in 2018, compared to 2017, primarily due to the Stampede and Penn State Fields, partially offset by the impact of downtime from a planned well workover at the Tubular Bells Field, the shutdown at the third-party operated Enchilada platform, and natural field decline. Total offshore production was lower in 2017, compared to 2016, due to shut-in production from the fire at the third-party operated Enchilada platform and natural field decline, partially offset by higher production from the Tubular Bells Field. Production from Utica averaged 9,000 boepd for calendar year 2018 (2017: 19,000 boepd; 2016: 29,000 boepd). Production from the Permian averaged net 4,000 boepd for calendar year 2017 (2016: 7,000 boepd).Europe: Total net production was lower in 2018 compared to 2017, 2021
primarily due to the sale of our intereststhe Shenzi Field in NorwayNovember 2020. International: Net crude oil production from Guyana was higher in December 2017. Crude2021, due to the production ramp up from the Liza Phase 1 development in 2020. Net oil production in Libya was higher in 2021 due to force majeure declared on production operations between January 2020 and October 2020. Net natural gas production was lower in 2017 compared to 2016, primarilyhigher at Malaysia and JDA reflecting higher natural gas nominations due to natural field decline. Productiona recovery in Norway averaged 24,000 boepd in 2017 (2016: 28,000 boepd).
Africa: Crude oil production was lower in 2018 compared to 2017, primarily reflecting the sale of Equatorial Guinea in November 2017, partially offseteconomic activity which had been impacted by higher production in Libya. Crude oil production in 2017 was comparable to 2016, as lower volumes from Equatorial Guinea were offset by higher production in Libya. Production in Equatorial Guinea averaged 25,000 boepd in 2017 (2016: 33,000 boepd). Production in Libya was 20,000 boepd in 2018 (2017: 10,000 boepd; 2016: 1,000 boepd).
Asia: Natural gas production was higher in 2018, compared to 2017, and in 2017, compared to 2016, primarily due to first production at the North Malay Basin full-field development in July 2017.
COVID-19.
Sales Volumes: The impact of lower sales volumes, primarily due to asset sales, decreased after-tax results by approximately $150 million in 2018, compared to 2017. WorldwideNet worldwide sales volumes from Hess net production, excludingwhich excludes sales volumes of crude oil, NGLs and natural gas purchased from third-parties,third parties, were as follows:
| | 2018 | | | 2017 | | | 2016 | | | | | | | | | | | | | | | | |
| | (In thousands) | | | 2021 | | 2020 | | 2019 |
Crude oil - barrels | | | 52,742 | | | | 63,367 | | | | 72,462 | | |
Natural gas liquids - barrels | | | 14,019 | | | | 15,152 | | | | 16,055 | | |
Natural gas - mcf | | | 202,041 | | | | 190,089 | | | | 191,482 | | |
| | | | | (In thousands) |
Crude oil – barrels (a) | | Crude oil – barrels (a) | 63,540 | | | 60,924 | | | 61,061 | |
Natural gas liquids – barrels | | Natural gas liquids – barrels | 19,406 | | | 22,397 | | | 17,067 | |
Natural gas – mcf | | Natural gas – mcf | 215,589 | | | 202,917 | | | 208,665 | |
Barrels of Oil Equivalent | | | 100,435 | | | | 110,201 | | | | 120,431 | | Barrels of Oil Equivalent | 118,878 | | | 117,141 | | | 112,906 | |
| | | | | | | | | | | | | | | | | | |
Crude oil - barrels per day | | | 144 | | | | 173 | | | | 198 | | Crude oil - barrels per day | 174 | | | 167 | | | 167 | |
Natural gas liquids - barrels per day | | | 39 | | | | 42 | | | | 44 | | Natural gas liquids - barrels per day | 53 | | | 61 | | | 47 | |
Natural gas - mcf per day | | | 553 | | | | 520 | | | | 523 | | Natural gas - mcf per day | 591 | | | 554 | | | 572 | |
Barrels of Oil Equivalent Per Day | | | 275 | | | | 302 | | | | 329 | | Barrels of Oil Equivalent Per Day | 326 | | | 320 | | | 309 | |
(a)At December 31, 2020, we had 4.2 million barrels of crude oil transported and stored on two chartered VLCCs for sale in Asian markets.The two VLCC cargos were sold in the first quarter of 2021.
Marketing, including purchased oil and gas: gas (Marketing expense):Marketing expense is mainly comprised of costs to purchase crude oil, NGLsNGL and natural gas from ourpartners in Hess operated wells or other third-parties,third parties, primarily in the U.S., and transportation and other distribution costs for U.S. marketing activities. The increasesMarketing expense was higher in 2018,2021 compared to 2017, and in 2017, compared2020 primarily due to 2016, primarily reflect the impact of higher benchmarkthird party crude oil volumes purchased and prices onpaid for purchased volumes. Marketing expenses in 2021 included $173 million related to the cost of purchased volumes.4.2 million barrels of crude oil stored on two VLCCs in 2020 that were sold in 2021. Marketing expense in 2020 was reduced by $164 million for the net cost of crude oil inventory that was capitalized for the barrels loaded on VLCCs.
Cash Operating Costs:Cash operating costs consistingconsist of operating costs and expenses, production and severance taxes and E&P general and administrative expenses, decreased by $221 millionexpenses. Excluding items affecting comparability described in 2018, compared to the prior year (2017: $404 million decrease versus 2016). The decrease in 2018, compared to 2017, is primarily due to asset sales and cost savings initiatives, partially offset by higher production taxes in the Bakken. The decrease in 2017, compared to 2016, is due to lower workover expenses, leaseItems Affecting Comparability of Earnings Between Periods onpage 37, cash operating and employee costs partially offset by higher production taxes in the Bakken. Operating costs in 2016 include higher workover costs to replace failed subsurface valves in the Gulf of Mexico.Midstream Tariffs Expense: Tariffs expense in 2018 increased compared to 2017, primarily due to higher throughput volumesmaintenance and water disposalworkover activity in 2018, partially offset by2021 compared with the prior year due to reduced activity in 2020 related to COVID-19, and higher production and severance taxes associated with higher crude oil prices in 2021. On a per-unit basis, cash operating costs were higher in 2021 due to the higher costs and the impact of lower costs from our former business in the Permian. 2021 production volumes.
Midstream Tariffs Expense: Tariffs expense in 2017 increased compared to 2016,from 2020, primarily due to higher shortfall feestariff rates and minimum volume commitments in 2017. For 2019,2021. In 2022, we estimate Midstream tariffs expense to be in the range of $750$1,190 million to $775$1,215 million.Depreciation, Depletion and Amortization: Depreciation, depletion and amortization (DD&A) costs decreased by $988 million
DD&A Expense: DD&A expense was lower in 2018, compared to 2017, 2021 primarily due to the sale of assets which had higherimpact to DD&A rates than the portfolio average, aresulting from year-end 2020 revisions and additions to proved reserves, lower DD&A rate at the Bakken due to year-end 2017 proved reserve additions,production volumes in 2021, and the impact of prior year asset impairments.DD&A costs decreased by $377 millionimpairment charges recognized in 2017, compared to 2016, primarily due to lower production and an improved portfolio average DD&A rate due to the production mix.first quarter of 2020.
Unit costs:Costs: Unit cost per boe information is based on total E&P net production volumes and excludes items affecting comparability of earnings as disclosed below.on page 37. Actual and forecast unit costs are as follows: | | Actual | | | Forecast range (a) |
| | 2018 | | | 2017 | | | 2016 | | | 2019 |
| | | | | | | | | | | | | | | | |
Cash operating costs (b) | | $ | 12.66 | | | $ | 14.27 | | | $ | 15.56 | | | $13.00 — $14.00 |
DD&A (c) | | | 17.14 | | | | 24.53 | | | | 26.40 | | | 18.00 — 19.00 |
Total Production Unit Costs | | $ | 29.80 | | | $ | 38.80 | | | $ | 41.96 | | | $31.00 — $33.00 |
(a)
| Forecast information excludes any contribution from Libya and items affecting comparability of earnings.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Actual | | Forecast range (a) |
| | 2021 | | 2020 | | 2019 | | 2022 |
| Cash operating costs (b) | $ | 11.55 | | | $ | 9.91 | | | $ | 11.99 | | | $12.50 — $13.00 |
| DD&A expense (c) | 11.84 | | | 15.80 | | | 17.43 | | | $11.50 — $12.50 |
| Total Production Unit Costs | $ | 23.39 | | | $ | 25.71 | | | $ | 29.42 | | | $24.00 — $25.50 |
(b)
| Excluding items affecting comparability of earnings and Libya, cash operating costs per boe for 2018 were $13.32 (2017: $14.56; 2016: $15.45).
|
(a)Forecast information excludes any contribution from Libya.(c)
| Excluding items affecting comparability of earnings and Libya, DD&A per boe for 2018 were $18.29 (2017: $25.29; 2016: $26.48).
|
(b)Cash operating costs per boe, excluding Libya, were $12.11 in 2021 (2020: $9.85; 2019: $12.54). (c)DD&A expense per boe, excluding Libya, was $12.43 in 2021 (2020: $15.98; 2019: $18.52).
Exploration Expenses:Exploration expenses, including items affecting comparability of earnings described below, were as follows: | | 2018 | | | 2017 | | | 2016 | |
| | (In millions) | |
Exploratory dry hole costs (a) | | $ | 165 | | | $ | 268 | | | $ | 1,064 | |
Exploration lease and other impairment | | | 37 | | | | 44 | | | | 145 | |
Geological and geophysical expense and exploration overhead | | | 160 | | | | 195 | | | | 233 | |
| | $ | 362 | | | $ | 507 | | | $ | 1,442 | |
(a)
| In 2018, we recorded | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | 2019 | | | | | | | | | (In millions) | | Exploratory dry hole costs (a) | $ | 11 | | | $ | 192 | | | $ | 49 | | | Exploration lease and other impairment (b) | 20 | | | 51 | | | 17 | | | Geological and geophysical expense and exploration overhead | 131 | | | 108 | | | 167 | | | | $ | 162 | | | $ | 351 | | | $ | 233 | |
(a)In 2021, dry hole costs primarily related to the Koebi-1 well in the Stabroek Block, offshore Guyana. In 2020, dry hole costs primarily related to the Tanager-1 well in the Kaieteur Block, offshore Guyana, the Galapagos Deep and Oldfield-1 wells in the Gulf of Mexico and the write-off of previously capitalized exploratory wells (see Items Affecting Comparability of Earnings Between Periods below). (b)In 2020, exploration lease and other impairment included impaired leasehold costs associated with the Aspy well, offshore Nova Scotia, Canada, the Pontoenoe-1 well, offshore Suriname, and the Sorubim-1 well on the Stabroek Block, offshore Guyana. In 2017, we recorded dry hole costs associated with our former interests in Ghana. In 2016, we recorded dry hole costs associated with our former interests in Australia and three exploration wells in the Gulf of Mexico. |
Exploration expenses were lower in 2018, compared to 2017, primarily due to lower dry hole expense and lower geologic and seismic costs. Exploration expenses were lower in 2017, compared to 2016, primarily due to lower dry hole expense, leasehold impairment expense, geologic and seismic costs, and employee expenses. See items affecting comparabilitya reprioritization of earnings between periods described below. For 2019,the Corporation’s forward capital program (see Items Affecting Comparability of Earnings Between Periods below).
In 2022, we estimate exploration expenses, excluding dry hole expense, to be in the range of
$200$170 million to
$220$180 million.
Income Taxes: The E&PIn 2021, income tax provisionexpense was$585 million compared with an expenseincome tax benefit of $391$12 million in 2018 (2017: $1,842 million benefit; 2016: $1,587 million expense). Excluding items affecting comparability between periods, the E&P2020, primarily due to higher pre-tax income in Libya and Guyana. Income tax provisionexpense from Libya operations was an expense of $391$436 million in 2018 (2017: $952021 compared with $38 million expense; 2016: $948 million benefit). The provision in 2018 compared to 2017, and 2017 compared to 2016, reflects higher production from Libya and lower deferred tax benefits on losses. Commencing in 2017, we2020. We are generally not recognizing deferred tax benefit or expense in certain countries, primarily the U.S. (non-Midstream), Denmark (hydrocarbon tax only)(sold in August 2021), Malaysia and Guyana,Malaysia, while we maintain valuation allowances against net deferred tax assets in these jurisdictions in accordance with the requirements of U.S. accounting standards. See E&P items affecting comparabilityItems Affecting Comparability of earnings below and Critical Accounting Policies and Estimates – Income Taxes beginning on page 39.Earnings Between Periods
below. Actual
and forecast effective tax rates are as follows:
| | Actual | | | Forecast range |
| | 2018 % | | | 2017 % | | | 2016 % | | | 2019 % |
Effective income tax benefit (expense) rate | | | (88 | ) | | | 34 | | | | (47 | ) | | N/A |
Adjusted effective income tax benefit (expense) rate (a) | | | 60 | | | | 7 | | | | 42 | | | 0 to (4) |
(a)
| Excludes any contribution from Libya and items affecting comparability of earnings.
|
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
| | % | | % | | % |
| Effective income tax benefit (expense) rate | (43) | | — | | (88) |
| Adjusted effective income tax benefit (expense) rate (a) | (15) | | (5) | | (36) |
(a)Excludes any contribution from Libya and items affecting comparability of earnings.
In 2022, we estimate income tax expense, excluding Libya and items affecting comparability of earnings between periods, to be in the range of $300 million to $310 million.
Items Affecting Comparability of Earnings Between Periods: Reported E&P earnings include the following items affecting comparability of income (expense) before and after income taxes::
| | Before Income Taxes | | | After Income Taxes | |
| | 2018 | | | 2017 | | | 2016 | | | 2018 | | | 2017 | | | 2016 | |
| | (In millions) | |
Gains (losses) on asset sales, net | | $ | 24 | | | $ | (41 | ) | | $ | 27 | | | $ | 24 | | | $ | (57 | ) | | $ | 17 | |
Exit costs and other | | | (110 | ) | | | — | | | | (26 | ) | | | (110 | ) | | | — | | | | (17 | ) |
Impairment | | | — | | | | (4,203 | ) | | | — | | | | — | | | | (2,250 | ) | | | — | |
Dry hole, lease impairment and other exploration expenses | | | — | | | | (280 | ) | | | (1,021 | ) | | | — | | | | (280 | ) | | | (745 | ) |
Noncash charges on de-designated crude oil collars | | | — | | | | (22 | ) | | | — | | | | — | | | | (22 | ) | | | — | |
Income tax adjustments | | | — | | | | — | | | | — | | | | — | | | | — | | | | (2,869 | ) |
Offshore rig cost | | | — | | | | — | | | | (105 | ) | | | — | | | | — | | | | (66 | ) |
Inventory write-off | | | — | | | | — | | | | (39 | ) | | | — | | | | — | | | | (19 | ) |
| | $ | (86 | ) | | $ | (4,546 | ) | | $ | (1,164 | ) | | $ | (86 | ) | | $ | (2,609 | ) | | $ | (3,699 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Before Income Taxes | | After Income Taxes |
| | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 |
| | | | | | | | | | | |
| | (In millions) |
| Impairment and other | $ | (147) | | | $ | (2,126) | | | $ | — | | | $ | (147) | | | $ | (2,049) | | | $ | — | |
| Dry hole and lease impairment expenses | — | | | (152) | | | — | | | — | | | (150) | | | — | |
| Crude oil inventories write-down | — | | | (53) | | | — | | | — | | | (52) | | | — | |
| Severance costs | — | | | (26) | | | — | | | — | | | (26) | | | — | |
| Cost recovery settlement | — | | | — | | | (21) | | | — | | | — | | | (19) | |
| Reversal of deferred tax asset valuation allowance | — | | | — | | | — | | | — | | | — | | | 60 | |
| Gains on asset sales, net | 29 | | | 79 | | | 22 | | | 29 | | | 79 | | | 22 | |
| | $ | (118) | | | $ | (2,278) | | | $ | 1 | | | $ | (118) | | | $ | (2,198) | | | $ | 63 | |
The pre-tax amounts of E&P items affecting comparability of income (expense) as presented in the Statement of Consolidated Incomeareas follows:
| | Before Income Taxes | |
| | 2018 | | | 2017 | | | 2016 | |
| | (In millions) | |
Sales and other operating revenues | | $ | — | | | $ | (22 | ) | | $ | — | |
Gains (losses) on asset sales, net | | | 24 | | | | (41 | ) | | | 27 | |
Operating costs and expenses | | | (19 | ) | | | — | | | | (162 | ) |
Exploration expenses, including dry holes and lease impairment | | | (3 | ) | | | (280 | ) | | | (1,029 | ) |
General and administrative expenses | | | (72 | ) | | | — | | | | — | |
Depreciation, depletion and amortization | | | (16 | ) | | | — | | | | — | |
Impairment | | | — | | | | (4,203 | ) | | | — | |
| | $ | (86 | ) | | $ | (4,546 | ) | | $ | (1,164 | ) |
| | | | | | | | | | | | | | | | | |
| | Before Income Taxes |
| 2021 | | 2020 | | 2019 |
| | | | | |
| | (In millions) |
| | | | | |
| Gains on asset sales, net | $ | 29 | | | $ | 79 | | | $ | 22 | |
| | | | | |
| 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 | — | | | (5) | | | — | |
| | | | | |
| Impairment and other | (147) | | | (2,126) | | | — | |
| | $ | (118) | | | $ | (2,278) | | | $ | 1 | |
2018:
2021:
•Gains (losses) on asset sales, net:We recordedrecognized a pre-tax gain of $14$29 million ($1429 million after income taxes) associated with the sale of our interests in Denmark.
•Impairment and other: We recorded a charge of $147 million ($147 million after income taxes) for the Utica shale playtotal estimated future abandonment obligations of the West Delta Field in eastern Ohiothe Gulf of Mexico. In June 2021, the U.S. Bankruptcy Court approved Fieldwood’s bankruptcy plan which included discharging decommissioning obligations, subject to conditions precedent, for certain of Fieldwood’s assets. Those obligations will transfer to former owners of the properties, including us with respect to the West Delta Field, which we sold in 2004. Potential recoveries from other parties that previously owned an interest in the West Delta Field have not been recognized as of December 31, 2021. See Note 12, Impairment and Other in the Notes to Consolidated Financial Statements.
2020:
•Impairment and other: We recorded noncash impairment charges totaling $2.1 billion ($2.0 billion after income taxes) related to our oil and gas properties at North Malay Basin in Malaysia, the South Arne Field in Denmark, and the Stampede and Tubular Bells fields in the Gulf of Mexico, primarily as a result of a lower long-term crude oil price outlook. Other charges totaling $21 million pre-tax ($20 million after income taxes) related to drilling rig right-of-use assets in the Bakken and surplus materials and supplies. See Note 12, Impairment and Other in the Notes to Consolidated Financial Statements.
•Dry hole and lease impairment expenses: We incurred pre-tax charges totaling $152 million ($150 million after income taxes) in the first quarter to write-off previously capitalized exploratory well costs of $125 million ($123 million after income taxes) primarily related to the northern portion of the Shenzi Field in the Gulf of Mexico and to impair certain exploration leasehold costs by $27 million ($27 million after income taxes) due to a reprioritization of our capital program.
•Crude oil inventories write-down: We incurred a pre-tax charge of $53 million ($52 million after income taxes) to adjust crude oil inventories to their net realizable value at the end of the first quarter following the significant decline in crude oil prices.
•Severance costs: We recorded a pre-tax charge of $26 million ($26 million after income taxes) for employee terminationbenefits incurred related to cost reduction initiatives.
•Gains on asset sales, net: We recorded a pre-tax gain of $10$79 million ($1079 million after income taxes) associated with the sale of our interests28% working interest in Ghana.
the Shenzi Field in the deepwater Gulf of Mexico.2019:
Exit costs and other: •Cost recovery settlement:We incurred noncash pre-tax charges of $73 million ($73 million after income taxes) in connection with vacated office space. In addition, we recorded a pre-tax severance charge of $37$21 million ($37 million after income taxes), related to a cost reduction program undertaken to reflect the reduced scale of our business following significant asset sales in 2017.
2017:
Gains (losses) on asset sales, net: We recognized a pre-tax gain of $486 million ($48619 million after income taxes) related to the sale of our assets in Equatorial Guinea, and a pre-tax gain of $330 million ($314 million after income taxes) related to the sale of our enhanced oilsettlement on historical cost recovery assetsbalances in the Permian Basin. We also incurred a pre-tax lossJDA that was paid in cash.
•Reversal of $857 million ($857 million after income taxes) on the sale of our interests in Norway. The loss included the recognition of $900 million in earnings for cumulative translation adjustments previously reflected within accumulated other comprehensive income. See Note 3, Dispositions in the Notes to Consolidated Financial Statements.
Impairment: deferred tax asset valuation allowance: We recorded a noncash impairment charge related to our interests in Norway totaling $2,503income tax benefit of $60 million, pre-tax ($550 million after income taxes) inwhich resulted from the third quarter prior to the sale of our interests in the fourth quarter. In addition, we recognized pre-tax impairment charges to reduce the carrying value of our interests in the Stampede Field by $1,095 million ($1,095 million after income taxes), and the Tubular Bells Field by $605 million ($605 million after income taxes) primarily becausereversal of a lower long-term crude oil price outlook. The Stampede Field had significant capitalized exploration and appraisal costs that were incurredvaluation allowance against net deferred tax assets in Guyana upon achieving first production from the Liza Phase 1 development.
•Gains on a 100% working interest basis on the Pony discovery prior to unitizing into the Stampede project. See Note 13, Impairment in the Notes to Consolidated Financial Statements.
Dry hole, lease impairment and other exploration expenses: asset sales, net:We recorded a pre-tax charge of $280 million ($280 million after income taxes) to fully impair the carrying value of our interest at the Hess operated offshore Deepwater Tano/Cape Three Points license, offshore Ghana (Hess 50% license interest) as a result of management’s decision in the fourth quarter of 2017 to not develop the previously discovered fields. These costs were incurred in periods prior to 2017.
Noncash charges on de-designated crude oil collars: We recorded a pre-tax chargegain of $22 million ($22 million after income taxes) related to certain crude oil collars not designated as cash flow hedges. The de-designation was a resultassociated with the sale of production downtime caused by a fire at the third-party operated Enchilada platformour remaining acreage in the Gulf of Mexico during the fourth quarter.
2016:
Dry hole, lease impairment and other exploration expenses: We recorded a pre-tax charge of $938 million ($693 million after income taxes) to write-off all previously capitalized wells and other project related costs for our Equus natural gas project, offshore the North West Shelf of Australia, following the decision to defer further development of the project. In addition, we recorded a pre-tax charge of $83 million ($52 million after income taxes) to write-off the previously capitalized Sicily-1 exploration well based on our decision not to pursue the project. These costs were incurred in periods prior to 2016.
| •
| Gains on asset sale, net: We recognized a pre-tax gain of $27 million ($17 million after income taxes) related to the sale of undeveloped onshore acreage in the U.S.
|
Utica shale play.Income taxes:We recorded a non-cash charge of $2,920 million to establish valuation allowances against net deferred tax assets at December 31, 2016, as required under application of the accounting standards following a three-year cumulative loss. This deferred tax charge had no impact on the Corporation’s cash flows or its underlying tax positions. In addition, we recorded a tax benefit of $51 million related to the resolution of certain international tax matters.
38
Offshore rig cost: We recognized a pre-tax charge of $105 million ($66 million after income taxes) related to an offshore drilling rig.
Inventory write-off: We incurred a pre-tax charge of $39 million ($19 million after income taxes) to write off surplus materials and supplies inventory.
Exit costs and other: We recorded exit and other costs of $26 million ($17 million after income taxes), which primarily relates to employee severance as part of a cost reduction program.
Midstream
Following is a summarized statement of income for our Midstream operations, which include results for a gas plant and associated CO2 assets in the Permian Basin (through August 2017) and water handling services in North Dakota that are wholly-owned by Hess:
| | 2018 | | | 2017 | | | 2016 | |
| | (In millions) | |
Revenues and Non-Operating Income | | | | | | | | | | | | |
Sales and other operating revenues | | $ | 713 | | | $ | 617 | | | $ | 569 | |
Losses on asset sales, net | | | — | | | | (51 | ) | | | — | |
Other, net | | | 6 | | | | — | | | | — | |
Total revenues and non-operating income | | | 719 | | | | 566 | | | | 569 | |
| | | | | | | | | | | | |
Costs and Expenses | | | | | | | | | | | | |
Operating costs and expenses | | | 193 | | | | 195 | | | | 218 | |
General and administrative expenses | | | 14 | | | | 16 | | | | 20 | |
Depreciation, depletion and amortization | | | 127 | | | | 123 | | | | 121 | |
Impairment | | | — | | | | — | | | | 67 | |
Interest expense | | | 60 | | | | 26 | | | | 19 | |
Total costs and expenses | | | 394 | | | | 360 | | | | 445 | |
| | | | | | | | | | | | |
Results of Operations Before Income Taxes | | | 325 | | | | 206 | | | | 124 | |
Provision (benefit) for income taxes (a) | | | 38 | | | | 31 | | | | 26 | |
Net income (loss) | | | 287 | | | | 175 | | | | 98 | |
Less: Net income (loss) attributable to noncontrolling interests (b) | | | 167 | | | | 133 | | | | 56 | |
Net Income (Loss) Attributable to Hess Corporation | | $ | 120 | | | $ | 42 | | | $ | 42 | |
(a)
| The provision for income taxes in the Midstream segment in 2018 and 2017 is presented before consolidating its operations with other U.S. activities of the Company and prior to evaluating realizability of net U.S. deferred taxes. An offsetting impact is presented in the E&P segment.
|
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
| | | | | |
| | (In millions) |
| Revenues and Non-Operating Income | | | | | |
| Sales and other operating revenues | $ | 1,204 | | | $ | 1,092 | | | $ | 848 | |
| | | | | |
| Other, net | 10 | | | 10 | | | 4 | |
| Total revenues and non-operating income | 1,214 | | | 1,102 | | | 852 | |
| Costs and Expenses | | | | | |
| Operating costs and expenses | 289 | | | 338 | | | 279 | |
| General and administrative expenses | 22 | | | 21 | | | 56 | |
| Depreciation, depletion and amortization | 166 | | | 157 | | | 142 | |
| Interest expense | 105 | | | 95 | | | 63 | |
| Total costs and expenses | 582 | | | 611 | | | 540 | |
| Results of Operations Before Income Taxes | 632 | | | 491 | | | 312 | |
| Provision (benefit) for income taxes | 15 | | | 7 | | | — | |
| Net income (loss) | 617 | | | 484 | | | 312 | |
| Less: Net income (loss) attributable to noncontrolling interests | 331 | | | 254 | | | 168 | |
| Net Income (Loss) Attributable to Hess Corporation | $ | 286 | | | $ | 230 | | | $ | 144 | |
(b)
| The partnership is not subject to tax and, therefore, the noncontrolling interest’s share of net income is a pre-tax amount.
|
Sales and other operating revenues in 2018 increased compared to 2017,from 2020 primarily due to higher throughput volumes and water disposal activity in 2018, partially offset by prior year activity associated with our former Permian assets that were sold in August 2017. Sales and other operating revenues in 2017 increased, compared to 2016, primarily due to higher shortfall fees earned, and higher tariff rates and throughput volumes,minimum volume commitments partially offset by lower pass-through rail export revenue associated with third-party rail charges and the sale of our Permian assets in August 2017.
transportation revenue. Operating costs and expenses in 2018 reflect increased activity related to produced water disposal services and lower costsdecreased from our former Permian assets versus the prior year. Operating costs and expenses were lower in 2017 compared to 2016, primarily2020 primarily due to lower third-party rail charges andpass-through transportation costs, which were partially offset by the sale of our Permian assetscosts incurred associated with the planned Tioga Gas Plant maintenance turnaround in August 2017.2021. DD&A expenses were higher in 2018 compared to 2017,expense increased from 2020 primarily due to pipelineadditional assets that were brought into serviceplaced in service. Interest expense increased from 2020 primarily due to the current year.
The increase$750 million of 4.250% fixed-rate senior unsecured notes due 2030 issued in interest expense in 2018, compared to 2017, and 2017, compared to 2016, reflects higher borrowings by Hess Infrastructure Partners LP.
For 2019,August 2021.
In 2022, we estimate net income attributable to Hess Corporation from the Midstream segment to be in the range of
$170$275 million to
$180$285 million.
Items Affecting Comparability of Earnings Between Periods: WeIn 2019, we recognized a pre-tax losscharge of $57$30 million ($3416 million after income taxes and noncontrolling interest)interests) in 2017General and Administrative Expenses for transaction related tocosts for Hess Midstream Partners LP’s acquisition of HIP and the sale of ourassociated corporate restructuring. See Note 4, Hess Midstream assetsLP in the Permian Basin. Midstream results in 2016 included a pre-tax charge of $67 million ($21 million after income taxes and noncontrolling interest)Notes to impair older specification rail cars.
Consolidated Financial Statements.
Corporate, Interest and Other
The following table summarizes Corporate, Interest and Other expenses:
| | | | | 2021 | | 2020 | | 2019 |
| | 2018 | | | 2017 | | | 2016 | | | | | | | |
| | (In millions) | | | (In millions) |
Corporate and other expenses (excluding items affecting comparability) | | $ | 97 | | | $ | 160 | | | $ | 131 | | Corporate and other expenses (excluding items affecting comparability) | $ | 121 | | | $ | 114 | | | $ | 114 | |
Interest expense | | | 359 | | | | 385 | | | | 380 | | Interest expense | 376 | | | 373 | | | 355 | |
Less: Capitalized interest | | | (20 | ) | | | (86 | ) | | | (61 | ) | Less: Capitalized interest | — | | | — | | | (38) | |
Interest expense, net | | | 339 | | | | 299 | | | | 319 | | Interest expense, net | 376 | | | 373 | | | 317 | |
Corporate, Interest and Other expenses before income taxes | | | 436 | | | | 459 | | | | 450 | | Corporate, Interest and Other expenses before income taxes | 497 | | | 487 | | | 431 | |
Provision (benefit) for income taxes | | | (3 | ) | | | (26 | ) | | | (163 | ) | Provision (benefit) for income taxes | — | | | (6) | | | — | |
Net Corporate, Interest and Other expenses after income taxes | | | 433 | | | | 433 | | | | 287 | | Net Corporate, Interest and Other expenses after income taxes | 497 | | | 481 | | | 431 | |
Items affecting comparability of earnings between periods, after income taxes | | | 20 | | | | 30 | | | | 923 | | Items affecting comparability of earnings between periods, after income taxes | — | | | 1 | | | 174 | |
Total Corporate, Interest and Other Expenses After Income Taxes | | $ | 453 | | | $ | 463 | | | $ | 1,210 | | Total Corporate, Interest and Other Expenses After Income Taxes | $ | 497 | | | $ | 482 | | | $ | 605 | |
Corporate and other expenses, excluding items affecting comparability, were lower in 2018, compared to 2017, primarily due to lower employee related costs, non-service pension costs and legal fees.
Corporate and other expenses, excluding items affecting comparability, were higher in
2017,2021 compared to
2016, 2020 primarily due to higher legal costs, increased pension settlement charges in 2017, anda gain from the recognitionsale of a nonrecurring gain of $8 millionproperty related to a former downstream business in 2016.2020. In
2019,2022, after-tax Corporate and other expenses, excluding items affecting comparability of earnings between periods, are estimated to be in the range of
$105$120 million to
$115$130 million.
Interest expense was lower in 2018, compared to 2017, due to lower average borrowings. Capitalized interest was lower in 2018, compared to 2017, primarily due to the Stampede Field commencing production in January 2018. Interest expense was higher in 2017, compared to 2016, primarily due to slightly higher average borrowings. Capitalized interest expense was higher in 2017, compared to 2016, due to increased activity at the Hess operated Stampede development project and sanction of the Liza Field Phase 1 development project during 2017. In 2019 after-tax interest expense, net is estimated to be in the range of $315$350 million to $325 million.
Excluding items affecting comparability of earnings between periods, the benefit for income taxes is lower$360 million in 2018 and 2017, compared to 2016, due to us generally not recognizing deferred tax benefit or expense in the U.S. while we maintain valuation allowances against net deferred tax assets in accordance with the requirements of U.S. accounting standards. This accounting treatment commenced on December 31, 2016. See items affecting comparability of earnings below and Critical Accounting Policies and Estimates – Income Taxes beginning on page 39.
2022.
Items Affecting Comparability of Earnings Between Periods: Corporate, Interest and Other results included the following items affecting comparability of income (expense) before and after income taxes:2018:
: 2020:
Loss on debt extinguishment: •Severance costs:Werecordedincurred a pre-tax charge of $53$1 million ($53($1 million after income taxes) for employee termination benefits related to the premium paid for debt repurchases. See Note 8, Debt, in the Notes to Consolidated Financial Statements.
2019:
Exit costs and other: •Pension settlement: We recorded a pre-taxnoncash pension settlement charge of $58$88 million ($5888 million after income taxes) resulting fromassociated with the settlementpurchase of legal claims relateda single premium annuity contract by the Hess Corporation Employees’ Pension Plan to former downstream interests.
•Income tax: We recorded an allocation of noncash income tax benefitexpense of $91$86 million to offset the recognitionthat was previously a component of a noncash income tax expense recorded inaccumulated other comprehensive income resulting primarily from changes in fair value ofrelated to our 2019 crude oil hedging program, as required under accounting standards.
2017:
Exit costs and other: We recorded a pre-tax charge of $30 million ($30 million after income taxes) in connection with vacated office space, of which $11 million is included in General and administrative expenses and $19 million is included in Depreciation, depletion and amortization in the Statement of Consolidated Income.
2016:
Income tax: We recorded a non-cash charge of $829 million to establish valuation allowances against net deferred tax assets at December 31, 2016, as required under application of the accounting standards following a three-year cumulative loss. This deferred tax charge had no impact on the Corporation’s cash flows or its underlying tax positions.
Loss on debt extinguishment: We recorded a pre-tax charge of $148 million ($92 million after income taxes) related to the repurchase and redemption of notes to complete a debt refinancing.
| •
| Exit costs and other: We recorded exit and other costs of $3 million ($2 million after income taxes), which primarily relates to employee severance.
|
Liquidity and Capital Resources
The following table sets forth certain relevant measures of our liquidity and capital resources at December 31:
| | 2018 | | | 2017 | |
| | (In millions, except ratio) | |
Cash and cash equivalents (a) | | $ | 2,694 | | | $ | 4,847 | |
Current maturities of long-term debt | | | 67 | | | | 580 | |
Total debt (b) | | | 6,672 | | | | 6,977 | |
Total equity | | | 10,888 | | | | 12,354 | |
Debt to capitalization ratio (c) | | | 38.0 | % | | | 36.1 | % |
(a)
| Includes $109 million of cash attributable to our Midstream Segment, at December 31, 2018 (2017: $356 million).
|
| | | | | | | | | | | |
| | 2021 | | 2020 |
| | | |
| | (In millions, except ratio) |
| Cash and cash equivalents (a) | $ | 2,713 | | | $ | 1,739 | |
| Current portion of long-term debt (b) | 517 | | | 10 | |
| Total debt (c) | 8,458 | | | 8,296 | |
| Total equity | 7,026 | | | 6,335 | |
| Debt to capitalization ratio for debt covenants (d) | 42.3 | % | | 47.5 | % |
(b)
| Includes $981 million of debt outstanding from HIP at December 31, 2018 (2017: $980 million) that is non-recourse to Hess Corporation.
|
(a)Includes $2 million of cash attributable to our Midstream Segment at December 31, 2021 (2020: $4 million) of which, $2 million is held by Hess Midstream LP at December 31, 2021 (2020: $3 million).(c)
| Total debt as a percentage of the sum of total debt plus equity.
|
(b)Includes the remaining $500 million outstanding under our $1 billion term loan maturing in March 2023 that we repaid in February 2022.(c)Includes $2,564 million of debt outstanding from our Midstream Segment at December 31, 2021 (2020: $1,910 million) that is non-recourse to Hess Corporation.
(d)Total Consolidated Debt of Hess Corporation (including finance leases and excluding Midstream non-recourse debt) as a percentage of Total Capitalization of Hess Corporation as defined under Hess Corporation's term loan and revolving credit facility financial covenants. Total Capitalization excludes the impact of noncash impairment charges and non-controlling interests. See Note 7, Debt in the Notes to Consolidated Financial Statements.
The following table sets forth a summary of our cash flows:
| | | | | 2021 | | 2020 | | 2019 |
| | 2018 | | | 2017 | | | 2016 | | | | | | | |
| | (In millions) | | | (In millions) |
Net cash provided by (used in): | | | | | | | | | | | | | Net cash provided by (used in): | | | | | |
Operating activities | | $ | 1,939 | | | $ | 945 | | | $ | 795 | | Operating activities | $ | 2,890 | | | $ | 1,333 | | | $ | 1,642 | |
Investing activities | | | (1,566 | ) | | | 1,358 | | | | (2,090 | ) | Investing activities | (1,325) | | | (1,707) | | | (2,843) | |
Financing activities | | | (2,526 | ) | | | (188 | ) | | | 1,311 | | Financing activities | (591) | | | 568 | | | 52 | |
Net Increase (Decrease) in Cash and Cash Equivalents | | $ | (2,153 | ) | | $ | 2,115 | | | $ | 16 | | Net Increase (Decrease) in Cash and Cash Equivalents | $ | 974 | | | $ | 194 | | | $ | (1,149) | |
Operating Activities: In 2018, Net cash provided by operating activities was $2,890 million in 2021 (2020: $1,333 million), while net cash provided by operating activities before changes in operating assets and liabilities was $2,991 million in 2021 (2020: $1,803 million). Net cash provided by operating activities before changes in operating assets and liabilities increased compared to 2017, primarily due to higher benchmark crude oil prices and lower operating costs, partially offset by lower production volumes largely due to asset sales. In 2017, operating cash flows increased, compared to 2016,from 2020 primarily due to higher benchmark crude oil prices and lower operating costs, partially offset by lower production volumes.realized selling prices. Changes in working capitaloperating assets and liabilities in 20182021 reduced net cash provided by $186operating activities by $101 million, (2017: $780 million reduction; 2016: $47 million reduction), primarily from higher receivables which includes premiums paid on crude oil hedge contracts, and abandonment expenditures. Changes in working capital in 2017 included increased accounts receivable due to higher crude oil prices, abandonment expenditures, premiums on crude oil hedge contracts, pension contributions, contract termination payments for an offshore drilling rig, and crude oil delivered as line fill.
Investing Activities: Total addition to property, plant and equipment were $2,097 million in 2018 (2017: $1,937 million; 2016: $2,251 million). The increase in Additions to property, plant and equipment in 2018, compared to 2017, is primarily related to increased expenditures in the Bakken, offshore Guyana, offshore Canada and in our Midstream segment, primarily offset by the impact of prior year asset sales and reduced development expenditure in both the Gulf of Mexico and Malaysia. In 2017, Additions to property, plant and equipment were lower, compared to 2016, primarily due to lower development expenditures at North Malay Basin, partially offset by increased investmentsaccrued income taxes and royalties payable, an increase in Bakkenaccrued liabilities, and Guyanaa decrease in 2017. In 2018, Midstream equity investmentscrude oil inventory resulting from our VLCC transactions. Changes in its 50/50 joint venture with Targa Resources were $67 million. Proceedsoperating assets and liabilities in 2020 reduced net cash provided by operating activities by $470 million, primarily from the salea decrease in accounts payable and accrued liabilities, an increase in crude oil inventory resulting from our VLCC transactions, and abandonment expenditures, partially offset by lower receivables. At December 31, 2021, we have accrued income taxes and royalties payable of assets of $607approximately $470 million in 2018 (2017: $3,296 million; 2016: $140Libya related to operations for the period December 2020 through November 2021, which we paid in January 2022.
Investing Activities: Total Additions to Property, Plant and Equipment were $1,747 million in 2021 (2020: $2,197 million) include the divestiture. The decrease primarily reflects lower drilling activity. Proceeds from asset sales were $427 million in 2021 (2020: $493 million).
Financing Activities: In 2021, we repaid $500 million of our joint venture interests$1 billion term loan maturing in March 2023. Borrowings in 2021 related to the Utica shale play$750 million of 4.250% fixed-rate senior unsecured notes due 2030 issued by our Midstream operating segment, while borrowings in eastern Ohio, and2020 related to our share of proceeds from the sale and lease-back transaction of the North Malay Basin floating storage and offloading vessel.Financing Activities: Repayments of debt were $633 million in 2018 (2017: $459 million; 2016: $1,455 million) while borrowings of debt with maturities in excess of 90 days were $800 million in 2017 and $1,496 million in 2016. We settled common stock purchases in the amount of $1,365 million in 2018 (2017: $110 million).$1 billion term loan. Common and preferred stock dividends paid were $345$311 million in 2018 (2017: $363 million; 2016: $3502021 (2020: $309 million). In 2017, Hess Midstream Partners LP received
proceeds of $365.5 million from the issuance of common units in an initial public offering, of which $350 million was distributed equally to Hess Corporation, and GIP. Net outflowspayments to noncontrolling interests were $211$664 million in 2018 (2017: $2432021 (2020: $261 million), which included $375 million net outflow; 2016: $23paid to GIP for the repurchase by HESM Opco of approximately 15.6 million net outflow).GIP-owned Class B units. In 2016,2021, we issued 28,750,000 shares of common stock and depositary shares representing 575,000 shares of 8% Series A Mandatory Convertible Preferred Stock for totalreceived net proceeds of $1.64 billion.
$178 million from two public offerings totaling approximately 7.8 million Hess-owned Class A shares in Hess Midstream LP.
Future Capital Requirements and Resources
At December 31,
2018, Hess Corporation,2021, we had
$2.6 $2.71 billion in cash and cash equivalents, excluding Midstream, and total liquidity, including available committed credit facilities, of approximately
$7.0$6.3 billion.
The Corporation has no significant near-term debt maturities. We have purchased crude oil put optionsOur fully undrawn $3.5 billion committed revolving credit facility matures in May 2024. In January 2022, we paid accrued Libyan income tax and royalties of approximately $470 million related to operations for calendar year 2019 that establish a WTI monthly floor price of $60 per barrel for 95,000 bopd.the period December 2020 through November 2021. In February 2022, we repaid the remaining $500 million outstanding under our $1 billion term loan.
Net production in 20192022 is forecast to be in the range of 270,000325,000 boepd to 280,000 330,000 boepd, excluding Libya, and we expect our 20192022 E&P capital and exploratory expenditures will be approximately $2.9 billion. Based$2.6 billion. For calendar year 2022, we have WTI collars with an average monthly floor price of $60 per barrel and an average monthly ceiling price of $100 per barrel for 90,000 bopd, and Brent collars with an average monthly floor price of $65 per barrel and an average monthly ceiling price of $105 per barrel for 60,000 bopd.
In 2022, based on current forward strip crude oil prices, for 2019, we expect cash flow from operating activities and cash and cash equivalents existing at December 31, 2018,2021 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, through the end of 2019.pursue asset sales, borrow against our committed revolving credit facility, or issue debt or equity securities.
The table below summarizes the capacity, usage, and available capacity of our borrowing and letter of credit facilities at December 31,
2018: | | | | | | | | | | | | Letters of | | | | | | | | | |
| | Expiration | | | | | | | | | | Credit | | | Total | | | Available | |
| | Date | | Capacity | | | Borrowings | | | Issued | | | Used | | | Capacity | |
| | | | (In millions) | |
Hess Corporation | | | | | | | | | | | | | | | | | | | | | | |
Revolving credit facility - Hess Corporation (a) | | January 2021 | | $ | 4,000 | | | $ | — | | | $ | — | | | $ | — | | | $ | 4,000 | |
Committed lines | | Various (b) | | | 445 | | | | — | | | | 29 | | | | 29 | | | | 416 | |
Uncommitted lines | | Various (b) | | | 255 | | | | — | | | | 255 | | | | 255 | | | | — | |
Total - Hess Corporation | | | | $ | 4,700 | | | $ | — | | | $ | 284 | | | $ | 284 | | | $ | 4,416 | |
| | | | | | | | | | | | | | | | | | | | | | |
Midstream | | | | | | | | | | | | | | | | | | | | | | |
Revolving credit facility - HIP (c) | | November 2022 | | $ | 600 | | | $ | — | | | $ | — | | | $ | — | | | $ | 600 | |
Revolving credit facility - Hess Midstream Partners LP (d) | | March 2021 | | | 300 | | | | — | | | | — | | | | — | | | | 300 | |
Total - Midstream | | | | $ | 900 | | | $ | — | | | $ | — | | | $ | — | | | $ | 900 | |
(a)
| In January 2020, the capacity reduces to $3.7 billion.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Expiration
Date | | Capacity | | Borrowings | | Letters of
Credit
Issued | | Total
Used | | Available
Capacity |
| | | | | | | | | | | |
| | | | (In millions) |
| Hess Corporation | | | | | | | | | | | |
| Revolving credit facility | May 2024 | | $ | 3,500 | | | $ | — | | | $ | — | | | $ | — | | | $ | 3,500 | |
| Committed lines | Various (a) | | 100 | | | — | | | 29 | | | 29 | | | 71 | |
| Uncommitted lines | Various (a) | | 230 | | | — | | | 230 | | | 230 | | | — | |
| Total - Hess Corporation | | | $ | 3,830 | | | $ | — | | | $ | 259 | | | $ | 259 | | | $ | 3,571 | |
| Midstream | | | | | | | | | | | |
| Revolving credit facility (b) | December 2024 | | $ | 1,000 | | | $ | 104 | | | $ | — | | | $ | 104 | | | $ | 896 | |
| Total - Midstream | | | $ | 1,000 | | | $ | 104 | | | $ | — | | | $ | 104 | | | $ | 896 | |
(b)
| Committed and uncommitted lines have expiration dates throughout 2019.
|
(a)Committed and uncommitted lines have expiration dates through 2022.(c)
| This credit facility may only be utilized by HIP and is non-recourse to Hess Corporation.
|
(b)This credit facility may only be utilized by HESM Opco and is non-recourse to Hess Corporation.(d)
| This credit facility may only be utilized by Hess Midstream Partners LP and is non-recourse to Hess Corporation.
|
Hess Corporation:The Corporation’s $4.0
In April 2021, we amended the Corporation's fully undrawn $3.5 billion syndicated revolving credit facility expiresthat had an expiration date in January 2021, with commitments of $3.7 billion availableMay 2023, by extending the facility for one year to May 2024 and incorporating customary provisions for the final year.eventual replacement of LIBOR, among other changes as set forth in the amended credit agreement. This facility can be used for borrowings and letters of credit. Borrowings on the facility will generally bear interest at 1.30%1.40% above LIBOR, though the London Interbank Offered Rate (LIBOR). The interest rate will be higheris subject to adjustment if ourthe Corporation’s credit rating is lowered. The facility contains a financial covenant that limits the amount of the total borrowings on the last day of each fiscal quarter to 60% of the Corporation’s total capitalization, defined as total debt plus stockholders’ equity.changes. At December 31, 2018,2021, Hess Corporation had no outstanding borrowings or letters of credit under thisits revolving credit facility.
In 2020, we entered into a $1 billion three year term loan agreement with a maturity date of March 16, 2023. Borrowings under the term loan generally bear interest at LIBOR plus an initial applicable margin of 2.25%. In July 2021, we repaid $500 million of the term loan, and in February 2022, we repaid the remaining $500 million.
The revolving credit facility and term loan are subject to customary representations, warranties, customary events of default and covenants, including a financial covenant limiting the ratio of Total Consolidated Debt to Total Capitalization of the Corporation and its consolidated subsidiaries to 65%, and a financial covenant limiting the ratio of secured debt to Consolidated Net Tangible Assets of the Corporation and its consolidated subsidiaries to 15% (as these capitalized terms are defined in the credit agreement for the revolving credit facility and the term loan agreement). The indentures for the Corporation's fixed-rate public notes limit the ratio of
secured debt to Consolidated Net Tangible Assets (as that term is defined in the indentures) to 15%. As of December 31, 2021, Hess Corporation was in compliance with thisthese financial covenant. covenants. The most restrictive of the financial covenants related to our fixed-rate public notes and our term loan and revolving credit facility would allow us to borrow up to an additional $1,843 million of secured debt at December 31, 2021. For additional information regarding the alteration or discontinuation of LIBOR on our borrowing costs, see
Financial Risks in Item 1A. Risk Factors. We had
$284$259 million in letters of credit outstanding at December 31,
2018 (2017: $2462021 (2020: $269 million), which
primarily relate to our
internationalglobal business operations.
See also Note 21, Financial Risk Management Activities in the Notes to Consolidated Financial Statements.We also have a shelf registration under which we may issue additional debt securities, warrants, common stock or preferred stock.
Midstream:
At December 31,
2018, HIP has $800 million2021, HESM Opco, a consolidated subsidiary of Hess Midstream LP, had $1.4 billion of senior secured syndicated credit facilities maturing
November 2022,December 16, 2024, consisting of a
$600 million 5-year$1 billion five year revolving credit facility and a
fully drawn
$200$400 million
5-year Term Loanfive year term loan A facility. The revolving credit facility can be used for borrowings and letters of credit to fund
the joint venture’sHESM Opco’s operating activities,
capital expenditures, distributions and
capital expenditures.for other general corporate purposes. Borrowings under the
5-year Term Loanfive year term loan A facility will generally bear interest at LIBOR plus an applicable margin ranging from 1.55% to 2.50%, while the applicable margin for the
5-yearfive year syndicated revolving credit facility ranges from 1.275% to 2.000%.
The interest rate is subject to adjustmentPricing levels for the facility fee and interest-rate margins are based on
HIP’s leverageHESM Opco’s ratio
which is calculated asof total debt to
Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA)EBITDA (as defined in the credit facilities). If
HIPHESM Opco obtains an investment grade credit rating,
as defined in the
amended credit agreement, pricing levels will be based on
theHESM Opco’s credit ratings in effect from time
to time. The credit facilities contain financial covenants that generally require HESM Opco to maintain a leverage ratio of no more than 5.0total debt to 1.0EBITDA (as defined in the credit facilities) for the prior four fiscal quarters of not greater than 5.00 to 1.00 as of the last day of each fiscal quarter (5.50 to 1.00 during the specified period following certain acquisitions) and, prior to HESM Opco obtaining an interest coverageinvestment grade credit rating, a ratio which is calculated asof secured debt to EBITDA to cash interest expense, of no less than 2.25 to 1.0 for the prior four fiscal quarters. The amended credit agreement includes a secured leverage ratio testquarters of not to exceed 3.75greater than 4.00 to 1.00 for so long as of the facilities remain secured. HIP islast day of each fiscal quarter. HESM Opco was in compliance with these financial covenants at December 31, 2018. Outstanding borrowings under this credit facility are non-recourse to Hess Corporation. At December 31, 2018, HIP’s revolving credit facility was undrawn and borrowings under the Term Loan A facility amounted to $197.5 million, excluding deferred issuance costs.2021. The credit facilities are secured by first-priority perfected liens on substantially all of HIP’s and certain of its wholly-owned subsidiaries’ directly owned assets, including its equity interests in certain subsidiaries, subject to customary exclusions.
Hess Midstream Partners LP (the “Partnership”) has a $300 million 4-year senior secured syndicated revolving credit facility that became available for utilization at completion of its initial public offering in April 2017. The credit facility can be used for borrowings and letters of credit to fund operating activities and capital expenditures of the Partnership and expires March 2021. Borrowings on the credit facility will generally bear interest at LIBOR plus an applicable margin of 1.275%. The interest rate is subject to adjustment based on the Partnership’s leverage ratio, which is calculated as total debt to EBITDA. If the Partnership obtains credit ratings, pricing levels will be based on the credit ratings in effect from time to time. The Partnership is subject to customary covenants in the credit agreement, including financial covenants that generally require a leverage ratio of no more than 4.5 to 1.0 for the prior four fiscal quarters. The credit facility is secured by first priority perfected liens on substantially all directly owned assets of the PartnershipHESM Opco and its wholly-owneddirect and indirect wholly owned material domestic subsidiaries, including equity interests in subsidiaries,directly owned by such entities, subject to certain customary exclusions. OutstandingAt December 31, 2021, borrowings of $104 million were drawn under thisHESM Opco’s revolving credit facility, and borrowings of $390 million, excluding deferred issuance costs, were drawn under HESM Opco’s term loan A facility. Borrowings under these credit facilities are non-recourse to Hess Corporation. At December 31, 2018, this facility was undrawn.
Two of the three major credit rating agencies that rate
the Corporation’sour debt have assigned an investment grade rating.
At December 31, 2018, we have investment grade credit ratings fromIn March 2021, Standard and Poor’s Ratings Services
(BBB-)affirmed our credit rating at BBB- and
revised the outlook to stable (from negative). Fitch Ratings
(BBB-).affirmed our BBB- credit rating and revised the outlook from stable to positive in August 2021 and Moody’s Investors Service
has rated our debt at Ba1. The consequence of lower credit ratings is an increase in interest rates and facility fees onaffirmed our credit
facilitiesrating at Ba1, which is below investment grade, and
revised the
potential for additional required collateral under operating agreements, which are not material.outlook from stable to positive in November 2021.
At December 31, 2018, HIP’s2021, HESM Opco’s senior unsecured debt is rated BB+ by Standard and Poor’s Ratings Services and Fitch Ratings, and Ba3 by Moody’s Investors Service,Service.
Cash Requirements:
Our cash obligations and
BB by Fitch Ratings.Contractual Obligationscommitments over the next twelve months include accounts payable, accrued liabilities, the current portion of long-term debt, interest, lease payments, and Contingencies
The following table shows aggregate information about certain contractualpurchase obligations at December 31, 2018:
| | | | | | Payments Due by Period | |
| | | | | | | | | | 2020 and | | | 2022 and | | | | | |
| | Total | | | 2019 | | | 2021 | | | 2023 | | | Thereafter | |
| | (In millions) | |
Total Debt (excludes interest) (a) | | $ | 6,672 | | | $ | 67 | | | $ | 66 | | | $ | 192 | | | $ | 6,347 | |
Operating Leases (b) (c) | | | 902 | | | | 355 | | | | 221 | | | | 128 | | | | 198 | |
Purchase Obligations: | | | | | | | | | | | | | | | | | | | | |
Capital expenditures (c) | | | 1,069 | | | | 443 | | | | 551 | | | | 75 | | | | — | |
Operating expenses (c) | | | 433 | | | | 219 | | | | 99 | | | | 61 | | | | 54 | |
Transportation and related contracts (c) | | | 1,050 | | | | 212 | | | | 401 | | | | 336 | | | | 101 | |
Asset retirement obligations | | | 857 | | | | 116 | | | | 75 | | | | 36 | | | | 630 | |
Other liabilities | | | 518 | | | | 121 | | | | 93 | | | | 84 | | | | 220 | |
(a)
| We anticipate cash payments for interest of $401 million for 2019, $775 million for 2020-2021, $752 million for 2022-2023, and $3,912 million thereafter forwhich cover a total of $5,840 million. These interest payments reflect our contractual obligations at December 31, 2018.
|
(b)
| On January 1, 2019, we will adopt ASC 842, Leases, which will result in operating lease commitments greater than one year being reflected on our Consolidated Balance Sheet. See Note 1, Nature of Operations, Basis of Presentation and Summary of Accounting Policies, in the Notes to Consolidated Financial Statements for further details.
|
(c)
| Comprises obligations where we, as operator, have contracted directly with suppliers.
|
Capital expenditures represent amounts that we were contractually committed at December 31, 2018, including the portion of our planned capital expenditure program in 2022 and include commitments for 2019. Obligationsoil and gas production expenses, transportation and related contracts, seismic purchases and other normal business expenses.
Our long-term cash obligations and commitments include:
•Debt and interest: See Note 7, Debt in the Notes to Consolidated Financial Statements.
•Operating and finance leases: The Corporation and certain of its subsidiaries lease drilling rigs, equipment, logistical assets (offshore vessels, aircraft, and shorebases), and office space for varying periods. See Note 6, Leases in the Notes to Consolidated Financial Statements.
•Purchase obligations:We were contractually committed at December 31, 2021 for certain long-term capital expenditures and operating expenses. Long-term obligations for operating expenses include commitments for oil and gas production expenses, transportation and related contracts, seismic purchases and other normal business expenses. Other liabilities reflect contractually committed obligationsSee Note 18, Guarantees, Contingencies and Commitments in the Notes to Consolidated Balance Sheet at December 31, 2018,Financial Statements.
•Asset retirement obligations:See Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements.
•Post-retirement plan liabilities:We have certain unfunded post-retirement plans, including pension plan liabilities and estimates for uncertainour post-retirement medical plan. See Note 9, Retirement Plans in the Notes to Consolidated Financial Statements.
•Uncertain income tax positions. The Corporation and certain of its subsidiaries lease drilling rigs, support vessels, office space and other assets for varying periods under leases accounted for as operating leases.positions: See Note 15, Income Taxes in the Notes to Consolidated Financial Statements.
Off-Balance Sheet Arrangements
At December 31, 2018,2021, we had $284$259 million in letters of credit. See also Note 19,18, Guarantees, Contingencies and Commitments in the Notes to Consolidated Financial Statements. We conduct E&P activities outside the U.S., principally in Guyana, the Joint Development Area of Malaysia/Thailand, and Malaysia, Denmark, Libya, Guyana, Suriname, and Canada. Therefore, we are subject to the risks associated with foreign operations, including political risk, tax law changes, currency risk, corruption and acts of terrorism. See Item 1A. Risk Factors for further details.
Critical Accounting Policies and Estimates
Accounting policies and estimates affect the recognition of assets and liabilities in the Consolidated Balance Sheet and revenues and expenses in the Statement of Consolidated Income. The accounting methods used can affect net income, equity and various financial statement ratios. However, our accounting policies generally do not change cash flows or liquidity. Accounting for Exploration and Development Costs: E&P activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized. The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of the project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves, and the economic and operating viability of a project include: commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors and firm plans for additional drilling and other factors.
Crude Oil and Natural Gas Reserves: The determination of estimated proved reserves is a significant element in arriving at the results of operations of E&P activities. The estimates of proved reserves affect well capitalizations, the unit of production depreciation rates of proved properties and wells and equipment, as well as impairment testing of oil and gas assets. For reserves to be booked as proved they must be determined with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. In addition, government and project operator approvals must be obtained and, depending on the amount of the project cost, senior management or the Board of Directors must commit to fund the project. We maintain our own internal reserve estimates that are calculated by technical staff that work directly with the oil and gas properties. Our technical staff
updatesupdate reserve estimates throughout the year based on evaluations of new wells, performance reviews, new technical data and other studies. To provide consistency throughout the Corporation, standard reserve estimation guidelines, definitions, reporting reviews and approval practices are used. The internal reserve estimates are subject to internal technical audits and senior management review. We also engage an independent third-party consulting firm to audit approximately 80% of our total proved reserves each year.
Proved reserves are calculated using the average price during the twelve-month period ending December 31 determined as an unweighted arithmetic average of the price on the first day of each month within the year, unless prices are defined by contractual agreements, excluding escalations based on future conditions. As discussed in Item 1A. Risk Factors, crude oil prices are volatile which can have an impact on our proved reserves. Crude oil prices used in the determination of proved reserves at December 31, 2021 were $66.34 per barrel for WTI (2020: $39.77) and $68.92 per barrel for Brent (2020: $43.43). At December 31, 2021, spot prices closed at $75.21 per barrel for WTI and $77.02 per barrel for Brent. If crude oil prices in 20192022 are at levels below that used in determining 20182021 proved reserves, we may recognize negative revisions to our December 31, 20192022 proved undeveloped reserves. In addition, we may recognize negative revisions to proved developed reserves, which can vary significantly by asset due to differing operating cost structures. Conversely, price increases in 20192022 above those used in determining 20182021 proved reserves could result in positive revisions to proved developed and proved undeveloped reserves at December 31, 2019.2022. It is difficult to estimate the magnitude of any potential net negative or positive change in proved reserves at December 31, 2019,2022, due to numerous currently unknown factors, including 20192022 crude oil prices, the amount of any additions to proved reserves, positive or negative revisions based on 2019in
proved reserves related to 2022 reservoir performance, and the levels to which industry costs will change in response to movements in commodity prices.2022 crude oil prices, and management’s plans as of December 31, 2022 for developing proved undeveloped reserves. A 10% change in proved developed and proved undeveloped reserves at December 31, 20182021 would result in an approximate $200$165 million pre-tax change in depreciation, depletion, and amortization expense for 20192022 based on projected production volumes. See the Supplementary Oil and Gas Data on pages 8289 through 9298 in the accompanying financial statements for additional information on our oil and gas reserves.
Midstream Joint Venture: We consolidate the activities of our 50/50 joint venture HIP, which qualifies as a variable interest entity (VIE) under U.S. generally accepted accounting principles. We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power through our 50% ownership to direct those activities that most significantly impact the economic performance of HIP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to HIP. This conclusion was based on a qualitative analysis that considered HIP’s governance structure, the commercial agreements between HIP and us, and the voting rights established between the members, which provide us the ability to control the operations of HIP.
Impairment of Long-lived Assets: We review long‑lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. Long‑lived assets are tested based on identifiable cash flows that are largely independent of the cash flows of other assets and liabilities. If the carrying amounts of the long-lived assets are not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is determinedmeasured based on the estimated fair value of the assets generally determined by discounting anticipated future net cash flows, an income valuation approach, or by a market‑based valuation approach, which are Level 3 fair value measurements.
In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a stipulated amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairment will generally differ from those used in the standardized measure of discounted future net cash flows, since the standardized measure requires the use of historical twelve-month average prices.
Our impairment tests of long-lived E&P producing assets are based on our best estimates of future production volumes (including recovery factors), selling prices, operating and capital costs, the timing of future production and other factors, which are updated each time an impairment test is performed.
While crude oil prices in 2018 were higher than the last few years, weWe could experience an
asset impairment in the future if
one or a combination of the following occur: the projected production volumes from oil and gas fields decrease, crude oil and natural gas selling prices decline significantly for an extended period or future estimated capital and operating costs increase significantly.
Impairment
As a result of Goodwill: Goodwill is testedthe significant decline in crude oil prices due to the economic slowdown from COVID-19, we reviewed our oil and gas fields and midstream operating segment asset groups for impairment annually on October 1st or when events or circumstances indicateat March 31, 2020. We impaired various oil and gas fields located in Malaysia, Denmark, and the Gulf of Mexico in the first quarter of 2020 primarily as a result of a lower long-term crude oil price outlook. See Note 12, Impairment and Other in the Notes to Consolidated Financial Statements for further details.
Hess Midstream LP: We consolidate the activities of our interest inHess Midstream LP, which qualifies as a variable interest entity (VIE) under U.S. generally accepted accounting principles. We have concluded that we are the carrying amountprimary beneficiary of the goodwill may not be recoverable. We conduct the goodwill test at a reporting unit level, which isVIE, as defined in the accounting standards, as an operating segmentsince we have the power through Hess Corporation’s approximate 43.5% consolidated ownership interest inHess Midstream LPto direct those activities that most significantly impact the economic performance ofHess Midstream LP, and are obligated to absorb losses or one level below an operating segment. The reporting unit or units used in an evaluation and measurement of goodwill for impairment testing are determined from several factors, includinghave the manner in which the business is managed. At December 31, 2018, ourright to receive benefits that could potentially be significant toHess Midstream operating segment had goodwill of $360 million that resulted from an allocation from our E&P segment upon the formation of the Midstream segment in 2015. Our E&P segment has no goodwill at December 31, 2018.To determine whether an indicator of impairment exists, the fair value of a reporting unit is compared with its carrying amount, including goodwill. If the fair value of the reporting unit exceeds its carrying value, goodwill is not impaired. If the carrying value of the reporting unit exceeds its fair value, an impairment charge would be recorded for the excess of the carrying value over fair value, limited by the amount of goodwill allocated to the reporting unit.
Fair value for the Midstream operating segment isLP
. This conclusion was based on a market approach, whereby the market capitalization of qualitative analysis that consideredHess Midstream Partners, LP’s (the Partnership),LP’s governance structure, the commercial agreements betweenHess Midstream LPand us, and the voting rights established between the members, which represents an approximate 20% economic interest inprovide us the operating companies that compriseability to control the operations ofHess Midstream segment, is adjusted to an amount equal to a 100% economic interest in the operating companies based on the Partnership’s stock price at the time of the impairment test. Other adjustments made to compute fair value include estimating the fair value of other minor Midstream assets not owned by the Partnership and long-term debt held directly by HIP.LP
. Income Taxes: Judgments are required in the determination and recognition of income tax assets and liabilities in the financial statements. These judgments include the requirement to only recognize the financial statement effect of a tax position only when management believes that it is more likely than not, that based on the technical merits, that the position will be sustained upon examination. We have net operating loss carryforwards or credit carryforwards in multiple jurisdictions and have recorded deferred tax assets for those losses and credits. Additionally, we have deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If, when tested under the relevant accounting standards, it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount that is expected to be realized.
The accounting standards require the evaluation of all available positive and negative evidence giving weight based on the evidence’s relative objectivity. In evaluating potential sources of positive evidence, we consider the reversal of taxable temporary differences, taxable income in carryback and carryforward periods, the availability of tax planning strategies, the existence of appreciated assets, estimates of future taxable income, and other factors. Estimates of future taxable income are based on assumptions of oil and gas reserves, selling prices, and other subjective operating assumptions that are consistent with internal business forecasts. In evaluating potential sources of negative evidence, we consider a cumulative loss in recent years, any history of operating losses or tax credit carryforwards expiring unused, losses expected in early future years, unsettled circumstances that, if unfavorably resolved, would adversely affect future operations and profit levels on a continuing basis in future years, and any carryback or carryforward periods that areperiod so brief that it would limit realization of tax benefits if a significant deductible temporary difference is expected to reverse in a single year.year would limit realization of tax benefits. Due to a sustained low commodity price environment, we remained in a three-year cumulative loss
position, both on a consolidated
loss positionbasis and for certain jurisdictions, at December 31,
2018.2021. A three-year cumulative
consolidated loss constitutes objective negative evidence to which the accounting standards require we assign significant weight relative to subjective evidence such as our estimates of future taxable income.
We are generally not recognizing deferred tax benefit or expense in certain countries, primarily the U.S. (non-Midstream), Denmark (hydrocarbon tax only)(sold in August 2021), Malaysia, and Guyana,Malaysia, while we maintain valuation allowances against net deferred tax assets in these jurisdictions. At December 31, 2018,2021, the ConsolidatedBalance Sheet reflects a $4,877$3,838 million valuation allowance against the net deferred tax assets for multiple jurisdictions based on the evaluation of the accounting standards described above. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income change or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as expected future growth. Asset Retirement Obligations: We have material legal obligations to remove and dismantle long‑lived assets and to restore land or seabed at certain E&P locations. In accordance with generally accepted accounting principles, we recognize a liability for the fair value of required asset retirement obligations. In addition, the fair value of any legally required conditional asset retirement obligation is recorded if the liability can be reasonably estimated. We capitalize such costs as a component of the carrying amount of the underlying assets in the period in which the liability is incurred. In subsequent periods, the liability is accreted, and the asset is depreciated over the useful life of the related asset. We estimate the fair value of these obligations by discounting projected future payments that will be required to satisfy the obligations. In determining these estimates, we are required to make several assumptions and judgments related to the scope of dismantlement, timing of settlement, interpretation of legal requirements, inflationary factors and discount rate. In addition, there are other external factors, which could significantly affect the ultimate settlement costs or timing for these obligations including changes in environmental regulations and other statutory requirements, fluctuations in industry costs and foreign currency exchange rates and advances in technology. As a result, our estimates of asset retirement obligations are subject to revision due to the factors described above. Changes in estimates prior to settlement result in adjustments to both the liability and related asset values, unless the field has ceased production, in which case changes are recognized in ourConsolidated Statement of Income. See Note 9, 8,Asset Retirement Obligations.
Retirement Plans: We have funded non-contributory defined benefit pension plans, an unfunded supplemental pension plan and an unfunded postretirement medical plan. We recognize the net change in the funded status of the projected benefit obligation for these plans in theConsolidated Balance Sheet.The determination of the obligations and expenses related to these plans are based on several actuarial assumptions. These assumptions represent estimates made by us, some of which can be affected by external factors. The most significant assumptions relate to:
Discount raterates used for measuring the present value of future plan obligations:obligations and net periodic benefit cost: The discount raterates used to estimate our projected benefit obligationobligations and net periodic benefit cost is based on a portfolio of high‑quality, fixed income debt instruments with maturities that approximate the expected payment of plan obligations. At December 31, 2018,2021, a 0.25% decrease in the discount rate assumptionassumptions would increase projected benefit obligations by approximately $100$130 million and would increase forecasted 20192022 annual net periodic benefit expense by approximately $5$10 million. The increase in the projected benefit obligationobligations would decrease the funded status of our pension plans, but any decrease in the funded status would be partially mitigated by increases in the fair value of fixed income investments in the asset portfolio.portfolios.
Expected long-term rates of returns on plan assets: The expected return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of pensionplan assets to that asset category. TheThe future expected return assumptions for individual asset categories are largely based on inputs from various investment experts regarding their future return expectations for particular asset categories. At December 31, 2018,2021, a 0.25% decrease in the expected long-term rates of returnsreturn on plan assets assumption would increase forecasted 20192022 annual net periodic benefit expense by approximately $5$10 million. Other assumptions include the rate of future increases in compensation levels and
expected participant
mortality level.mortality.
Derivatives: We utilize derivative instruments, including futures, forwards, options and swaps, individually or in combination to mitigate our exposure to fluctuations in the prices of crude oil and natural gas, as well as changes in interest and foreign currency exchange rates. All derivative instruments are recorded at fair value in ourConsolidated Balance Sheet. Our policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not designated as hedges are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges), or hedges of changes in fair value of recognized assets and liabilities or of unrecognized firm commitments (fair value hedges). Changes in fair value of derivatives that are designated as cash flow hedges are recorded as a component of other comprehensive income (loss). Amounts included in Accumulated other comprehensive income (loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged commitmentitem is recorded as an adjustment to its carrying amount and recognized currently in earnings.
Fair Value Measurements: We use various valuation approaches in determining fair value for financial instruments, including the market and income approaches. Our fair value measurements also include non-performance risk and time value of money considerations. Counterparty credit is considered for receivable balances,financial assets, and our credit is considered for accruedfinancial liabilities. We also record certain nonfinancial assets and liabilities at fair value when required by generally accepted accounting principles. These fair value measurements are recorded in connection with business combinations, qualifying non-monetary exchanges, the initial recognition of asset retirement obligations and any impairment of long-lived assets, equity method investments or goodwill.
We determine fair value in accordance with the fair value measurements accounting standard which established a hierarchy for the inputs used to measure fair value based on the source of the inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3), including
discounted cash flows and other unobservable data.data. Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market. Multiple inputs may be used to measure fair value; however, the level
ofassigned to a fair value
assigned for each physical derivative and financial asset or liabilitymeasurement is based on the lowest significant input level within this fair value hierarchy.
Environment, Health and Safety
Our long-term vision and values provide a foundation for how we do business and define our commitment to meeting high standards of corporate citizenship and creating a long lasting positive impact on the communities where we do business. Our strategy is reflected in our
environment, health, safety and social responsibility (EHSEHS &
SR)SR policies and by a management system framework that helps protect our workforce, customers and local communities. Our management systems are intended to promote internal consistency, adherence to policy objectives and continual improvement in EHS & SR performance. Improved performance may, in the short‑term, increase our operating costs and could also require increased capital expenditures to reduce potential risks to our assets, reputation and license to operate. In addition to enhanced EHS & SR performance, improved productivity and operational efficiencies may be realized from investments in EHS & SR. We have programs in place to evaluate regulatory compliance, audit facilities, train employees, prevent and manage risks and emergencies and to generally meet corporate EHS & SR goals and objectives.
Environmental Matters
We recognize that climate change is a global environmental concern. We assess, monitor and take measures to reduce our carbon footprint at existing and planned operations. The EPA has adopted a series of GHG monitoring, reporting, and emissions control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting further legislation to reduce GHG emissions. For example, in November 2021, the EPA proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. The EPA is currently seeking public comments on its proposal, which the EPA hopes to finalize by the end of 2022. In addition, states have taken measures to reduce emissions of GHGs, primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs. At the international level, the Paris Agreement on climate change aimed to enhance global response to global temperature changes and to reduce GHG emissions, among other things. We are committed to complying with all Greenhouse Gas (GHG)GHG emissions mandatesregulations that apply to our operations, including those related to venting or flaring of natural gas, and the responsible management of GHG emissions at our facilities. While we monitor climate-related regulatory initiatives and international public policy issues, the current state of ongoing international climate initiatives and any related domestic actions make it difficult to assess the timing or effect on our operations or to predict with certainty the future costs that we may incur in order to comply with future international treaties, legislation or new regulations. However, future restrictions on emissions of GHGs, or related measures to encourage use of low carbon energy could result in higher capital expenditures and operating expenses for us and the oil and gas industry in general and may reduce demand for our products, as described under
Regulatory, Legal and Environmental Risks in Item 1A. Risk Factors. We will have continuing expenditures for environmental assessment and remediation. Sites where corrective action may be necessary include onshore E&P facilities, sites from discontinued operations where we retained liability and, although not currently significant, EPA “Superfund” sites where we have been named a potentially responsible party.We accrue for environmental assessment and remediation expenses when the future costs are probable and reasonably estimable. For additional information, see
Item 3. Legal Proceedings. At December 31, 2018,2021, our reserve for estimated remediation liabilities was approximately $80$60 million. We expect that existing reserves for environmental liabilities will adequately cover costs to assess and remediate known sites. Our remediation spending was approximately $15$16 million in 2018 (2017:2021 (2020: $15 million; 2016: $102019: $20 million). The amount of other expenditures incurred to comply with federal, state, local and foreign country environmental regulations is difficult to quantify as such costs are captured as mostly indistinguishable components of our capital expenditures and operating expenses. As an element of our EHS and SR strategy, we purchase carbon credits annually to offset 100 percent of our estimated Scope 3 business travel emissions and 100 percent of our estimated Scope 1 and Scope 3 emissions associated with operating the Corporation’s truck fleet, aviation activities (aircraft and helicopters) and personal and rental vehicle miles driven on company business. We also
offset purchased electricity used in our operations from nonrenewable sources by purchasing renewable energy credits. The cost of purchased carbon and renewable energy credits was not material to our financial results in 2021 and was included in Operating costs and expenses in the Statement of Consolidated Income.
ItemHealth and Safety Matters
The crude oil and natural gas industry is regulated at federal, state, local and foreign government levels regarding the health and safety of E&P operations. Such laws and regulations relate to, among other matters, occupational safety, the use of hydraulic fracturing to stimulate crude oil and natural gas production, well control and integrity, process safety and equipment integrity, and may include permitting and disclosure requirements, operating restrictions and other conditions on the development of crude oil and natural gas. The level of our expenditures to comply with federal, state, local and foreign country health and safety regulations is difficult to quantify as such costs are captured as mostly indistinguishable components of our capital expenditures and operating expenses. While compliance with laws and regulations relating to health and safety matters increases the overall cost of business for us and the oil and gas industry in general, it has not had, to date, a material adverse effect on our operations, financial condition or results of operations.
Occupational Safety: We are subject to the requirements set forth under federal workplace standards by the OSHA and comparable state statutes that regulate the protection of the health and safety of workers. Under OSHA and other federal and state occupational safety and health laws and laws of foreign countries in which we operate, we must develop, maintain and disclose certain information about hazardous materials used, released, or produced in our operations.
Production and Well Integrity: Our U.S. onshore production facilities are subject to U.S. federal government, state and local regulations regarding the use of hydraulic fracturing and well control and integrity. Our offshore production facilities in the Gulf of Mexico are subject to the U.S. federal government’s Safety and Environmental Management System regulations, which provide a systematic approach for identifying, managing and mitigating hazards. Adapting to new technical standards and procedures in production and in our well integrity management system is fundamental to our aim of protecting the environment as well as the health and safety of our workforce and the communities in which we operate, and to safeguarding our product.
Process Safety and Equipment Integrity: We are also regulated at federal, state, local and foreign government levels regarding process safety and the integrity of our equipment, including OSHA’s Process Safety Management of Highly Hazardous Chemicals standard. ICE are barriers and safeguards that prevent or mitigate process safety incidents through detection, isolation, containment, control or emergency preparedness and response within our facilities. We have established ICE performance standards, which set specific requirements and criteria for inspections and tests that help to ensure ICE barriers are effective. We conduct assessments collaboratively with our operated assets, subject matter experts and technical authorities to evaluate compliance with corporate and asset environment, health and safety standards and procedures, as well as with applicable regulations. For additional information on our emergency response and incident mitigation activities, see Emergency Preparedness and Response Plans and Procedures in Items 1 and 2. Business and Properties.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
In the normal course of our business, we are exposed to commodity risks related to changes in the prices of crude oil,
natural gas liquids,NGL, and natural gas as well as changes in interest rates and foreign currency values. In the disclosures that follow, financial risk management activities refer to the mitigation of these risks through hedging activities.
Controls: We maintain a control environment under the direction of our Chief Risk Officer. Controls over instruments used in financial risk management activities include volumetric and term limits. Our Treasury department is responsible for administering and monitoring foreign exchange rate and interest rate hedging programs using similar controls and processes, where applicable. Hedging strategies are reviewed annually by the Audit Committee of the Board of Directors. Instruments: We primarily use forward commodity contracts, foreign exchange forward contracts, futures, swaps, and options in our risk management activities. These contracts are generally widely traded instruments with standardized terms. The following describes these instruments and how we use them: | •
| Swaps: We use financially settled swap contracts with third-parties as part of our financial risk management activities. Cash flows from swap contracts are determined based on underlying commodity prices or interest rates and are typically settled over the life of the contract.
| |
| •
| Forward Foreign Exchange Contracts: We enter into forward contracts, primarily for the British Pound, which commit us to buy or sell a fixed amount of British Pound at a predetermined exchange rate on a future date.
| |
•Swaps: We use financially settled swap contracts with third parties as part of our financial risk management activities. Cash flows from swap contracts are determined based on underlying commodity prices or interest rates and are typically settled over the life of the contract. | •
| Exchange Traded Contracts: We may use exchange traded contracts, including futures, on a number of different underlying energy commodities. These contracts are settled daily with the relevant exchange and may be subject to exchange position limits.
| |
•Forward Foreign Exchange Contracts: We enter into forward contracts, primarily for the British Pound, Canadian Dollar and Malaysian Ringgit, which commit us to buy or sell a fixed amount of those currencies at a predetermined exchange rate on a future date. | •
| Options: Options on various underlying energy commodities include exchange traded and third-party contracts and have various exercise periods. As a seller of options, we receive a premium at the outset and bear the risk of unfavorable changes in the price of the commodity underlying the option. As a purchaser of options, we pay a premium at the outset and have the right to participate in the favorable price movements in the underlying commodities.
| |
•Exchange-traded Contracts: We may use exchange-traded contracts, including futures, on a number of different underlying energy commodities. These contracts are settled daily with the relevant exchange and may be subject to exchange position limits.•Options: Options on various underlying energy commodities include exchange-traded and third-party contracts and have various exercise periods. As a purchaser of options, we pay a premium at the outset and are exposed to the favorable consequence of collecting payment upon exercise depending upon the underlying commodity price movement. As a seller of options, we receive a premium at the outset and are exposed to the unfavorable consequence of having to make payment upon exercise depending upon the underlying commodity price movement.
Financial Risk Management Activities
At December 31, 2018, outstanding total debt, excluding capital leases, was substantially comprised of fixed rate debt instruments with a carrying value of $6,403 million and a fair value of $6,225 million. A 15% increase or decrease in interest rates would decrease or increase the fair value of our fixed rate debt by approximately $480 million or $550 million, respectively. Any changes in interest rates do not impact cash outflows associated with fixed rate interest payments or settlement of debt principal, unless a debt instrument is repurchased prior to maturity.
At December 31, 2018, we have outstanding WTI crude oil put contracts for calendar year 2019 with a WTI monthly floor price of $60 per barrel for 95,000 bopd. At December 31, 2018, an assumed 10% increase in the forward WTI crude oil prices used in determining the fair value of our crude oil put contracts would reduce the fair value of these derivatives instruments by approximately $120 million, while an assumed 10% decrease in the same WTI crude oil prices would increase the fair value of these derivative instruments by approximately $140 million.
We have outstanding foreign exchange contracts with
a total notional
amount of $16amounts totaling $145 million at December 31,
20182021 that are used to reduce our exposure to fluctuating foreign exchange rates for various currencies. The change in fair value of foreign exchange contracts from a 10%
strengthening or weakening
ofin the U.S. Dollar exchange rate is estimated to be a
gain or loss of
less thanapproximately $5 million,
respectively, at December 31,
2018.2021.
At December 31, 2021, our total long-term debt, which was substantially comprised of fixed-rate instruments, had a carrying value of $8,458 million and a fair value of $9,897 million. A 15% increase or decrease in interest rates would decrease or increase the fair value of debt by approximately $390 million or $405 million, respectively. Any changes in interest rates do not impact our cash outflows associated with fixed-rate interest payments or settlement of debt principal, unless a debt instrument is repurchased prior to maturity.
For calendar year 2022, we have WTI collars with an average monthly floor price of $60 per barrel and an average monthly ceiling price of $100 per barrel for 90,000 bopd, and Brent collars with an average monthly floor price of $65 per barrel and an average monthly ceiling price of $105 per barrel for 60,000 bopd. As of December 31, 2021, an assumed 10% increase in the forward WTI and Brent crude oil prices used in determining the fair value of our collars would reduce the fair value of these derivative instruments by approximately $100 million, while an assumed 10% decrease in the same crude oil prices would increase the fair value of these derivative instruments by approximately $100 million.
See Note21,20, Financial Risk Management Activities, in the Notes to Consolidated Financial Statementsfor further details. details.
Item 8. Financial Statements and Supplementary Data
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS
*
Schedules have been omitted because of the absence of the conditions under which they are required or because the required information is presented in the financial statements or the notes thereto.
Management’s Report on Internal Control over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a‑15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes‑Oxley Act, based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on our evaluation, management concluded that our internal control over financial reporting was effective as of December 31,
2018.2021.
The Corporation’s independent registered public accounting firm, Ernst & Young LLP, has audited the effectiveness of the Corporation’s internal control over financial reporting as of December 31,
2018,2021, as stated in their report, which is included herein.
By
| | | | | | | | | | | | | | | | | | | | |
| By | | /s/ John P. Rielly | | By | | /s/ John B. Hess |
| | John P. Rielly Senior
Executive Vice President and
Chief Financial Officer
| | | | John B. Hess
Chief Executive Officer
|
February 21, 2019
March 1, 2022
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Opinion on Internal Control over Financial Reporting
We have audited Hess Corporation and consolidated subsidiaries’ (the “Corporation”) internal control over financial reporting as of December 31,
2018,2021, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Hess Corporation and consolidated subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31,
2018,2021, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Corporation as of December 31,
20182021 and
2017,2020, the related statements of consolidated income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31,
2018,2021, and the related notes and our report dated
February 21, 2019March 1, 2022 expressed an unqualified opinion thereon.
The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
New York, New York
February 21, 2019
March 1, 2022
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Hess Corporation and consolidated subsidiaries (the “Corporation”) as of December 31,
20182021 and
2017,2020, the related statements of consolidated income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31,
2018,2021, and the related notes (collectively referred to as the
“financial“consolidated financial statements”). In our opinion, the
consolidated financial statements present fairly, in all material respects, the
consolidated financial position of the Corporation at December 31,
20182021 and
2017,2020, and the
consolidated results of its operations and its cash flows for each of the three years in the period ended December 31,
2018,2021, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Corporation’s internal control over financial reporting as of December 31,
2018,2021, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated
February 21, 2019March 1, 2022 expressed an unqualified opinion thereon.
These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on the Corporation’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
| | | | | | | | |
| | Depreciation, depletion and amortization of proved oil and natural gas properties |
Description of the
Matter
| | The net book value of the Corporation’s exploration and production assets was $11,047 million at December 31, 2021, and depreciation, depletion and amortization (DD&A) expense was $1,361 million for the year then ended. As described in Note 1 to the financial statements, the Corporation follows the successful efforts method of accounting for its oil and gas exploration and production activities. Under the successful efforts method of accounting, DD&A expense is recorded using the units-of-production method, based on proved oil and gas reserves, as estimated by petroleum engineering specialists, for property acquisition costs and proved developed oil and gas reserves, also estimated by petroleum engineering specialists, for oil and gas production facilities and wells. Proved oil and gas reserves are based on geological and engineering evaluations of estimated in-place hydrocarbon volumes using financial and non-financial inputs. Significant judgment is required by the Corporations’ internal engineering staff in evaluating the geological and engineering data used to estimate reserves. Estimating proved reserves also requires the selection of inputs, including oil and natural gas price assumptions, future operating and capital costs assumptions and tax rates by jurisdiction, among others. Management used independent petroleum engineering specialists to audit |
| | | | | | | | |
| | approximately 88% of the Corporation’s proved reserves at December 31, 2021 as prepared by the Corporation’s internal engineering staff.
Auditing the Corporation’s DD&A expense calculation is complex because of our need to assess the reasonableness of management’s determination of the inputs described above used in estimating proved oil and gas reserves and to use the work of the internal engineering staff and independent petroleum engineering specialists. |
| | |
| How We Addressed the Matter in Our Audit | | We obtained an understanding, evaluated the design and tested the operating effectiveness of internal controls that address the risks of material misstatement relating to the DD&A expense calculation. This included controls over the completeness and accuracy of the financial data used in estimating proved oil and gas reserves.
Our testing of the Corporation’s DD&A expense calculation included, among other procedures, evaluating the professional qualifications and objectivity of the Corporation’s internal petroleum engineering specialist responsible for overseeing the preparation of the Corporation’s reserve estimates and of the independent petroleum engineering specialist used to audit the estimates.In addition, we tested the completeness and accuracy of the financial data used in the estimation of proved oil and gas reserves by agreeing significant inputs to source documentation, where available, on a sample basis and assessing the inputs for reasonableness based on review of corroborative evidence and consideration of any contrary evidence.Additionally, we performed analytic and lookback procedures on inputs into the oil and gas reserve estimate as well as on the outputs.Finally, we tested the mathematical accuracy of the DD&A expense calculations, including comparing the proved oil and gas reserves to the Corporation’s reserve report. |
We have served as the Corporation’s auditor since 1971
New York, New York
February 21, 2019
March 1, 2022
HESS
CORPORATIONCORPORATION AND CONSOLIDATED SUBSIDIARIESCONSOLIDATED BALANCE SHEET
| | | December 31, | | | December 31, |
| | 2018 | | | 2017 | | | 2021 | | 2020 |
| | (In millions, | | | | | |
| | except share amounts) | | | (In millions,
except share amounts) |
Assets | | | | | | | | | Assets | | | |
Current Assets: | | | | | | | | | Current Assets: | | | |
Cash and cash equivalents | | $ | 2,694 | | | $ | 4,847 | | Cash and cash equivalents | $ | 2,713 | | | $ | 1,739 | |
Accounts receivable: | | | | | | | | | Accounts receivable: | |
From contracts with customers | | | 771 | | | | 677 | | From contracts with customers | 1,062 | | | 710 | |
Joint venture and other | | | 230 | | | | 347 | | Joint venture and other | 149 | | | 150 | |
Inventories | | | 245 | | | | 232 | | Inventories | 223 | | | 378 | |
Other current assets | | | 519 | | | | 54 | | Other current assets | 199 | | | 104 | |
Total current assets | | | 4,459 | | | | 6,157 | | Total current assets | 4,346 | | | 3,081 | |
Property, plant and equipment: | | | | | | | | | Property, plant and equipment: | | | |
Total — at cost | | | 33,222 | | | | 32,504 | | Total — at cost | 31,178 | | | 30,519 | |
Less: Reserves for depreciation, depletion, amortization and lease impairment | | | 17,139 | | | | 16,312 | | Less: Reserves for depreciation, depletion, amortization and lease impairment | 16,996 | | | 16,404 | |
Property, plant and equipment — net | | | 16,083 | | | | 16,192 | | Property, plant and equipment — net | 14,182 | | | 14,115 | |
| Operating lease right-of-use assets — net | | Operating lease right-of-use assets — net | 352 | | | 426 | |
| Finance lease right-of-use assets — net | | Finance lease right-of-use assets — net | 144 | | | 168 | |
| Post-retirement benefit assets | | Post-retirement benefit assets | 409 | | | 45 | |
Goodwill | | | 360 | | | | 360 | | Goodwill | 360 | | | 360 | |
Deferred income taxes | | | 21 | | | | 21 | | Deferred income taxes | 71 | | | 59 | |
Other assets | | | 510 | | | | 382 | | Other assets | 651 | | | 567 | |
Total Assets | | $ | 21,433 | | | $ | 23,112 | | Total Assets | $ | 20,515 | | | $ | 18,821 | |
Liabilities | | | | | | | | | Liabilities | | | |
Current Liabilities: | | | | | | | | | Current Liabilities: | |
Accounts payable | | $ | 495 | | | $ | 435 | | Accounts payable | $ | 220 | | | $ | 200 | |
Accrued liabilities | | | 1,560 | | | | 1,337 | | Accrued liabilities | 1,710 | | | 1,251 | |
Taxes payable | | | 81 | | | | 83 | | Taxes payable | 528 | | | 81 | |
Current maturities of long-term debt | | | 67 | | | | 580 | | |
| Current portion of long-term debt | | Current portion of long-term debt | 517 | | | 10 | |
| Current portion of operating and finance lease obligations | | Current portion of operating and finance lease obligations | 89 | | | 81 | |
Total current liabilities | | | 2,203 | | | | 2,435 | | Total current liabilities | 3,064 | | | 1,623 | |
Long-term debt | | | 6,605 | | | | 6,397 | | Long-term debt | 7,941 | | | 8,286 | |
| Long-term operating lease obligations | | Long-term operating lease obligations | 394 | | | 478 | |
| Long-term finance lease obligations | | Long-term finance lease obligations | 200 | | | 220 | |
Deferred income taxes | | | 421 | | | | 429 | | Deferred income taxes | 383 | | | 342 | |
Asset retirement obligations | | | 741 | | | | 753 | | Asset retirement obligations | 1,005 | | | 894 | |
Other liabilities and deferred credits | | | 575 | | | | 744 | | Other liabilities and deferred credits | 502 | | | 643 | |
Total Liabilities | | | 10,545 | | | | 10,758 | | Total Liabilities | 13,489 | | | 12,486 | |
Equity | | | | | | | | | Equity | | | |
Hess Corporation stockholders’ equity: | | | | | | | | | Hess Corporation stockholders’ equity: | |
Preferred stock, par value $1.00; Authorized — 20,000,000 shares: | | | | | | | | | |
Series A 8% Cumulative Mandatory Convertible; $1,000 per share liquidation preference; Issued — 574,997 shares (2017: 575,000) | | | 1 | | | | 1 | | |
Common stock, par value $1.00; Authorized — 600,000,000 shares: | | | | | | | | | Common stock, par value $1.00; Authorized — 600,000,000 shares: | |
Issued — 291,434,534 shares (2017: 315,053,615) | | | 291 | | | | 315 | | |
| Issued — 309,744,953 shares (2020: 306,980,092) | | Issued — 309,744,953 shares (2020: 306,980,092) | 310 | | | 307 | |
Capital in excess of par value | | | 5,386 | | | | 5,824 | | Capital in excess of par value | 6,017 | | | 5,684 | |
Retained earnings | | | 4,257 | | | | 5,597 | | Retained earnings | 379 | | | 130 | |
Accumulated other comprehensive income (loss) | | | (306 | ) | | | (686 | ) | Accumulated other comprehensive income (loss) | (406) | | | (755) | |
Total Hess Corporation stockholders’ equity | | | 9,629 | | | | 11,051 | | Total Hess Corporation stockholders’ equity | 6,300 | | | 5,366 | |
Noncontrolling interests | | | 1,259 | | | | 1,303 | | Noncontrolling interests | 726 | | | 969 | |
Total equity | | | 10,888 | | | | 12,354 | | Total equity | 7,026 | | | 6,335 | |
Total Liabilities and Equity | | $ | 21,433 | | | $ | 23,112 | | Total Liabilities and Equity | $ | 20,515 | | | $ | 18,821 | |
The consolidated financial statements reflect the successful efforts method of accounting for oil and gas exploration and production activities.
See accompanying Notes to Consolidated Financial Statements.
HESS
CORPORATIONCORPORATION AND CONSOLIDATED SUBSIDIARIESSTATEMENT OF CONSOLIDATED INCOME
| | | | | Year Ended December 31, |
| | Years Ended December 31, | | | 2021 | | 2020 | | 2019 |
| | 2018 | | | 2017 | | | 2016 | | | | | | | |
| | (In millions, except per share amounts) | | | (In millions, except per share amounts) |
Revenues and Non-Operating Income | | | | | | | | | | | | | Revenues and Non-Operating Income | | | | | |
Sales and other operating revenues | | $ | 6,323 | | | $ | 5,466 | | | $ | 4,762 | | Sales and other operating revenues | $ | 7,473 | | | $ | 4,667 | | | $ | 6,495 | |
Gains (losses) on asset sales, net | | | 32 | | | | (86 | ) | | | 23 | | |
| Gains on asset sales, net | | Gains on asset sales, net | 29 | | | 87 | | | 22 | |
Other, net | | | 111 | | | | 11 | | | | 54 | | Other, net | 81 | | | 50 | | | (7) | |
Total revenues and non-operating income | | | 6,466 | | | | 5,391 | | | | 4,839 | | Total revenues and non-operating income | 7,583 | | | 4,804 | | | 6,510 | |
| | | | | | | | | | | | | | | | | | |
Costs and Expenses | | | | | | | | | | | | | Costs and Expenses | |
Marketing, including purchased oil and gas | | | 1,771 | | | | 1,267 | | | | 1,063 | | Marketing, including purchased oil and gas | 2,034 | | | 936 | | | 1,736 | |
Operating costs and expenses | | | 1,134 | | | | 1,443 | | | | 1,876 | | Operating costs and expenses | 1,229 | | | 1,218 | | | 1,237 | |
Production and severance taxes | | | 171 | | | | 119 | | | | 101 | | Production and severance taxes | 172 | | | 124 | | | 184 | |
Exploration expenses, including dry holes and lease impairment | | | 362 | | | | 507 | | | | 1,442 | | Exploration expenses, including dry holes and lease impairment | 162 | | | 351 | | | 233 | |
General and administrative expenses | | | 473 | | | | 422 | | | | 414 | | General and administrative expenses | 340 | | | 357 | | | 397 | |
Interest expense | | | 399 | | | | 325 | | | | 338 | | Interest expense | 481 | | | 468 | | | 380 | |
Loss on debt extinguishment | | | 53 | | | | — | | | | 148 | | |
Depreciation, depletion and amortization | | | 1,883 | | | | 2,883 | | | | 3,244 | | Depreciation, depletion and amortization | 1,528 | | | 2,074 | | | 2,122 | |
Impairment | | | — | | | | 4,203 | | | | 67 | | |
| Impairment and other | | Impairment and other | 147 | | | 2,126 | | | — | |
Total costs and expenses | | | 6,246 | | | | 11,169 | | | | 8,693 | | Total costs and expenses | 6,093 | | | 7,654 | | | 6,289 | |
Income (Loss) Before Income Taxes | | | 220 | | | | (5,778 | ) | | | (3,854 | ) | Income (Loss) Before Income Taxes | 1,490 | | | (2,850) | | | 221 | |
Provision (benefit) for income taxes | | | 335 | | | | (1,837 | ) | | | 2,222 | | Provision (benefit) for income taxes | 600 | | | (11) | | | 461 | |
Net Income (Loss) | | | (115 | ) | | | (3,941 | ) | | | (6,076 | ) | Net Income (Loss) | 890 | | | (2,839) | | | (240) | |
Less: Net income (loss) attributable to noncontrolling interests | | | 167 | | | | 133 | | | | 56 | | Less: Net income (loss) attributable to noncontrolling interests | 331 | | | 254 | | | 168 | |
Net Income (Loss) Attributable to Hess Corporation | | | (282 | ) | | | (4,074 | ) | | | (6,132 | ) | Net Income (Loss) Attributable to Hess Corporation | 559 | | | (3,093) | | | (408) | |
Less: Preferred stock dividends | | | 46 | | | | 46 | | | | 41 | | Less: Preferred stock dividends | — | | | — | | | 4 | |
Net Income (Loss) Attributable to Hess Corporation Common Stockholders | | $ | (328 | ) | | $ | (4,120 | ) | | $ | (6,173 | ) | Net Income (Loss) Attributable to Hess Corporation Common Stockholders | $ | 559 | | | $ | (3,093) | | | $ | (412) | |
| | | | | | | | | | | | | | | | | | |
Net Income (Loss) Attributable to Hess Corporation Per Common Share | | | | | | | | | | | | | |
| Net Income (Loss) Attributable to Hess Corporation Per Common Share: | | Net Income (Loss) Attributable to Hess Corporation Per Common Share: | |
Basic | | $ | (1.10 | ) | | $ | (13.12 | ) | | $ | (19.92 | ) | Basic | $ | 1.82 | | | $ | (10.15) | | | $ | (1.37) | |
Diluted | | $ | (1.10 | ) | | $ | (13.12 | ) | | $ | (19.92 | ) | Diluted | $ | 1.81 | | | $ | (10.15) | | | $ | (1.37) | |
Weighted Average Number of Common Shares Outstanding (Diluted) | | | 298.2 | | | | 314.1 | | | | 309.9 | | |
| Weighted Average Number of Common Shares Outstanding: | | Weighted Average Number of Common Shares Outstanding: | |
| Basic | | Basic | 307.4 | | | 304.8 | | | 301.2 | |
| Diluted | | Diluted | 309.3 | | | 304.8 | | | 301.2 | |
Common Stock Dividends Per Share | | $ | 1.00 | | | $ | 1.00 | | | $ | 1.00 | | Common Stock Dividends Per Share | $ | 1.00 | | | $ | 1.00 | | | $ | 1.00 | |
See accompanying Notes to Consolidated Financial Statements.
HESS
CORPORATIONCORPORATION AND CONSOLIDATED SUBSIDIARIESSTATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME
| | | Years Ended December 31, | | | Year Ended December 31, |
| | 2018 | | | 2017 | | | 2016 | | | 2021 | | 2020 | | 2019 |
| | (In millions) | | | | | | | |
| | | | | | | | | | | | | | (In millions) |
Net Income (Loss) | | $ | (115 | ) | | $ | (3,941 | ) | | $ | (6,076 | ) | Net Income (Loss) | $ | 890 | | | $ | (2,839) | | | $ | (240) | |
| | | | | | | | | | | | | |
Other Comprehensive Income (Loss): | | | �� | | | | | | | | | | Other Comprehensive Income (Loss): | | | | | |
| | | | | | | | | | | | | |
Derivatives designated as cash flow hedges | | | | | | | | | | | | | Derivatives designated as cash flow hedges | |
Effect of hedge (gains) losses reclassified to income | | | 173 | | | | 18 | | | | — | | Effect of hedge (gains) losses reclassified to income | 243 | | | (547) | | | (1) | |
Income taxes on effect of hedge (gains) losses reclassified to income | | | — | | | | — | | | | — | | Income taxes on effect of hedge (gains) losses reclassified to income | — | | | — | | | — | |
Net effect of hedge (gains) losses reclassified to income | | | 173 | | | | 18 | | | | — | | Net effect of hedge (gains) losses reclassified to income | 243 | | | (547) | | | (1) | |
Change in fair value of cash flow hedges | | | 330 | | | | (156 | ) | | | — | | Change in fair value of cash flow hedges | (315) | | | 649 | | | (462) | |
Income taxes on change in fair value of cash flow hedges | | | (86 | ) | | | — | | | | — | | Income taxes on change in fair value of cash flow hedges | — | | | — | | | 86 | |
Net change in fair value of cash flow hedges | | | 244 | | | | (156 | ) | | | — | | Net change in fair value of cash flow hedges | (315) | | | 649 | | | (376) | |
Change in derivatives designated as cash flow hedges, after taxes | | | 417 | | | | (138 | ) | | | — | | Change in derivatives designated as cash flow hedges, after taxes | (72) | | | 102 | | | (377) | |
| | | | | | | | | | | | | |
Pension and other postretirement plans | | | | | | | | | | | | | Pension and other postretirement plans | |
(Increase) reduction in unrecognized actuarial losses | | | 29 | | | | 35 | | | | (155 | ) | (Increase) reduction in unrecognized actuarial losses | 355 | | | (205) | | | (160) | |
Income taxes on actuarial changes in plan liabilities | | | (6 | ) | | | — | | | | 20 | | Income taxes on actuarial changes in plan liabilities | — | | | — | | | — | |
(Increase) reduction in unrecognized actuarial losses, net | | | 23 | | | | 35 | | | | (135 | ) | (Increase) reduction in unrecognized actuarial losses, net | 355 | | | (205) | | | (160) | |
Amortization of net actuarial losses | | | 41 | | | | 77 | | | | 60 | | Amortization of net actuarial losses | 66 | | | 47 | | | 144 | |
Income taxes on amortization of net actuarial losses | | | — | | | | — | | | | (21 | ) | Income taxes on amortization of net actuarial losses | — | | | — | | | — | |
Net effect of amortization of net actuarial losses | | | 41 | | | | 77 | | | | 39 | | Net effect of amortization of net actuarial losses | 66 | | | 47 | | | 144 | |
Change in pension and other postretirement plans, after taxes | | | 64 | | | | 112 | | | | (96 | ) | Change in pension and other postretirement plans, after taxes | 421 | | | (158) | | | (16) | |
| | | | | | | | | | | | | |
Foreign currency translation adjustment | | | | | | | | | | | | | |
Foreign currency translation adjustment | | | — | | | | 144 | | | | 56 | | |
Asset disposition | | | — | | | | 900 | | | | — | | |
Change in foreign currency translation adjustment | | | — | | | | 1,044 | | | | 56 | | |
| | | | | | | | | | | | | |
Other Comprehensive Income (Loss) | | | 481 | | | | 1,018 | | | | (40 | ) | Other Comprehensive Income (Loss) | 349 | | | (56) | | | (393) | |
| | | | | | | | | | | | | |
Comprehensive Income (Loss) | | | 366 | | | | (2,923 | ) | | | (6,116 | ) | Comprehensive Income (Loss) | 1,239 | | | (2,895) | | | (633) | |
Less: Comprehensive income (loss) attributable to noncontrolling interests | | | 167 | | | | 133 | | | | 56 | | Less: Comprehensive income (loss) attributable to noncontrolling interests | 331 | | | 254 | | | 168 | |
Comprehensive Income (Loss) Attributable to Hess Corporation | | $ | 199 | | | $ | (3,056 | ) | | $ | (6,172 | ) | Comprehensive Income (Loss) Attributable to Hess Corporation | $ | 908 | | | $ | (3,149) | | | $ | (801) | |
See accompanying Notes to Consolidated Financial Statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
| | Year Ended December 31, | | | | | | | | | | | | | | | | |
| | 2018 | | | 2017 | | | 2016 | | | Year Ended December 31, |
| | (In millions) | | | 2021 | | 2020 | | 2019 |
| | | | | | | | | | | | | | | | | | |
Cash Flows from Operating Activities | | | | | | | | | | | | | |
| | | | (In millions) |
| Cash Flows From Operating Activities | | Cash Flows From Operating Activities | | | | | |
Net income (loss) | | $ | (115 | ) | | $ | (3,941 | ) | | $ | (6,076 | ) | Net income (loss) | $ | 890 | | | $ | (2,839) | | | $ | (240) | |
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities | | | | | | | | | | | | | |
(Gains) losses on asset sales, net | | | (32 | ) | | | 86 | | | | (23 | ) | |
| Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | | Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | |
| (Gains) on asset sales, net | | (Gains) on asset sales, net | (29) | | | (87) | | | (22) | |
Depreciation, depletion and amortization | | | 1,883 | | | | 2,883 | | | | 3,244 | | Depreciation, depletion and amortization | 1,528 | | | 2,074 | | | 2,122 | |
Impairment | | | — | | | | 4,203 | | | | 67 | | |
| Impairment and other | | Impairment and other | 147 | | | 2,126 | | | — | |
Exploratory dry hole costs | | | 165 | | | | 268 | | | | 1,064 | | Exploratory dry hole costs | 11 | | | 192 | | | 49 | |
Exploration lease and other impairment | | | 37 | | | | 44 | | | | 145 | | Exploration lease and other impairment | 20 | | | 51 | | | 17 | |
| Pension settlement loss | | Pension settlement loss | 9 | | | — | | | 93 | |
Stock compensation expense | | | 72 | | | | 86 | | | | 73 | | Stock compensation expense | 77 | | | 79 | | | 85 | |
Noncash (gains) losses on commodity derivatives, net | | | 182 | | | | 97 | | | | — | | Noncash (gains) losses on commodity derivatives, net | 216 | | | 260 | | | 116 | |
Provision (benefit) for deferred income taxes and other tax accruals | | | (120 | ) | | | (2,001 | ) | | | 2,200 | | Provision (benefit) for deferred income taxes and other tax accruals | 122 | | | (53) | | | 17 | |
Loss on debt extinguishment | | | 53 | | | | — | | | | 148 | | |
Changes in operating assets and liabilities | | | | | | | | | | | | | |
| Changes in operating assets and liabilities: | | Changes in operating assets and liabilities: | |
(Increase) decrease in accounts receivable | | | (138 | ) | | | (340 | ) | | | 96 | | (Increase) decrease in accounts receivable | (748) | | | 267 | | | (383) | |
(Increase) decrease in inventories | | | (12 | ) | | | (64 | ) | | | 77 | | (Increase) decrease in inventories | 135 | | | (117) | | | (16) | |
Increase (decrease) in accounts payable and accrued liabilities | | | 88 | | | | (44 | ) | | | (87 | ) | Increase (decrease) in accounts payable and accrued liabilities | 241 | | | (533) | | | 4 | |
Increase (decrease) in taxes payable | | | (2 | ) | | | (34 | ) | | | 9 | | Increase (decrease) in taxes payable | 447 | | | (16) | | | 16 | |
Changes in other operating assets and liabilities | | | (122 | ) | | | (298 | ) | | | (142 | ) | Changes in other operating assets and liabilities | (176) | | | (71) | | | (216) | |
Net cash provided by (used in) operating activities | | | 1,939 | | | | 945 | | | | 795 | | Net cash provided by (used in) operating activities | 2,890 | | | 1,333 | | | 1,642 | |
| | | | | | | | | | | | | | | | | | |
Cash Flows from Investing Activities | | | | | | | | | | | | | |
| Cash Flows From Investing Activities | | Cash Flows From Investing Activities | |
Additions to property, plant and equipment - E&P | | | (1,854 | ) | | | (1,788 | ) | | | (1,974 | ) | Additions to property, plant and equipment - E&P | (1,584) | | | (1,896) | | | (2,433) | |
Additions to property, plant and equipment - Midstream | | | (243 | ) | | | (149 | ) | | | (277 | ) | Additions to property, plant and equipment - Midstream | (163) | | | (301) | | | (396) | |
Payments for Midstream equity investments | | | (67 | ) | | | — | | | | — | | Payments for Midstream equity investments | — | | | — | | | (33) | |
Proceeds from asset sales, net of cash sold | | | 607 | | | | 3,296 | | | | 140 | | Proceeds from asset sales, net of cash sold | 427 | | | 493 | | | 22 | |
Other, net | | | (9 | ) | | | (1 | ) | | | 21 | | Other, net | (5) | | | (3) | | | (3) | |
Net cash provided by (used in) investing activities | | | (1,566 | ) | | | 1,358 | | | | (2,090 | ) | Net cash provided by (used in) investing activities | (1,325) | | | (1,707) | | | (2,843) | |
| | | | | | | | | | | | | | | | | | |
Cash Flows from Financing Activities | | | | | | | | | | | | | |
| Cash Flows From Financing Activities | | Cash Flows From Financing Activities | |
Net borrowings (repayments) of debt with maturities of 90 days or less | | | — | | | | (153 | ) | | | 43 | | Net borrowings (repayments) of debt with maturities of 90 days or less | (80) | | | 152 | | | 32 | |
Debt with maturities of greater than 90 days | | | | | | | | | | | | | |
| Debt with maturities of greater than 90 days: | | Debt with maturities of greater than 90 days: | |
Borrowings | | | — | | | | 800 | | | | 1,496 | | Borrowings | 750 | | | 1,000 | | | 760 | |
Repayments | | | (633 | ) | | | (459 | ) | | | (1,455 | ) | Repayments | (510) | | | — | | | (8) | |
Proceeds from issuance of Hess Midstream Partnership LP units | | | — | | | | 366 | | | | — | | |
Proceeds from issuance of preferred stock | | | — | | | | — | | | | 557 | | |
Proceeds from issuance of common stock | | | — | | | | — | | | | 1,087 | | |
| Proceeds from sale of Class A shares of Hess Midstream LP | | Proceeds from sale of Class A shares of Hess Midstream LP | 178 | | | — | | | — | |
| Employee stock options exercised | | Employee stock options exercised | 77 | | | 15 | | | 40 | |
| Cash dividends paid | | Cash dividends paid | (311) | | | (309) | | | (316) | |
| Payments on finance lease obligations | | Payments on finance lease obligations | (10) | | | (7) | | | (49) | |
Common stock acquired and retired | | | (1,365 | ) | | | (110 | ) | | | — | | Common stock acquired and retired | — | | | — | | | (25) | |
Cash dividends paid | | | (345 | ) | | | (363 | ) | | | (350 | ) | |
Noncontrolling interests, net | | | (211 | ) | | | (243 | ) | | | (23 | ) | Noncontrolling interests, net | (664) | | | (261) | | | (353) | |
Other, net | | | 28 | | | | (26 | ) | | | (44 | ) | Other, net | (21) | | | (22) | | | (29) | |
Net cash provided by (used in) financing activities | | | (2,526 | ) | | | (188 | ) | | | 1,311 | | Net cash provided by (used in) financing activities | (591) | | | 568 | | | 52 | |
| | | | | | | | | | | | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | (2,153 | ) | | | 2,115 | | | | 16 | | Net Increase (Decrease) in Cash and Cash Equivalents | 974 | | | 194 | | | (1,149) | |
Cash and Cash Equivalents at Beginning of Year | | | 4,847 | | | | 2,732 | | | | 2,716 | | Cash and Cash Equivalents at Beginning of Year | 1,739 | | | 1,545 | | | 2,694 | |
Cash and Cash Equivalents at End of Year | | $ | 2,694 | | | $ | 4,847 | | | $ | 2,732 | | Cash and Cash Equivalents at End of Year | $ | 2,713 | | | $ | 1,739 | | | $ | 1,545 | |
See accompanying Notes to Consolidated Financial Statements.
HESS CORPORATIONCORPORATION AND CONSOLIDATED SUBSIDIARIES STATEMENT OF CONSOLIDATED EQUITY
| | Mandatory Convertible Preferred Stock | | | Common Stock | | | Capital in Excess of Par Value | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Total Hess Stockholders' Equity | | | Noncontrolling Interests | | | Total Equity | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | | | Mandatory Convertible Preferred Stock | | Common Stock | | Capital in Excess of Par | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total Hess Stockholders' Equity | | Noncontrolling Interests | | Total Equity |
Balance at December 31, 2015 | | $ | — | | | $ | 286 | | | $ | 4,127 | | | $ | 16,637 | | | $ | (1,664 | ) | | $ | 19,386 | | | $ | 1,015 | | | $ | 20,401 | | |
| | | | | (In millions) |
| Balance at December 31, 2018 | | Balance at December 31, 2018 | $ | 1 | | | $ | 291 | | | $ | 5,386 | | | $ | 4,257 | | | $ | (306) | | | $ | 9,629 | | | $ | 1,259 | | | $ | 10,888 | |
Net income (loss) | | | — | | | | — | | | | — | | | | (6,132 | ) | | | — | | | | (6,132 | ) | | | 56 | | | | (6,076 | ) | Net income (loss) | — | | | — | | | — | | | (408) | | | — | | | (408) | | | 168 | | | (240) | |
Other comprehensive income (loss) | | | — | | | | — | | | | — | | | | — | | | | (40 | ) | | | (40 | ) | | | — | | | | (40 | ) | Other comprehensive income (loss) | — | | | — | | | — | | | — | | | (393) | | | (393) | | | — | | | (393) | |
Stock issuance | | | 1 | | | | 29 | | | | 1,577 | | | | — | | | | — | | | | 1,607 | | | | — | | | | 1,607 | | |
Share-based compensation activity, including income taxes | | | — | | | | 2 | | | | 69 | | | | — | | | | — | | | | 71 | | | | — | | | | 71 | | |
| Preferred stock conversion | | Preferred stock conversion | (1) | | | 12 | | | (11) | | | — | | | — | | | — | | | — | | | — | |
| Share-based compensation | | Share-based compensation | — | | | 2 | | | 123 | | | — | | | — | | | 125 | | | — | | | 125 | |
Dividends on preferred stock | | | — | | | | — | | | | — | | | | (41 | ) | | | — | | | | (41 | ) | | | — | | | | (41 | ) | Dividends on preferred stock | — | | | — | | | — | | | (4) | | | — | | | (4) | | | — | | | (4) | |
Dividends on common stock | | | — | | | | — | | | | — | | | | (317 | ) | | | — | | | | (317 | ) | | | — | | | | (317 | ) | Dividends on common stock | — | | | — | | | — | | | (310) | | | — | | | (310) | | | — | | | (310) | |
| Conversion of Midstream structure | | Conversion of Midstream structure | — | | | — | | | 15 | | | — | | | — | | | 15 | | | (22) | | | (7) | |
| Sale of water business to Hess Infrastructure Partners | | Sale of water business to Hess Infrastructure Partners | — | | | — | | | 78 | | | — | | | — | | | 78 | | | (78) | | | — | |
Noncontrolling interests, net | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (14 | ) | | | (14 | ) | Noncontrolling interests, net | — | | | — | | | — | | | — | | | — | | | — | | | (353) | | | (353) | |
Balance at December 31, 2016 | | $ | 1 | | | $ | 317 | | | $ | 5,773 | | | $ | 10,147 | | | $ | (1,704 | ) | | $ | 14,534 | | | $ | 1,057 | | | $ | 15,591 | | |
Cumulative effect of adoption of new accounting standards | | | — | | | | — | | | | 2 | | | | (39 | ) | | | — | | | | (37 | ) | | | — | | | | (37 | ) | |
| Balance at December 31, 2019 | | Balance at December 31, 2019 | $ | — | | | $ | 305 | | | $ | 5,591 | | | $ | 3,535 | | | $ | (699) | | | $ | 8,732 | | | $ | 974 | | | $ | 9,706 | |
Net income (loss) | | | — | | | | — | | | | — | | | | (4,074 | ) | | | — | | | | (4,074 | ) | | | 133 | | | | (3,941 | ) | Net income (loss) | — | | | — | | | — | | | (3,093) | | | — | | | (3,093) | | | 254 | | | (2,839) | |
Other comprehensive income (loss) | | | — | | | | — | | | | — | | | | — | | | | 1,018 | | | | 1,018 | | | | — | | | | 1,018 | | Other comprehensive income (loss) | — | | | — | | | — | | | — | | | (56) | | | (56) | | | — | | | (56) | |
Share-based compensation activity | | | — | | | | 1 | | | | 92 | | | | — | | | | — | | | | 93 | | | | — | | | | 93 | | |
Dividends on preferred stock | | | — | | | | — | | | | — | | | | (46 | ) | | | — | | | | (46 | ) | | | — | | | | (46 | ) | |
| Share-based compensation | | Share-based compensation | — | | | 2 | | | 93 | | | (5) | | | — | | | 90 | | | — | | | 90 | |
Dividends on common stock | | | — | | | | — | | | | — | | | | (317 | ) | | | — | | | | (317 | ) | | | — | | | | (317 | ) | Dividends on common stock | — | | | — | | | — | | | (307) | | | — | | | (307) | | | — | | | (307) | |
Common stock acquired and retired | | | — | | | | (3 | ) | | | (43 | ) | | | (74 | ) | | | — | | | | (120 | ) | | | — | | | | (120 | ) | |
Hess Midstream Partners LP units issuance | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | 356 | | | | 356 | | |
Noncontrolling interests, net | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (243 | ) | | | (243 | ) | Noncontrolling interests, net | — | | | — | | | — | | | — | | | — | | | — | | | (259) | | | (259) | |
Balance at December 31, 2017 | | $ | 1 | | | $ | 315 | | | $ | 5,824 | | | $ | 5,597 | | | $ | (686 | ) | | $ | 11,051 | | | $ | 1,303 | | | $ | 12,354 | | |
Cumulative effect of adoption of new accounting standards | | | — | | | | — | | | | — | | | | 101 | | | | (101 | ) | | | — | | | | — | | | | — | | |
| Balance at December 31, 2020 | | Balance at December 31, 2020 | $ | — | | | $ | 307 | | | $ | 5,684 | | | $ | 130 | | | $ | (755) | | | $ | 5,366 | | | $ | 969 | | | $ | 6,335 | |
Net income (loss) | | | — | | | | — | | | | — | | | | (282 | ) | | | — | | | | (282 | ) | | | 167 | | | | (115 | ) | Net income (loss) | — | | | — | | | — | | | 559 | | | — | | | 559 | | | 331 | | | 890 | |
Other comprehensive income (loss) | | | — | | | | — | | | | — | | | | — | | | | 481 | | | | 481 | | | | — | | | | 481 | | Other comprehensive income (loss) | — | | | — | | | — | | | — | | | 349 | | | 349 | | | — | | | 349 | |
Share-based compensation activity | | | — | | | | 1 | | | | 103 | | | | — | | | | — | | | | 104 | | | | — | | | | 104 | | |
Dividends on preferred stock | | | — | | | | — | | | | — | | | | (46 | ) | | | — | | | | (46 | ) | | | — | | | | (46 | ) | |
| Share-based compensation | | Share-based compensation | — | | | 3 | | | 153 | | | — | | | — | | | 156 | | | — | | | 156 | |
Dividends on common stock | | | — | | | | — | | | | — | | | | (299 | ) | | | — | | | | (299 | ) | | | — | | | | (299 | ) | Dividends on common stock | — | | | — | | | — | | | (310) | | | — | | | (310) | | | — | | | (310) | |
Common stock acquired and retired | | | — | | | | (25 | ) | | | (541 | ) | | | (814 | ) | | | — | | | | (1,380 | ) | | | — | | | | (1,380 | ) | |
| Sale of Class A shares of Hess Midstream LP | | Sale of Class A shares of Hess Midstream LP | — | | | — | | | 152 | | | — | | | — | | | 152 | | | 103 | | | 255 | |
| Repurchase of Class B units of Hess Midstream Operations LP | | Repurchase of Class B units of Hess Midstream Operations LP | — | | | — | | | 28 | | | — | | | — | | | 28 | | | (390) | | | (362) | |
Noncontrolling interests, net | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | (211 | ) | | | (211 | ) | Noncontrolling interests, net | — | | | — | | | — | | | — | | | — | | | — | | | (287) | | | (287) | |
Balance at December 31, 2018 | | $ | 1 | | | $ | 291 | | | $ | 5,386 | | | $ | 4,257 | | | $ | (306 | ) | | $ | 9,629 | | | $ | 1,259 | | | $ | 10,888 | | |
| Balance at December 31, 2021 | | Balance at December 31, 2021 | $ | — | | | $ | 310 | | | $ | 6,017 | | | $ | 379 | | | $ | (406) | | | $ | 6,300 | | | $ | 726 | | | $ | 7,026 | |
See accompanying Notes to Consolidated Financial Statements.
1.
Nature of Operations, Basis of PresentationPresentation and Summary of Accounting PoliciesUnless the context indicates otherwise, references to “Hess”, “the Corporation”, “Registrant”, “we”, “us” and “our” refer to the consolidated business operations of Hess Corporation and its affiliates.
Nature of Business: Hess Corporation, incorporated in the State of Delaware in 1920, is a global Exploration and Production (E&P)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.), Denmark,Guyana, the Malaysia/Thailand Joint Development Area (JDA), and Malaysia. We conduct exploration activities primarily offshore Guyana, Suriname, Canada and in the U.S. Gulf of Mexico. At the Stabroek Block (Hess 30%),Mexico, and offshore Guyana, we have participated in twelve significant discoveriesSuriname and sanctioned in 2017 the first phase of development of the block.Canada.
Our Midstream operating segment, which is comprised of Hess Corporation’s approximate 43.5% consolidated ownership interest in Hess Midstream LP at December 31, 2021 (see Note 4, Hess Midstream LP) provides fee-based services, including gathering, compressing and processing natural gas and fractionating NGLs;NGL; gathering, terminaling, loading and transporting crude oil and NGLs;NGL; storing and terminaling propane, and water handling services primarily in the Bakken and Three Forks Shale playsshale play in the Williston Basin area of North Dakota. Basis of Presentation and Principles of Consolidation:The consolidated financial statements include the accounts of Hess Corporation and entities in which we own more than a 50% voting interest. We alsoCommencing December 16, 2019, we consolidateHess Midstream LP, a variable interest entity that acquired Hess Infrastructure Partners LP (HIP), a variable interest entity, based on our conclusion that we have the power through our 50%Hess Corporation’s approximate 43.5% consolidated ownership interest inHess Midstream LPto direct those activities that most significantly impact the economic performance of HIP,Hess Midstream LP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to HIP. Hess Midstream LP. Prior to December 16, 2019, we consolidated HIP, also a variable interest entity based on the conclusion that we had the power to direct the activities that most significantly impacted the economic performance of HIP, and were obligated to absorb losses or had the right to receive benefits that could potentially be significant toHIP. This conclusion was based on a qualitative analysis that consideredHess Midstream LP’s governance structure, the commercial agreements betweenHess Midstream LPand us, and the voting rights established between the members, which provide us the ability to control the operations ofHess Midstream LP.
Our undivided interests in unincorporated oil and gas E&P ventures are proportionately consolidated. Investments in affiliated companies, 20% to 50% owned and where we have the ability to influence the operating or financial decisions of the affiliate, are accounted for using the equity method.
In 2018, we adopted Accounting Standards Codification (ASC) Topic, ASC 606, Revenue from Contracts with Customers, using the modified retrospective method. Accordingly, the required disclosures under ASC 606 were provided only for the current period. The adoption of this standard did not affect the timing of revenue recognition for our uncompleted contracts at January 1, 2018, and as a result, no cumulative effect adjustment to Retained earnings was recognized. Accounts receivables from contracts with customers is presented separately in the Consolidated Balance Sheet with the prior year balance recast to conform to the current period presentation. In addition, as the adoption of ASC 606 did not affect previous conclusions regarding our involvement as a principal versus agent in contracts with customers, there were no changes in presentation to the Statement of Consolidated Income.
In 2018, we adopted Accounting Standards Update (ASU) 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This ASU contains a provision that prohibits the capitalization of the non-service cost components of net periodic benefit cost when constructing or producing an asset. This provision was applied prospectively effective January 1, 2018. The ASU contains another provision requiring that non-service cost components of net periodic benefit cost be presented separately from the service cost component in the Statement of Consolidated Income. We elected the practical expedient allowing the use of amounts previously disclosed in the notes to our Consolidated Financial Statements as the basis for the required retrospective application of this provision, as capitalization of non-service cost components of net periodic benefit cost was not material. For the years ended December 31, 2017 and 2016, the retrospective application resulted in the reclassification of net expense totaling $14 million and $5 million, respectively to Other, net from Operating costs and expenses and General and administrative expenses in our Statement of Consolidated Income.
In 2018, we adopted ASU 2017-12, Derivatives and Hedging – Targeted Improvements to Accounting for Hedging Activities. This ASU makes certain targeted improvements to simplify the application of the existing hedge accounting guidance. The adoption of this ASU resulted in an increase to Retained earnings and a decrease in Accumulated other comprehensive income (loss) of $1 million in our Consolidated Balance Sheet in order to remove the cumulative effect of hedging ineffectiveness previously recognized in earnings for contracts designated as hedging instruments that were outstanding at January 1, 2018.
In 2018, the FASB issued ASU 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This ASU allows the reclassification of stranded income tax effects within Accumulated other comprehensive income (loss) to Retained earnings that resulted from the enactment of U.S. Federal income tax reform, commonly referred to as the U.S. Tax Cuts and Jobs Act (“Act”). Specifically, this ASU provides entities the option to reclassify the stranded income tax effects resulting from the reduction to the corporate income tax rate from the Act upon adoption of this ASU, instead of upon liquidation of the individual items (or of the underlying portfolio of items). This ASU is effective for us beginning in the first quarter of 2019, with early adoption permitted. We elected to adopt this ASU effective October 1, 2018. The adoption resulted in an increase to Retained earnings and a decrease to Accumulated other comprehensive income (loss) of $100 million in our Consolidated Balance Sheet.
In 2018, we adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force). This ASU requires the total change in cash and cash equivalents and restricted cash be reflected
on the statement of cash flows. A reconciliation to the balance sheet is also required when cash and cash equivalents and restricted cash are not separately presented on the balance sheet or are presented in more than one financial statement line item on the balance sheet. The adoption of this ASU did not have a material impact on our Statement of Consolidated Cash Flows.
In 2018, we adopted ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the FASB Emerging Issues Task Force). This ASU is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific classification issues for which current guidance is either unclear or is non-specific. The requirement that fees paid to third-parties and premiums incurred relating to the repayment of debt be classified as financing cash outflows is among the classification issues addressed by this ASU. The adoption of this ASU did not have a material impact on our Statement of Consolidated Cash Flows.
In 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill and Other – Simplifying the Test for Goodwill Impairment. This ASU modifies the concept of goodwill impairment from a condition that exists when the carrying amount of goodwill exceeds its implied fair value to a condition that exists when the carrying amount of the reporting unit exceeds its fair value. Thus, an entity should recognize an impairment charge for the amount by which the carrying amount of a reporting unit exceeds its fair value, limited by the amount of goodwill allocated to the reporting unit. This ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted. We elected to adopt this ASU effective October 1, 2018, and the adoption had no impact on our Consolidated Financial Statements.
Estimates and Assumptions: In preparing financial statements in conformity with U.S. generally accepted accounting principles (GAAP),GAAP, management makes estimates and assumptions that affect the reported amounts of assets and liabilities in the
Consolidated Balance Sheetand revenues and expenses in our theStatement of Consolidated Income. Actual results could differ from those estimates. Estimates made by management include oil and gas reserves, asset and other valuations, depreciable lives, pension liabilities, legal and environmental obligations, asset retirement obligations and income taxes.
Revenue Recognition: See Note 2,
Exploration and Production
The E&P segment recognizes revenue from the sale of crude oil, NGL, and natural gas as performance obligations under contracts with customers are satisfied. Our responsibilities to deliver each unit of quantity of crude oil, NGL, and natural gas under these contracts represent separate, distinct performance obligations. These performance obligations are satisfied at the point in time control of each unit of quantity transfers to the customer. Generally, the control of each unit of quantity transfers to the customer upon the transfer of legal title at the point of physical delivery. Pricing is variable and is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials.
For long-term international natural gas contracts with ship-or-pay provisions, our obligation to stand-ready to provide a minimum volume over each commitment period represents separate, distinct performance obligations. Penalties owed against future deliveries of natural gas due to delivery of volumes below minimum delivery commitments are recognized as reductions to revenue in the commitment period when the shortfall occurs. Long-term international natural gas contracts may also contain take-or-pay provisions whereby the customer is required to pay for volumes not taken that are below minimum volume commitments but the customer has certain make-up rights to receive shortfall volumes in subsequent periods. Shortfall payments received from customers when volumes purchased are below the minimum volume commitment are deferred upon receipt as a contract liability. Revenue is recognized at the earlier of when we deliver the make-up volumes in subsequent periods or when it becomes remote that the customer will exercise their make-up rights.
Certain crude oil, NGL, and natural gas volumes are purchased by Hess from third parties, including working interest partners and royalty owners in certain Hess-operated properties, before they are sold to customers. Where control over the crude oil, NGL, or natural gas transfers to Hess before the volumes are transferred to the customer, revenue and the associated cost of purchased volumes are presented on a gross basis in the Statement of Consolidated Income within Sales and other operating revenues and Marketing, including purchased oil and gas, respectively. Where control of crude oil, NGL, or natural gas is not transferred to Hess, revenue is presented net of the associated cost of purchased volumes within Sales and other operating revenues in the Statement of Consolidated Income. Contract Duration and Pricing:
Contracts with customers for the sale of U.S. crude oil, NGL, and natural gas primarily include those contracts that involvethe short-term sale of volumes during a specified period,and those contracts that automatically renew on a periodic basis until either party cancels. We have certain long-term contracts with customers for the sale of U.S. natural gas and NGL that have remaining durations ranging from one to eleven years.
Contracts with customers for the sale of international crude oil involve the short-term sale of volumes during a specified period. Pricing is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials, shortly after control of the volumes transfers to the customer. International contracts with customers for the sale of natural gas are in the form of natural gas sales agreements with government entities that have durations that are aligned with the durations of production sharing contracts or other contractual arrangements with host governments. Pricing is determined using contractual formulas that are based on the price of alternative fuels as obtained from price indices and other factors.
Contract Balances:
Our right to receive or collect payment from the customer is aligned with the timing of revenue recognition except in situations when we receive shortfall payments under contracts with take-or-pay provisions with customer make-up rights.
Generally, we receive payments from customers on a monthly basis, shortly after the physical delivery of the crude oil, NGL, or natural gas.
Transaction Price Allocated to Remaining Performance Obligations:
The transaction price allocated to our wholly unsatisfied performance obligations on uncompleted contracts is variable. Further, many of our contracts with customers have durations of less than twelve months. Accordingly, we have elected under the provisions of Accounting Standards Codification (ASC) 606, Revenues from Contracts with Customers, the exemption from disclosure of revenue recognizable in future periods as these performance obligations are satisfied.
Sales-based Taxes:
We exclude sales-based taxes that are collected from customers from the transaction price in our contracts with customers. Accordingly, revenue from contracts with customers is net of sales-based taxes that are collected from customers and remitted to taxing authorities.
Midstream
Our Midstream segment provides gathering, compression, processing, fractionation, storage, terminaling, loading and transportation, and water handling services.
The Midstream segment has multiple long-term, fee-based commercial agreements with certain subsidiaries of Hess, each generally with an initial ten-year term that can be extended for an additional ten-year term at the unilateral right of Hess Midstream. These contracts have minimum volumes the customer is obligated to provide each calendar quarter. The minimum volume commitments are subject to fluctuation based on nominations covering substantially all of our E&P segment’s production and projected third-party volumes that will be purchased in the Bakken. As the minimum volume commitments are subject to fluctuation, and as these contracts contain fee inflation escalators and fee recalculation mechanisms, substantially all of the transaction price at contract inception is variable. The midstream segment also has long-term, fee based commercial agreements for water handling services with a subsidiary of Hess with an initial 14 year term that can be extended for an additional ten-year term at the unilateral right of Hess Midstream. Water handling services are provided for an agreed-upon fee per barrel or the reimbursement of third-party fees.
The Midstream segment’s responsibilities to provide each of the above services for each year under each of the commercial agreements are considered separate, distinct performance obligations. Revenue is recognized for each performance obligation under these commercial agreements over-time as services are rendered using the output method, measured using the amount of volumes serviced during the period. The Midstream segment has elected the practical expedient under the provisions of ASC 606,Revenue
from Contracts with Customers to recognize revenue in the amount it is entitled to invoice. If the commercial agreements have ship-or-pay provisions, the Midstream segment’s responsibility to stand-ready to service a minimum volume over each quarterly commitment period represent separate, distinct performance obligations. Shortfall payments received under ship-or-pay provisions are recognized as revenue in the calendar quarter the shortfall occurs as the customer does not have make-up rights beyond the calendar quarter end of the quarterly commitment period. All revenues, receivables, and contract balances arising from the commercial agreements between the Midstream segment and the Hess subsidiaries that are the counterparty to the commercial agreements are eliminated upon consolidation.
On December 30, 2020, Hess Midstream exercised its renewal options to extend the terms of certain gas gathering, crude oil gathering, gas processing and fractionation, storage, and terminal and export commercial agreements for the secondary term through December 31, 2033. There were no changes to any provisions of the existing commercial agreements as a result of the exercise of the renewal options.
Exploration and Development Costs: E&P activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized. The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of a project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors, firm plans for additional drilling and other factors.
Depreciation, Depletion and Amortization: We record depletion expense for acquisition costs of proved properties using the units of production method over proved oil and gas reserves. Depreciation and depletion expense for oil and gas production facilities and wells is calculated using the units of production method over proved developed oil and gas reserves. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors. Depreciation of all other plant and equipment is determined on the straight-line method based on estimated useful lives. Capitalized Interest: Interest from external borrowings is capitalized on material projects using the weighted average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at first production from the field. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying assets.
Impairment of Long‑lived Assets: We review long‑lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts of the long-lived assets are not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is determinedmeasured based on the estimated fair value of the assets generally determined by discounting anticipated future net cash flows, an income valuation approach, or by a market‑based valuation approach, which are Level 3 fair value measurements.
In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a projected amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairment will generally
differ from those used in the standardized measure of discounted future net cash flows reported in
Supplementary Oil and Gas Data, since the standardized measure requires the use of historical twelve-month average prices.
Impairment of Goodwill: Goodwill is tested for impairment annually on October 1st or when events or circumstances indicate that the carrying amount of the goodwill may not be recoverable. To determine whether an indicator of impairment exists,goodwill is impaired, the fair value of a reporting unit is compared with its carrying amount,value, including goodwill. If the fair value of the reporting unit exceeds its carrying value, goodwill is not impaired. If the carrying value of the reporting unit exceeds its fair value, an impairment charge would be recorded for the excess of the carrying value over fair value, limited by the amount of goodwill allocated to the reporting unit. At December 31, 2018,2021, goodwill of $360 million relates to the Midstream operating segment. Cash and Cash Equivalents: Cash and cash equivalents primarily comprises cash on hand and on deposit, as well as highly liquid investments that are readily convertible into cash and have maturities of three months or less when acquired.
Inventories: Unsold Produced and unsold crude oil and NGLsNGL are valued at the lower of cost or net realizable value. Cost is determined based onusing the average cost of production.production plus any transport cost incurred in bringing the volumes to their present location. Materials and supplies are valued at cost. Obsolete or surplus materials identified during periodic reviews are valued at the lower of cost or estimated net realizable value. Leases: We determine if an arrangement is a lease at inception by evaluating whether the contract conveys the right to control an identified asset during the period of use. Right-of-use (ROU) assets represent our right to use an identified asset for the lease term and lease obligations represent our obligation to make payments as set forth in the lease arrangement. ROU assets and lease liabilities are recognized in the Consolidated Balance Sheet as operating leases or finance leases at the commencement date based on the present value of the minimum lease payments over the lease term. Where the implicit discount rate in a lease is not readily determinable, we use our incremental borrowing rate based on information available at the commencement date for determining the present value of the minimum lease payments. The lease term used in measurement of our lease obligations includes options to extend or terminate the lease when, in our judgment, it is reasonably certain that we will exercise that option. Variable lease payments that depend on an index or a rate are included in the measurement of lease obligations using the index or rate at the commencement date. Variable lease payments that vary because of changes in facts or circumstances after the commencement date of the lease are not included in the minimum lease payments used to measure lease obligations. We have agreements that include financial obligations for lease and nonlease components. For purposes of measuring lease obligations, we have elected not to separate nonlease components from lease components for the following classes of assets: drilling rigs, office space, offshore vessels, and aircraft. We apply a portfolio approach to account for operating lease ROU assets and liabilities for certain vehicles, railcars, field equipment and office equipment leases.
Finance lease cost is recognized as amortization of the ROU asset and interest expense on the lease liability. Operating lease cost is generally recognized on a straight-line basis. Operating lease costs for drilling rigs used to drill development wells and successful exploration wells are capitalized. Operating lease cost for other ROU assets used in oil and gas producing activities are either capitalized or expensed on a straight-line basis based on the nature of operation for which the ROU asset is utilized.
Leases with an initial term of 12 months or less are not recorded on the balance sheet as permitted under ASC 842, Leases. We recognize lease cost for short-term leases on a straight-line basis over the term of the lease. Some of our leases include one or more options to renew. The renewal option is at our sole discretion and is not included in the lease term for measurement of the lease obligation unless we are reasonably certain at the commencement date of the lease, to renew the lease.
Income Taxes: Deferred income taxes are determined using the liability method. We have net operating loss carryforwards or credit carryforwards in multiple jurisdictions and have recorded deferred tax assets for those losses and credits. Additionally, we have deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If, when tested under the relevant accounting standards, it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount that is expected to be realized. The accounting standards require the evaluation of all available positive and negative evidence giving weight based on the evidence’s relative objectivity. In evaluating potential sources of positive evidence, we consider the reversal of taxable temporary differences, taxable income in carryback and carryforward periods, the availability of tax planning strategies, the existence of appreciated assets, estimates of future taxable income, and other factors. In evaluating potential sources of negative evidence, we consider a cumulative loss in recent years, any history of operating losses or tax credit carryforwards expiring unused, losses expected in early future years, unsettled circumstances that, if unfavorably resolved, would adversely affect future operations and profit levels on a continuing basis in future years, and any carryback or carryforward periods that areperiod so brief that it would limit realization of tax benefits if a significant deductible temporary difference is expected to reverse in a single year.year would limit realization of tax benefits. We assign cumulative historical losses significant weight in the evaluation of realizability relative to more subjective evidence such as forecasts of future income. In addition, we recognize the financial statement effect of a tax position only when management believes that it is more likely than not, that based on the technical merits, the position will be sustained upon examination. We are no longer indefinitely reinvested with respect to the book in excess of tax basis in the investment in our foreign subsidiaries. Because of U.S. tax reform we expect that the future reversal of such temporary differences will occur free of material taxation. We classify interest and penalties associated with uncertain tax positions as income tax expense. We account for the U.S. tax effect of global intangible low-taxed income earned by foreign subsidiaries in the period that such income is earned. We utilize the aggregate approach for releasing disproportionate income tax effects fromAccumulated other comprehensive income (loss). Asset Retirement Obligations: We have material legal obligations to remove and dismantle long‑lived assets and to restore land or the seabed at certain E&P locations. We initially recognize a liability for the fair value of legally required asset retirement obligations in the period in which the retirement obligations are incurred and capitalize the associated asset retirement costs as part of the carrying amount of the long‑lived assets. In subsequent periods, the liability is accreted, and the asset is depreciated over the useful life of the related asset. Fair value is determined by applying a credit adjusted risk-free rate to the undiscounted expected future abandonment expenditures, which represent Level 3 inputs in the fair value hierarchy defined under Fair Value Measurements below.expenditures. Changes in estimates prior to settlement result in adjustments to both the liability and related asset values, unless the field has ceased production, in which case changes are recognized in theStatement of Consolidated Income.
We measure asset retirement obligations based on the requirements of existing laws and regulations in accordance with ASC 410-20, Asset Retirement Obligations. Laws and regulations associated with the scope and timing for the abandonment of oil and gas wells, facilities and equipment could change which could increase the cost of our abandonment obligations. In addition, we may be required to assume abandonment obligations for certain divested assets in the event the current or future owners of facilities previously owned by us are unable to perform, whether due to bankruptcy or otherwise.
Retirement Plans: We recognize the funded status of defined benefit postretirement plans in theConsolidated Balance Sheet. The funded status is measured as the difference between the fair value of plan assets and the projected benefit obligation. We recognize the net changes in the funded status of these plans as a component of Other Comprehensive Income (Loss) in the year in which such changes occur. Actuarial gains and losses in excess of 10% of the greater of the benefit obligation or the market value of assets are amortized over the average remaining service period of active employees or the remaining average expected life if a plan’s participants are predominantly inactive. Derivatives: We utilize derivative instruments for financial risk management activities. In these activities, we may use futures, forwards, options and swaps, individually or in combination, to mitigate our exposure to fluctuations in prices of crude oil and natural gas, as well as changes in interest and foreign currency exchange rates.
All derivative instruments are recorded at fair value in our the Consolidated Balance Sheet. Our policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not designated as hedges are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges), or hedges of changes in fair value of recognized assets and liabilities or of unrecognized firm commitments (fair value hedges). Changes in fair value of derivatives that are designated as cash flow hedges are recorded as a component of other comprehensive income (loss). Amounts included in Accumulated other comprehensive income (loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged commitmentitem is recorded as an adjustment to its carrying amount and recognized currently in earnings.
Fair Value Measurements:We use various valuation approaches in determining fair value for financial instruments, including the market and income approaches. Our fair value measurements also include non-performance risk and time value of money considerations. Counterparty credit is considered for receivable balances,financial assets, and our credit is considered for accruedfinancial liabilities. We also record certain nonfinancial assets and liabilities at fair value when required by GAAP. These fair value measurements are recorded in connection with business combinations, qualifying nonmonetary exchanges, the initial recognition of asset retirement obligations and any impairment of long‑lived assets, equity method investments or goodwill. We determine fair value in accordance with the fair value measurements accounting standard which established a hierarchy for the inputs used to measure fair value based on the source of the inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3), including discounted cash flows and other unobservable data. Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market. Multiple inputs may be used to measure fair value; however, the level ofassigned to a fair value assigned for each physical derivative and financial asset or liabilitymeasurement is based on the lowest significant input level within this fair value hierarchy. Details on the methods and assumptions used to determine the fair values are as follows:
Fair value measurements based on Level 1 inputs: Measurements that are most observable are based on quoted prices of identical instruments obtained from the principal markets in which they are traded. Closing prices are both readily available and representative of fair value. Market transactions occur with sufficient frequency and volume to assure liquidity. Fair value measurements based on Level 2 inputs: Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. Measurements based on Level 2 inputs include over-the-counter derivative instruments that are priced on an exchange tradedexchange-traded curve but have contractual terms that are not identical to exchange tradedexchange-traded contracts. Fair value measurements based on Level 3 inputs: Measurements that are least observable are estimated from related market data, determined from sources with little or no market activity for comparable contracts or are positions with longer durations. Fair values determined using discounted cash flows and other unobservable data are also classified as Level 3. Netting of Financial Instruments:We generally enter into master netting arrangements to mitigate legal and counterparty credit risk. Master netting arrangements are generally accepted overarching master contracts that govern all individual transactions with the same counterparty entity as a single legally enforceable agreement. The U.S. Bankruptcy Code provides for the enforcement of certain termination and netting rights under certain types of contracts upon the bankruptcy filing of a counterparty, commonly known as the “safe harbor” provisions. If a master netting arrangement provides for termination and netting upon the counterparty’s bankruptcy, these rights are generally enforceable with respect to “safe harbor” transactions. If these arrangements provide the right of offset and our intent and practice is to offset amounts in the case of such a termination, our policy is to record the fair value of derivative assets and liabilities on a net basis. In the normal course of business, we rely on legal and credit risk mitigation clauses
providing for adequate credit assurance as well as close‑out netting, including two‑party netting and single counterparty multilateral netting. As applied to us, “two‑party netting” is the right to net amounts owing under safe harbor transactions between a single defaulting counterparty entity and a single Hess entity, and “single counterparty multilateral netting” is the right to net amounts owing under safe harbor transactions among a single defaulting counterparty entity and multiple Hess entities. We are reasonably assured that these netting rights would be upheld in a bankruptcy proceeding in the U.S. in which the defaulting counterparty is a debtor under the U.S. Bankruptcy Code.
Share-based Compensation: We account for share-based compensation underbased on the fair value method of accounting.the award on the date of grant. The fair value of all share‑based compensation is recognized over the requisite service period for the entire award, whether the award was granted with ratable or cliff vesting terms, net of actual forfeitures. We estimate fair value at the date of grant using a Black‑Scholes
valuation model for employee stock options and a Monte Carlo simulation model for performance share units.units (PSUs). Fair value of restricted stock is based on the market value of the underlying shares at the date of grant.
Foreign Currency Translation: The U.S. Dollar is the functional currency (primary currency in which business is conducted) for our foreign operations. Adjustments resulting from remeasuring monetary assets and liabilities that are denominated in a currency other than the functional currency are recorded in Other, net in theStatement of Consolidated Income. For our former operations in Norway that did not use the U.S. Dollar as the functional currency, adjustments resulting from translating foreign currency assets and liabilities into U.S. Dollars were recorded in the Consolidated Balance Sheet in a separate component of equity titled Accumulated other comprehensive income (loss) prior to the disposition. See Note 3, Dispositions. Maintenance and Repairs: Maintenance and repairs are expensed as incurred. Capital improvements are recorded as additions in Property, plant and equipment. Environmental Expenditures: We accrue and expense the undiscounted environmental costs necessary to remediate existing conditions related to past operations when the future costs are probable and reasonably estimable. At year‑end 2018,2021, our reserve for estimated remediation liabilities was approximately $80$60 million. Environmental expenditures that increase the life or efficiency of property or reduce or prevent future adverse impacts to the environment are capitalized.New Accounting Pronouncements: In February 2016, the FASB issued ASU 2016-02, Leases, as a new ASC Topic, ASC 842. The new standard supersedes ASC 840 and will require the recognition of right-of-use assets and lease liabilities for all leases with lease terms greater than one year, including leases currently treated as operating leases under ASC 840. ASC 842 is effective for us beginning in the first quarter of 2019. We have elected to adopt ASC 842 using the modified retrospective method which allows application of the new standard prospectively from the date of adoption with a cumulative effect adjustment, if any, recorded to Retained Earnings at the date of adoption. Accordingly, comparative financial statements for periods prior to the adoption date of ASC 842 will not be affected. In addition, we have elected to apply a number of practical expedients permitted by the ASU, including not needing to reassess: (i) whether existing contracts are (or contain) leases, (ii) whether the lease classification for existing leases would differ under ASC 842, (iii) whether initial direct costs incurred for existing leases are capitalizable under ASC 842, and (iv) land easements that were not previously accounted for as leases under ASC 840. We have completed our implementation plan to adopt ASU 842, but we continue to monitor standard setting activity and our internal controls to comply with the accounting and disclosure requirements. Upon adoption on January 1, 2019, we expect to recognize operating and finance lease obligations totaling approximately $1.2 billion, of which approximately $390 million of liabilities at December 31, 2018, are included in the Consolidated Balance Sheet. We enter into various leases in the normal course of business primarily for drilling rigs, a floating storage and offloading vessel, support vessels, and office space.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses. This ASU makes changes to the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standard requires the use of a forward-looking "expected loss" model compared to the current "incurred loss" model. This ASU is effective for us beginning in the first quarter of 2020, with early adoption permitted beginning in the first quarter of 2019. We are currently assessing the impact of the ASU on our Consolidated Financial Statements.
2.
RevenueRevenue from contracts with customers on a disaggregated basis in 2018 was as follows (in millions):
| | Exploration and Production | | | Midstream | | | Eliminations | | | Total | |
| | United States | | | Europe | | | Africa | | | Asia | | | E&P Total | | | | | | | | | | | | | |
Sales of our net production volumes: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Crude oil revenue | | $ | 2,832 | | | $ | 153 | | | $ | 434 | | | $ | 104 | | | $ | 3,523 | | | $ | — | | | $ | — | | | $ | 3,523 | |
Natural gas liquids revenue | | | 308 | | | | — | | | | — | | | | — | | | | 308 | | | | — | | | | — | | | | 308 | |
Natural gas revenue | | | 176 | | | | 11 | | | | 21 | | | | 651 | | | | 859 | | | | — | | | | — | | | | 859 | |
Sales of purchased oil and gas | | | 1,661 | | | | — | | | | 93 | | | | 14 | | | | 1,768 | | | | — | | | | — | | | | 1,768 | |
Intercompany revenue | | | — | | | | — | | | | — | | | | — | | | | — | | | | 713 | | | | (713 | ) | | | — | |
Total revenues from contracts with customers | | | 4,977 | | | | 164 | | | | 548 | | | | 769 | | | | 6,458 | | | | 713 | | | | (713 | ) | | | 6,458 | |
Other operating revenues (a) | | | (135 | ) | | | — | | | | — | | | | — | | | | (135 | ) | | | — | | | | — | | | | (135 | ) |
Total sales and other operating revenues | | $ | 4,842 | | | $ | 164 | | | $ | 548 | | | $ | 769 | | | $ | 6,323 | | | $ | 713 | | | $ | (713 | ) | | $ | 6,323 | |
(a)
| Includes gains (losses) on commodity derivatives.
|
Exploration and Production
The E&P segment recognizes revenue from the sale of crude oil, NGLs, and natural gas as performance obligations under contracts with customers are satisfied. Our responsibilities to deliver each unit of quantity of crude oil, NGL, and natural gas under these contracts represent separate, distinct performance obligations. These performance obligations are satisfied at the point in time control of each unit of quantity transfers to the customer. Generally, the control of each unit of quantity transfers to the customer upon the transfer of legal title at the point of physical delivery. Pricing is variable and is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials.
For long-term international natural gas contracts with ship-or-pay provisions, our obligation to stand-ready to provide a minimum volume over each commitment period represents separate, distinct performance obligations. Penalties owed against future deliveries of natural gas due to delivery of volumes below minimum delivery commitments are recognized as reductions to revenue in the commitment period when the shortfall occurs. Long-term international natural gas contracts may also contain take-or-pay provisions whereby the customer is required to pay for volumes not taken that are below the minimum volume commitment, but the customer has certain make-up rights to receive shortfall volumes in subsequent periods. Shortfall payments received from customers when volumes purchased are below the minimum volume commitment are deferred upon receipt as a contract liability. Revenue is recognized at the earlier of when we deliver the make-up volumes in subsequent periods or when it becomes remote that the customer will exercise their make-up rights.
Certain crude oil, NGL, and natural gas volumes are purchased by Hess from third-parties, including working interest partners and royalty owners in certain Hess-operated properties, before they are sold to customers. Where control over the crude oil, NGLs, or natural gas transfers to Hess before the volumes are transferred to the customer, revenue and the associated cost of purchased volumes are presented on a gross basis in the Statement of Consolidated Income within Sales and other operating revenues and Marketing, including purchased oil and gas, respectively. Where control of crude oil, NGLs, or natural gas is not transferred to Hess, revenue is presented net of the associated cost of purchased volumes within Sales and other operating revenues in the Statement of Consolidated Income.
Contract types
The following is a summary of contract types for our E&P segment:
Crude oil, NGLs, and natural gas – United States (U.S.): Contracts with customers for the sale of U.S. crude oil, NGLs, and natural gas primarily include those contracts that involve the short-term sale of volumes during a specified period, and those contracts that automatically renew on a periodic basis until either party cancels. We have certain long-term contracts with customers for the sale of U.S. natural gas and NGLs that have remaining durations of less than ten years. Contracts may specify a fixed volume for delivery subject to tolerance thresholds or may specify a percentage of production to be delivered from a particular location. Pricing is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials.
Crude oil – International: Contracts with customers for the sale of international crude oil involve the short-term sale of volumes during a specified period. These contracts specify a fixed volume for delivery subject to tolerance thresholds. Pricing is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials, shortly after control of the volumes transfers to the customer.
Natural gas – International: Contracts with customers for the sale of natural gas are in the form of natural gas sales agreements with government entities that have durations that are aligned with the durations of production sharing contracts or other contractual arrangements with host governments. Pricing is determined using contractual formulas that are based on the price of alternative fuels as obtained from price indices and other factors. These contracts also specify a minimum volume we are obligated to make available during specified periods within the contract term and may specify minimum volumes the customer is obligated to purchase during specified periods within the contract term. If we do not deliver the volume properly nominated by the customer, the customer is entitled to a price discount on future volumes equivalent to the shortfall delivery. Under certain international natural gas sales agreements, if the customer purchases natural gas volumes below the minimum volume commitment, the customer is required to pay us for the shortfall volumes and may receive make-up volumes in subsequent periods at no additional cost.
Revenue from sale of third-party purchased volumes: Crude oil, NGLs, and natural gas are purchased by Hess from third-parties, including working interest partners and royalty owners in certain Hess-operated properties, before they are sold to customers. The types of contracts with customers for the sale of third-party purchased volumes are the same as those described above.
Contract Balances
Our right to receive or collect payment from the customer is aligned with the timing of revenue recognition except in situations when we receive shortfall payments under contracts with take-or-pay provisions with customer make-up rights or where we recognize a liability for price discounts owed against future deliveries as a result of not shipping minimum volume commitments. At December 31, 2018 and 2017, there were no contract assets or contract liabilities, respectively.
Generally, we receive payments from customers on a monthly basis, shortly after the physical delivery of the crude oil, NGLs, or natural gas. In 2018, we did not recognize any impairment losses on receivables arising from contracts with customers.
Transaction Price Allocated to Remaining Performance Obligations
The transaction price allocated to our wholly unsatisfied performance obligations on uncompleted contracts is variable. Further, many of our contracts with customers have durations of less than twelve months. Accordingly, we have elected under the provisions of ASC 606 the exemption from disclosure of revenue recognizable in future periods as these performance obligations are satisfied.
Sales-based Taxes
We exclude sales-based taxes that are collected from customers from the transaction price in our contracts with customers. Accordingly, revenue from contracts with customers is net of sales-based taxes that are collected from customers and remitted to taxing authorities.
Midstream
Our Midstream segment provides gathering, compression, processing, fractionation, storage, terminaling, loading and transportation, and water handling services.
The Midstream segment has multiple long-term, fee-based commercial agreements with a marketing subsidiary of Hess, each generally with an initial ten-year term that can be extended for an additional ten-year term at the unilateral right of our Midstream segment. These contracts have minimum volumes the customer is obligated to provide each calendar quarter. The minimum volume commitments are subject to fluctuation based on nominations covering substantially all of our E&P segment’s production and projected third-party volumes that will be purchased in the Bakken. As the minimum volume commitments are subject to fluctuation, and as these contracts contain fee inflation escalators and fee recalculation mechanisms, substantially all of the transaction price at contract inception is variable. The Midstream segment also provides water handling services to a subsidiary of Hess for an agreed-upon fee per barrel or the reimbursement of third-party fees.
The Midstream segment’s responsibilities to provide each of the above services for each year under each of the commercial agreements are considered separate, distinct performance obligations. Revenue is recognized for each performance obligation under these commercial agreements over-time as services are rendered using the output method, measured using the amount of volumes serviced during the period. The Midstream segment has elected the practical expedient under the provisions of ASC 606 to recognize revenue in the amount it is entitled to invoice. If the commercial agreements have take-or-pay provisions, the Midstream segment’s responsibility to stand-ready to service a minimum volume over each quarterly commitment period represent separate, distinct performance obligations. Shortfall payments received under take-or-pay provisions are recognized as revenue in the calendar quarter the shortfall occurs as the customer does not have make-up rights beyond the calendar quarter
end of the quarterly commitment period. All revenues, receivables, and contract balances arising from the commercial agreements between the Midstream segment and the Hess marketing subsidiary that is the counterparty to the commercial agreements are eliminated upon consolidation.
3. Dispositions
2018: We completed the sale of our joint venture interests in the Utica shale play in eastern Ohio in August for proceeds of $396 million, after normal closing adjustments, and recognized a pre-tax gain of $14 million ($14 million after income taxes). In addition, we completed the sale of our interests in Ghana for total consideration of $100 million, consisting of a $25 million payment that was received at closing and a further payment of $75 million that is payable to us upon the buyer receiving government approval for a Plan of Development on the Deepwater Tano Cape Three Points Block. The receipt of proceeds at closing resulted in a pre-tax gain of $10 million ($10 million after income taxes).
2017: We completed the sale of our enhanced oil recovery assets in the Permian Basin in August for proceeds of $597 million, after normal closing adjustments, and recognized a pre-tax gain of $273 million ($280 million attributable to Hess Corporation after income taxes and noncontrolling interest). This sale transaction included both upstream and midstream assets resulting in an after-tax gain of $314 million allocated to the E&P segment, and an after-tax loss of $34 million allocated to the Midstream segment. In November, we completed the sale of our interests in Equatorial Guinea for proceeds of $449 million, after normal closing adjustments, which resulted in a pre-tax gain of $486 million ($486 million after income taxes). In December, we completed the sale of our interests in the Valhall and Hod assets, offshore Norway for proceeds of $2,056 million, after normal closing adjustments, which resulted in a pre-tax loss of $857 million ($857 million after income taxes). This loss includes a recognition in earnings of $900 million for cumulative translation adjustments that were previously reflected within Accumulated Other Comprehensive Income (Loss) in Stockholders’ Equity. We also sold certain U.S. onshore assets for proceeds totaling approximately $194 million and recognized net pre-tax gains totaling $12 million ($12 million after income taxes).
Pre-tax income (loss) associated with our interests in Equatorial Guinea and Norway, excluding the financial statement impacts resulting from the asset sales in 2017, were as follows for the three years ended December 31:
| | 2018 | | | 2017 | | | 2016 | |
| | (In millions) | |
Equatorial Guinea (a) | | $ | — | | | $ | 69 | | | $ | (95 | ) |
Norway (b) | | | — | | | | (55 | ) | | | (195 | ) |
Income (Loss) from Continuing Operations Before Income Taxes | | $ | — | | | $ | 14 | | | $ | (290 | ) |
(a)
| Pre-tax income for 2017 excludes the gain of $486 million related to sale of our assets in November 2017.
|
(b)
| Pre-tax loss for 2017 excludes the loss of $857 million related to sale of our assets in December 2017. In addition, the 2017 loss excludes a pre-tax impairment charge of $2,503 million associated with the disposition.
|
2016: We sold miscellaneous non-core assets during the year for proceeds totaling approximately $100 million and recognized net pre-tax gains totaling $23 million ($14 million after income taxes).
The asset sales in 2018 and 2017 high grade our portfolio by divesting of lower return, mature assets to invest in higher return assets, primarily in Guyana and the Bakken, and to fund purchases of common stock and retirement of debt in 2018.
4. Inventories
Inventories at December 31 were as follows:
| | | | | 2021 | | 2020 |
| | 2018 | | | 2017 | | | | | |
| | (In millions) | | | (In millions) |
Crude oil and natural gas liquids | | $ | 74 | | | $ | 59 | | Crude oil and natural gas liquids | $ | 52 | | | $ | 226 | |
Materials and supplies | | | 171 | | | | 173 | | Materials and supplies | 171 | | | 152 | |
Total Inventories | | $ | 245 | | | $ | 232 | | Total Inventories | $ | 223 | | | $ | 378 | |
At December 31, 2020, crude oil inventories included $164 million associated with the cost of 4.2 million barrels of crude oil transported and stored on 2 chartered VLCCs for sale in Asian markets. The 2 VLCC cargos were sold in the first quarter of 2021.
5.
3. Property, Plant and Equipment
Property, plant and equipment at December 31 were as follows:
| | | | | 2021 | | 2020 |
| | 2018 | | | 2017 | | | | | |
| | (In millions) | | | (In millions) |
Exploration and Production | | | | | | | | | Exploration and Production | | | |
Unproved properties | | $ | 394 | | | $ | 520 | | Unproved properties | $ | 184 | | | $ | 164 | |
Proved properties | | | 3,124 | | | | 3,162 | | Proved properties | 2,877 | | | 2,930 | |
Wells, equipment and related facilities | | | 26,173 | | | | 25,550 | | Wells, equipment and related facilities | 23,745 | | | 23,224 | |
| | | 29,691 | | | | 29,232 | | | 26,806 | | | 26,318 | |
Midstream | | | 3,492 | | | | 3,219 | | Midstream | 4,342 | | | 4,163 | |
Corporate and Other | | | 39 | | | | 53 | | Corporate and Other | 30 | | | 38 | |
Total — at cost | | | 33,222 | | | | 32,504 | | Total — at cost | 31,178 | | | 30,519 | |
Less: Reserves for depreciation, depletion, amortization and lease impairment | | | 17,139 | | | | 16,312 | | Less: Reserves for depreciation, depletion, amortization and lease impairment | 16,996 | | | 16,404 | |
Property, Plant and Equipment — Net | | $ | 16,083 | | | $ | 16,192 | | Property, Plant and Equipment — Net | $ | 14,182 | | | $ | 14,115 | |
Capitalized Exploratory Well Costs: The following table discloses the amount of capitalized exploratory well costs pending determination of proved reserves at December 31 and the changes therein during the respective years:
| | | | | 2021 | | 2020 | | 2019 |
| | 2018 | | | 2017 | | | 2016 | | | | | | | |
| | (In millions) | | | (In millions) |
Balance at January 1 | | $ | 304 | | | $ | 597 | | | $ | 1,415 | | Balance at January 1 | $ | 459 | | | $ | 584 | | | $ | 418 | |
Additions to capitalized exploratory well costs pending the determination of proved reserves | | | 128 | | | | 116 | | | | 79 | | Additions to capitalized exploratory well costs pending the determination of proved reserves | 222 | | | 111 | | | 224 | |
Reclassifications to wells, facilities and equipment based on the determination of proved reserves | | | — | | | | (165 | ) | | | — | | Reclassifications to wells, facilities and equipment based on the determination of proved reserves | — | | | (111) | | | (58) | |
Capitalized exploratory well costs charged to expense | | | (14 | ) | | | (268 | ) | | | (897 | ) | Capitalized exploratory well costs charged to expense | — | | | (125) | | | — | |
Dispositions and other | | | — | | | | 24 | | | | — | | |
| Balance at December 31 | | $ | 418 | | | $ | 304 | | | $ | 597 | | Balance at December 31 | $ | 681 | | | $ | 459 | | | $ | 584 | |
Number of Wells at December 31 | | | 24 | | | | 12 | | | | 17 | | Number of Wells at December 31 | 35 | | | 22 | | | 31 | |
During the three years ended December 31, 2018,2021, additions to capitalized exploratory well costs primarily related to drilling at the Stabroek Block, offshore Guyana. OtherIn 2019, other drilling activity included the BungaEsox prospect in Malaysia during 2018 and in the Gulf of Mexico during 2016. Mexico.
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
primarily relatedin 2020 resulted from sanctions of the Payara Field development, the third sanctioned project on the Stabroek Block, offshore Guyana, and an additional phase of development at the North Malay Basin, offshore Peninsular Malaysia. In 2019, reclassifications to
thewells, facilities and equipment resulted from sanction of the
first phaseLiza Phase 2 development on the Stabroek Block and the Esox tieback well to the Tubular Bells Field in the Gulf of
Liza Field development, offshore Guyana in 2017.Mexico.
Capitalized exploratory well costs charged to expense
includein 2020 of $125 million primarily related to the
following:2018: In Canada, offshore Nova Scotia (Hess 50% participating interest), the operator, BP Canada, completed drillingnorthern portion of the Aspy exploration well, which did not encounter commercial quantities of hydrocarbons. As a result, we expensed well costs totaling $120 million of which $106 million were incurred and expensed in 2018.
2017: In Ghana, at the Hess operated offshore Deepwater Tano/Cape Three Points licenseShenzi Field (Hess 50% license interest), management determined in the fourth quarter of 2017 that it would not develop the previously discovered fields. As a result, we recorded a charge of $268 million to write-off previously capitalized exploration wells.
2016: At the Hess-operated Equus natural gas project, offshore the North West Shelf of Australia in the fourth quarter of 2016, we terminated a joint front-end engineering study with a third-party natural gas liquefaction joint venture and notified the Australian government of our intent to defer the project. As a result, we expensed all well costs associated with the project, including an exploration well completed in the second quarter of 2016, totaling $830 million. These properties were sold in 2017. In the second quarter of 2016, we expensed costs associated with two exploration wells at the non-operated Sicily project28%) in the Gulf of Mexico where hydrocarbons were encountered but we decided not to pursue the project due to reprioritization of our forward capital program in response to the low commodity price environment and the limited time remaining on the leases. We also expensed the cost of an unsuccessful exploration well at the non-operated Melmar projectsignificant decline in the Gulf of Mexico, where noncommercial quantities of hydrocarbons were encountered.
crude oil prices. The preceding table excludes exploratory dry holewell costs of $151 million in 2018 (2017: $0 million; 2016: $167 million), which were incurred and subsequently expensed in the same year. In 2018, these costs are associated with the Aspy well, offshore Nova Scotia, Canada, the Pontoenoe-1 well, offshore Suriname, the Sorubim-1 well on the Stabroek Block, offshore Guyana, and the Bunga Teruntum-1 well in North Malay Basin.
during 2021 of $11 million (2020: $67 million; 2019: $49 million).
Exploratory well costs capitalized for greater than one year following completion of drilling were $267$459 million at December 31, 2018,2021, separated by year of completion as follows (in millions):
2017 | | $ | 97 | |
2016 | | | — | |
2015 | | | 166 | |
2014 | | | — | |
2013 | | | 4 | |
| | $ | 267 | |
| | | | | |
| 2020 | $ | 117 | |
| 2019 | 173 | |
| 2018 | 105 | |
| 2017 | 27 | |
| 2016 and prior | 37 | |
| | $ | 459 | |
Gulf of Mexico: Guyana:Approximately 45%90% of the capitalized well costs in excess of one year relatesrelate to the appraisal of the northern portion of the Shenzi Field (Hess 28% participating interest) in the Gulf of Mexico,successful exploration wells where hydrocarbons were encountered inon the Stabroek Block (Hess 30%). In the fourth quarter of 2015. Following exploration and2021, the operator submitted a fourth development plan for the Yellowtail Field to the Government of Guyana for approval.The operator also plans further appraisal drilling activities completed by the operator in prior years on adjacent blocks to the northand is conducting pre-development planning for additional phases of our Shenzi blocks, the operator is planning to acquire 3D seismic in 2019 for use in development planning of the northern portion of the Shenzi Field.Guyana:development.
JDA: Approximately 35% of the capitalized well costs in excess of one year relates to the Liza-4, Payara-1, Payara-2 and Snoek-1 wells on the Stabroek Block, offshore Guyana (Hess 30%), where hydrocarbons were encountered. The operator plans to integrate the Liza-4 discovery into the second phase of development, which is expected to commence production by mid-2022. The operator plans to integrate the Payara-1 and Payara-2 discoveries into the third phase of development, which is expected to commence production as early as 2023. The Snoek discovery is expected to produce into the Liza Phase 1 FPSO under a subsequent phase of development.JDA: Approximately 15%8% of the capitalized well costs in excess of one year relates to the JDA (Hess 50%) in the Gulf of Thailand, (Hess 50%) where hydrocarbons were encountered in three3 successful exploration wells drilled in the western part of Block A-18. The operator has submitted a development plan concept to the regulator to facilitate ongoing commercial negotiations for an extension of the existing gas sales contract to include development of the western part of the Block.
Malaysia: Approximately 5%2% of the capitalized well costs in excess of one year relates to North Malay Basin (Hess 50%), offshore Peninsular Malaysia, (Hess 50%), where hydrocarbons were encountered in one1 successful exploration well drilled in the fourth quarterwell. Subsurface evaluation and pre-development studies are ongoing.
4. Hess Midstream LP
HIP was initially formed on May 21, 2015, with Hess selling 50% of
2015. In 2018, we completed four exploration wells and are conducting subsurface evaluationsHIP to GIP for
consideration in future phases of field development.6. Hess Infrastructure Partners LP
Onapproximately $2.6 billion on July 1, 2015, we sold2015. 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 50%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 InfrastructureMentor 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 (HIP)(Hess Midstream), which is taxed as a corporation for U.S. federal and state income tax purposes. Hess Midstream Partners changed its name to Global Infrastructure Partners (GIP)“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 1-for-1 basis.
In March 2021, Hess Midstream completed an underwritten public equity offering of 6.9 million Class A shares held by Hess and GIP. These Class A shares of Hess Midstream were obtained by Hess and GIP through the exchange of 6.9 million of their Class B units of HESM Opco. As a result of this transaction, Hess received net cash considerationproceeds of $70 million and recorded an increase in additional paid-in capital and noncontrolling interests of $56 million and $41 million, respectively. The increase of $41 million in noncontrolling interests is comprised of $14 million resulting from the change in ownership and $27 million due to the recognition of a deferred tax asset as a result of an increase in the tax basis of Hess Midstream LP's investment in HESM Opco.
In August 2021, HESM Opco repurchased 31.25 million Class B units held by Hess and GIP for $750 million. Hess received net proceeds of $375 million. HESM Opco issued $750 million in aggregate principal amount of 4.250% fixed-rate senior unsecured notes due 2030 in a private offering to finance the repurchase. The transaction resulted in an increase in additional paid-in capital and a decrease in noncontrolling interests of $28 million, and an increase in deferred tax assets and noncontrolling interests of $15 million due to a decrease in the book basis of Hess Midstream LP's investment in HESM Opco. The $375 million paid to GIP was recorded as a reduction to noncontrolling interests.
In October 2021, Hess Midstream completed an underwritten public equity offering of approximately $2.6 billion. HIP8.6 million Class A Shares held by Hess and its affiliates primarily comprise ourGIP. These Class A shares of Hess Midstream operating segment.were obtained by Hess and GIP through the exchange of approximately 8.6 million of their Class B units of HESM Opco. As a result of this transaction, Hess received net proceeds of $108 million and recorded an increase in additional paid-in capital and noncontrolling interests of $96 million and $62 million, respectively. The Midstream operating segment currently generates substantially allincrease of its revenues under long-term, fee-based agreements with our E&P operating segment$62 million in noncontrolling interests is comprised of $12 million resulting from the change in ownership and intends$50 million due to pursue additional throughput volumes from third-partiesthe recognition of a deferred tax asset as a result of an increase in the Williston Basin area. We operatetax basis of Hess Midstream LP's investment in HESM Opco.
After giving effect to the
above transactions in 2021, public shareholders of Class A shares of Hess Midstream
assetsown approximately 13%, and
operations, including routineHess and
emergency maintenance and repair services under various operational and administrative services agreements.The tariff agreements between our E&P operating segment and the Midstream entities became effective on January 1, 2014 and are 10-year, fee-based commercial agreements, with HIP having the sole option to renew the agreements for an additional 10-year term. These agreements include minimum volume commitments based on dedicated production, inflation escalators and fee recalculation mechanisms. The Midstream segment has minimal direct commodity price exposure, and the E&P segment retains ownershipGIP each own approximately 43.5%, of the crude oil, naturalconsolidated entity on an as-exchanged basis at December 31, 2021.
Little Missouri 4 (LM4) is a 200 million standard cubic feet per day gas or NGLs processed, terminaled, stored or transported byprocessing plant located south of the Midstream segment.We consolidate the activitiesMissouri River in McKenzie County, North Dakota, that was constructed as part of HIP, a 50/50 joint venture between Hess CorporationMidstream and GIP,Targa Resources Corp. Hess Midstream has a natural gas processing agreement with LM4 under which qualifies asit pays a variable interest entity (VIE) under U.S. GAAP. We have concluded that weprocessing fee and reimburses LM4 for its proportionate share of electricity costs. In 2021, these processing fees were $28 million (2020: $26 million; 2019: $6 million) and are the primary beneficiary of the VIE, as definedincluded in
Operating costs and expenses in the accounting standards, since we have the power, through our 50% ownership, to direct those activities that most significantly impact the economic performanceStatement of HIP. This conclusion was based on a qualitative analysis that considered HIP’s governance structure, the commercial agreements between HIP and us, and the voting rights established between the members, which provide us the ability to control the operations of HIP.Consolidated Income
. At December 31,
2018, HIP2021, Hess Midstream liabilities totaling
$1,105$2,694 million
(2017: $1,065(2020: $2,026 million) are on a nonrecourse basis to Hess Corporation, while
HIPHess Midstream assets available to settle the obligations of
HIPHess Midstream included
Cashcash and cash equivalents totaling
$109$2 million
(2017: $356(2020: $3 million)
and Property,, property, plant and equipment, net totaling
$2,664$3,125 million
(2017: $2,520(2020: $3,111 million)
and an equity-method investment in LM4 of $102 million (2020: $108 million).
66
7. Hess Midstream Partners LP – Initial Public Offering
In April 2017, Hess Midstream Partners LP (the “Partnership”), sold 16,997,000 common units representing limited partner interests
5. Accrued Liabilities
The following table provides detail of our accrued liabilities at a price of $23 per unit in an initial public offering (IPO) for net proceeds of $365.5 million, of which $350 million was distributed equally to Hess CorporationDecember 31:
| | | | | | | | | | | |
| | 2021 | | 2020 |
| | | |
| | (In millions) |
| Accrued capital expenditures | $ | 479 | | | $ | 345 | |
| Accrued operating and marketing expenditures | 462 | | | 325 | |
| Accrued payments to royalty and working interest owners | 253 | | | 170 | |
| Current portion of asset retirement obligations | 185 | | | 105 | |
| Accrued interest on debt | 138 | | | 126 | |
| Accrued compensation and benefits | 124 | | | 117 | |
| Other accruals | 69 | | | 63 | |
| Total Accrued Liabilities | $ | 1,710 | | | $ | 1,251 | |
6. Leases
Operating and GIP. The Partnership owns an approximate 20% controlling interest in the operating companies that comprise our midstream joint venture, while HIP, the 50/50 joint venture between Hess Corporation and GIP, owns the remaining 80%. Hess Corporation and GIP each own a direct 33.75% limited partner interest in the Partnership and a 50% indirect ownership interest through HIP in the Partnership’s general partner, which has a 2% economic interest in the Partnership plus incentive distribution rights. The public unit holders own a 30.5% limited partner interest in the Partnership.
8. Debt
Total debtfinance lease obligations at December 31 consisted ofincluded in the following:
Consolidated Balance Sheet were as follows: | | 2018 | | | 2017 | |
| | (In millions) | |
Debt - Hess Corporation: | | | | | | | | |
Fixed-rate public notes: | | | | | | | | |
8.1% due 2019 | | $ | — | | | $ | 349 | |
3.5% due 2024 | | | 298 | | | | 297 | |
4.3% due 2027 | | | 992 | | | | 991 | |
7.9% due 2029 | | | 463 | | | | 500 | |
7.3% due 2031 | | | 627 | | | | 679 | |
7.1% due 2033 | | | 537 | | | | 596 | |
6.0% due 2040 | | | 740 | | | | 740 | |
5.6% due 2041 | | | 1,234 | | | | 1,234 | |
5.8% due 2047 | | | 493 | | | | 493 | |
Total fixed-rate public notes | | | 5,384 | | | | 5,879 | |
Capital lease obligations | | | 269 | | | | — | |
Financing obligations associated with floating production system | | | 40 | | | | 118 | |
Fair value adjustments - interest rate hedging | | | (2 | ) | | | — | |
Total Debt - Hess Corporation | | $ | 5,691 | | | $ | 5,997 | |
| | | | | | | | |
Debt - Midstream: | | | | | | | | |
Fixed-rate notes: 5.6% due 2026 - HIP | | $ | 787 | | | $ | 785 | |
Term loan A facility - HIP | | | 194 | | | | 195 | |
Total Debt - Midstream | | $ | 981 | | | $ | 980 | |
| | | | | | | | |
Total Debt: | | | | | | | | |
Current maturities of long-term debt | | $ | 67 | | | $ | 580 | |
Long-term debt | | | 6,605 | | | | 6,397 | |
Total Debt | | $ | 6,672 | | | $ | 6,977 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases | | Finance Leases |
| | | | | | | |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
| (In millions) |
| Right-of-use assets — net (a) | $ | 352 | | | $ | 426 | | | $ | 144 | | | $ | 168 | |
| Lease obligations: | | | | | | | |
| Current | $ | 70 | | | $ | 63 | | | $ | 19 | | | $ | 18 | |
| Long-term | 394 | | | 478 | | | 200 | | | 220 | |
| Total lease obligations | $ | 464 | | | $ | 541 | | | $ | 219 | | | $ | 238 | |
(a)At December 31, 2018,2021, finance lease ROU assets had a cost of $212 million (2020: $212 million) and accumulated amortization of $68 million (2020: $44 million).
Lease obligations represent 100% of the maturity profilepresent value of total debtfuture minimum lease payments in the lease arrangement. Where we have contracted directly with a lessor in our role as operator of an unincorporated oil and gas venture, we bill our partners their proportionate share for reimbursements as payments under lease agreements become due pursuant to the terms of our joint operating and other agreements.
The nature of our leasing arrangements at December 31, 2021 was as follows:
| | Total | | | Hess Corporation | | | Midstream | |
| | (In millions) | |
2019 | | $ | 67 | | | $ | 56 | | | $ | 11 | |
2020 | | | 32 | | | | 17 | | | | 15 | |
2021 | | | 34 | | | | 18 | | | | 16 | |
2022 | | | 171 | | | | 19 | | | | 152 | |
2023 | | | 21 | | | | 21 | | | | — | |
Thereafter | | | 6,347 | | | | 5,560 | | | | 787 | |
Total debt (excluding interest) | | $ | 6,672 | | | $ | 5,691 | | | $ | 981 | |
Debt – Hess Corporation:
Fixed-rate public notes:
At December 31, 2018, Hess Corporation’s fixed-rate public notes had a gross principal amountOperating leases: In the normal course of $5,438 million (2017: $5,938 million)business, we primarily lease drilling rigs, equipment, logistical assets (offshore vessels, aircraft, and a weighted average interest rate of 5.9% (2017: 6.0%). Our long‑term debt agreements, including the revolving credit facility, contain financial covenants that restrict the amount of total borrowingsshorebases), and secured debt. The most restrictive of these covenants allow us to borrow up to an additional $3,098 million of secured debt at December 31, 2018. Capitalized interest was $20 million in 2018 (2017: $86 million; 2016: $61 million).
In 2018, we paid $553 million to redeem $350 million principal amount of 8.125% notes due 2019 and to purchase other notes with a carrying value of $150 million. As a result, we recorded total losses on debt extinguishment of $53 million in 2018 (2017: $0 million; 2016: $148 million). Concurrent with the redemption of the 2019 notes, we terminated interest rate swaps with a notional amount of $350 million.
Capital lease:
office space.
Finance leases: In 2018, we entered into a sale and lease-back arrangement for a floating storage and offloading vessel (FSO) to handle produced condensate at North Malay Basin, offshore Peninsular Malaysia (Hess operated – 50%). Pursuant to the sale agreement, we received total proceeds of approximately $260 million, including our partner’s share of the proceeds which is reported in Accounts Payable on our Consolidated Balance Sheet. No gain or loss was recognized from the sale transaction. The lease agreement is for 16 years with four consecutive twelve-month renewal options that may be exercised at our discretion.Malaysia. At December 31, 2018,2021, the carrying valueremaining lease term for the FSO was 11.8 years.
Maturities of lease obligations at December 31, 2021 were as follows:
| | | | | | | | | | | |
| | Operating Leases | | Finance
Leases |
| | | |
| | (In millions) |
| 2022 | $ | 87 | | | $ | 36 | |
| 2023 | 75 | | | 36 | |
| 2024 | 69 | | | 36 | |
| 2025 | 64 | | | 36 | |
| 2026 | 49 | | | 31 | |
| Remaining years | 219 | | | 145 | |
| Total lease payments | 563 | | | 320 | |
| Less: Imputed interest | (99) | | | (101) | |
| Total lease obligations | $ | 464 | | | $ | 219 | |
The following information relates to the operating and finance leases at December 31:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Operating Leases | | Finance Leases |
| 2021 | | 2020 | | 2021 | | 2020 |
| Weighted average remaining lease term | 9.9 years | | 10.3 years | | 11.8 years | | 12.8 years |
| Range of remaining lease terms | 0.1 - 14.5 years | | 0.1 - 15.5 years | | 11.8 years | | 12.8 years |
| Weighted average discount rate | 4.1% | | 4.0% | | 7.9% | | 7.9% |
The components of lease costs for the years ended December 31, 2021 and 2020 were as follows:
| | | | | | | | | | | |
| 2021 | | 2020 |
| | | |
| (In millions) |
| Operating lease cost | $ | 88 | | | $ | 200 | |
| Finance lease cost: | | | |
| Amortization of leased assets | 24 | | | 31 | |
| Interest on lease obligations | 18 | | | 20 | |
| Short-term lease cost (a) | 137 | | | 199 | |
| Variable lease cost (b) | 21 | | | 38 | |
| Sublease income (c) | (17) | | | (15) | |
| Total lease cost | $ | 271 | | | $ | 473 | |
(a)Short-term lease cost is primarily attributable to equipment used in global exploration, development, production, and crude oil marketing activities. Future short-term lease costs will vary based on activity levels of our operated assets.
(b)Variable lease costs for drilling rigs result from differences in the minimum rate and the actual usage of the ROU asset during the lease period. Variable lease costs for logistical assets result from differences in stated monthly rates and total charges reflecting the actual usage of the ROU asset during the lease period. Variable lease costs for our office leases represent common area maintenance charges which have not been separated from lease components.
(c)We sublease certain of our office space to third parties under our head lease.
The above lease costs represent 100% of the lease
asset is $264 million andpayments due for the
carrying value of the lease obligation is $269 million, which represents 100% of the present value of future minimum lease payments, of which $15 million is included in Current maturities of long-term debt and $254 million is included in Long-term debt on our Consolidated Balance Sheet.period, including where we as operator have contracted directly with suppliers. As the payments under
the lease
agreementagreements where we are operator become due, we
will bill our
partnerpartners their proportionate share for reimbursement pursuant to the terms of our joint operating
agreement.Credit facility:
agreements. Reimbursements are not reflected in the table above. Certain lease costs above associated with exploration and development activities are included in capital expenditures.
Supplemental cash flow information related to leases for the years ended December 31, 2021 and 2020 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Leases | | Finance Leases |
| | | | | | | |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
| (In millions) |
| Cash paid for amounts included in the measurement of lease obligations: | | | | | | | |
| Operating cash flows (a) | $ | 87 | | | $ | 218 | | | $ | 18 | | | $ | 20 | |
| Financing cash flows (a) | — | | | — | | | 18 | | | 17 | |
| Noncash transactions: | | | | | | | |
| Leased assets recognized for new lease obligations incurred | 12 | | | 51 | | | — | | | — | |
| Changes in leased assets and lease obligations due to lease modifications (b) | 29 | | | 123 | | | — | | | — | |
(a)Amounts represent gross lease payments before any recovery from partners.
(b)In 2020, primarily related to negotiated extensions of an office lease and offshore drilling rig leases.
7. Debt
Total debt at December 31 consisted of the following:
| | | | | | | | | | | |
| | 2021 | | 2020 |
| | | |
| | (In millions) |
| Debt - Hess Corporation: | | | |
| Senior unsecured fixed-rate public notes: | | | |
| 3.500% due 2024 | $ | 299 | | | $ | 299 | |
| 4.300% due 2027 | 995 | | | 994 | |
| 7.875% due 2029 | 464 | | | 464 | |
| 7.300% due 2031 | 628 | | | 628 | |
| 7.125% due 2033 | 537 | | | 537 | |
| 6.000% due 2040 | 742 | | | 741 | |
| 5.600% due 2041 | 1,236 | | | 1,236 | |
| 5.800% due 2047 | 494 | | | 494 | |
| Total senior unsecured fixed-rate public notes | 5,395 | | | 5,393 | |
| Term loan facility | 497 | | | 988 | |
| Fair value adjustments - interest rate hedging | 2 | | | 5 | |
| Total Debt - Hess Corporation | $ | 5,894 | | | $ | 6,386 | |
| | | |
| Debt - Midstream (Hess Midstream Operations LP): | | | |
| Senior unsecured fixed-rate public notes: | | | |
| 5.625% due 2026 | $ | 791 | | | $ | 789 | |
| 5.125% due 2028 | 543 | | | 542 | |
| 4.250% due 2030 | 739 | | | — | |
| Total senior unsecured fixed-rate public notes | 2,073 | | | 1,331 | |
| Term loan A facility | 387 | | | 395 | |
| Revolving credit facility | 104 | | | 184 | |
| Total Debt - Midstream | $ | 2,564 | | | $ | 1,910 | |
| | | |
| Total Debt: | | | |
| Current portion of long-term debt | $ | 517 | | | $ | 10 | |
| Long-term debt | 7,941 | | | 8,286 | |
| Total Debt | $ | 8,458 | | | $ | 8,296 | |
At December 31, 2021, the maturity profile of total debt was as follows:
| | | | | | | | | | | | | | | | | |
| | Total | | Hess
Corporation | | Midstream |
| | | | | |
| | (In millions) |
| 2022 | $ | 520 | | | $ | 500 | | | $ | 20 | |
| 2023 | 30 | | | — | | | 30 | |
| 2024 | 744 | | | 300 | | | 444 | |
| 2025 | — | | | — | | | — | |
| 2026 | 800 | | | — | | | 800 | |
| Thereafter | 6,438 | | | 5,138 | | | 1,300 | |
| Total Borrowings | 8,532 | | | 5,938 | | | 2,594 | |
| Less: Deferred financing costs and discounts | (74) | | | (44) | | | (30) | |
| Total Debt (excluding interest) | $ | 8,458 | | | $ | 5,894 | | | $ | 2,564 | |
No interest was capitalized in 2021 or 2020 (2019: $38 million).
Debt – Hess Corporation:
Senior unsecured fixed-rate public notes:
At December 31, 2021, Hess Corporation’s $4fixed-rate public notes had a gross principal amount of $5,438 million (2020: $5,438 million) and a weighted average interest rate of 5.9% (2020: 5.9%). The indentures for our fixed-rate public notes limit the ratio of secured debt to Consolidated Net Tangible Assets (as that term is defined in the indentures) to 15%. As of December 31, 2021, Hess Corporation was in compliance with this financial covenant.
Term loan and credit facility:
In March 2020, we entered into a $1 billion syndicatedthree year term loan agreement with a maturity date of March 16, 2023. In July 2021, we repaid $500 million of the $1 billion outstanding under the term loan, and in February 2022, we repaid the remaining $500 million. The remaining $500 million has been classified as Current portion of long-term debt in our Consolidated Balance Sheet at December 31, 2021 as it was our intent to repay the remaining $500 million in the first quarter of 2022.
In 2019, we entered into a $3.5 billion revolving credit facility expires in Januarywith a maturity date of May 15, 2023. In April 2021, with commitments of $3.7 billion availablewe amended this credit facility by extending this facility's expiration date for one year to May 2024 and incorporating customary provisions for the final year.eventual replacement of LIBOR among other changes as set forth in the amended credit agreement. Borrowings on the facility will generally bear interest at 1.30%1.40% above LIBOR, though the London Interbank Offered Rate (LIBOR). The interest rate will be higheris subject to adjustment if our credit rating is lowered. The facility contains a financial covenant that limits the amount of the total borrowings on the last day of each fiscal quarter to 60% of the Corporation’s total capitalization, defined as total debt plus stockholders’ equity.changes. At December 31, 2018,2021, Hess Corporation had no outstanding borrowings or letters of credit under this facility.
The revolving credit facility and
term loan are subject to customary representations, warranties, customary events of default and covenants, including a financial covenant limiting the ratio of Total Consolidated Debt to Total Capitalization of the Corporation and its consolidated subsidiaries to 65%, and a financial covenant limiting the ratio of secured debt to Consolidated Net Tangible Assets of the Corporation and its consolidated subsidiaries to 15% (as these capitalized terms are defined in the credit agreement for the revolving credit facility and the term loan agreement). As of December 31, 2021, Hess Corporation was in compliance with thisthese financial covenant.covenants.
The most restrictive of the financial covenants related to our fixed-rate public notes and our term loan and revolving credit facility would allow us to borrow up to an additional $1,843 million of secured debt at December 31, 2021.
Other outstanding letters of credit at December 31 were as follows:
| | 2018 | | | 2017 | |
| | (In millions) | |
Committed lines (a) | | $ | 29 | | | $ | 29 | |
Uncommitted lines (a) | | | 255 | | | | 217 | |
Total | | $ | 284 | | | $ | 246 | |
(a)
| At December 31, 2018, committed and uncommitted lines have expiration dates throughout 2019.
|
| | | | | | | | | | | |
| | 2021 | | 2020 |
| | | |
| | (In millions) |
| Committed lines (a) | $ | 29 | | | $ | 54 | |
| Uncommitted lines (a) | 230 | | | 215 | |
| Total | $ | 259 | | | $ | 269 | |
(a)At December 31, 2021, committed and uncommitted lines have expiration dates through 2022.
Debt - Midstream:
Our Midstream segment holds the following non-recourse debt:
Hess Infrastructure Partners (HIP):
Senior unsecured fixed-rate public notes:
In November 2017, HIP issued $800 million in aggregate principal amount of 5.625% fixed-rate senior unsecured notes due in February 20262026. In December 2019, in connection with the acquisition of HIP and concurrently amended itscorporate restructuring described in Note 4, Hess Midstream LP, HESM Opco assumed $800 million of outstanding HIP senior unsecured credit facilities.notes in a par-for-par exchange. In addition, in December 2019, HESM Opco issued $550 million in aggregate principal amount of 5.125% fixed-rate senior unsecured notes due in 2028 to finance the acquisition of HIP used a portion of the proceeds from the note issuance toand repay outstanding borrowings under HIP’s credit facilitiesfacilities. In August 2021, HESM Opco issued $750 million in aggregate principal amount of 4.250% fixed-rate senior unsecured notes due in 2030 in a private offering to finance the repurchase of 31.25 million HESM Opco Class B units held by Hess and GIP. These senior unsecured notes are guaranteed by certain of HESM Opco’s direct and indirect wholly owned material domestic subsidiaries. These senior unsecured notes are non-recourse to fund a distribution to the partners. Under the amendedHess Corporation.
Credit facilities:
At December 31, 2021, HESM Opco had $1.4 billion of senior secured syndicated credit facilities
thematuring December 2024, consisting of a $1 billion 5-year
Term Loan A facility was reduced to $200 million and the 5-year syndicated revolving credit facility increased to $600 million from $400 million previously, with the maturity of both facilities extended to November 2022. The amended facilities are secured by first-priority perfected liens on substantially all of HIP’s and certain of its wholly-owned subsidiaries’ directly owned assets, including its equity interests in certain subsidiaries, subject to customary exclusions. The 5-year syndicated revolving credit facility
is expected to continueand a fully drawn $400 million 5-year term loan A facility. The revolving credit facility can be used for borrowings and letters of credit to fund
the joint venture’sHESM Opco’s operating activities,
capital expenditures, distributions and
capital expenditures.for other general corporate purposes. Borrowings under the 5-year
Term Loanterm loan A facility will generally bear interest at LIBOR plus an applicable margin ranging from 1.55% to 2.50%, while the applicable margin for the 5-year syndicated revolving credit facility ranges from 1.275% to 2.000%.
The interest rate continues to be subject to adjustmentPricing levels for the facility fee and interest-rate margins are based on
the joint venture’s leverageHESM Opco’s ratio
which is calculated asof total debt to
Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA)EBITDA (as defined in the credit facilities). If
HIPHESM Opco obtains an
investment grade credit rating, as defined in the amended credit agreement, pricing levels will be based on theHESM Opco’s credit ratings in effect from time to time. The joint venture is subjectcredit facilities contain covenants that require HESM Opco to customary covenantsmaintain a ratio of total debt to EBITDA (as defined in the credit agreement that include financial covenants that generally require a leverage ratio of no more than 5.0 to 1.0facilities) for the prior four fiscal quarters of not greater than 5.00 to 1.00 as of the last day of each fiscal quarter (5.50 to 1.00 during the specified period following certain acquisitions) and, prior to HESM Opco obtaining an interest coverageinvestment grade credit rating, a ratio which is calculated asof secured debt to EBITDA to cash interest expense, of no less than 2.25 to 1.0 for the prior four fiscal quarters. The amended credit agreement includes a secured leverage ratio testquarters of not to exceed 3.75greater than 4.00 to 1.00 for so long as of the facilities remain secured. HIP islast day of each fiscal quarter. HESM Opco was in compliance with all debtthese financial covenants at December 31, 2018, and its financial covenants do not currently impact its ability to issue indebtedness to fund future capital expenditures. At December 31, 2018, HIP’s revolving credit facility was undrawn and borrowings under the Term Loan A facility amounted to $197.5 million, excluding deferred issuance costs.
Hess Midstream Partners (the Partnership):
The Partnership has a $300 million 4-year senior secured syndicated revolving credit facility through March 2021 that can be used for borrowings and letters of credit to fund operating activities and capital expenditures of the Partnership. Borrowings on the credit facility will generally bear interest at LIBOR plus an applicable margin of 1.275%. The interest rate is subject to adjustment based on the Partnership’s leverage ratio, which is calculated as total debt to EBITDA. If the Partnership obtains credit ratings, pricing levels will be based on the credit ratings in effect from time to time. The Partnership is subject to customary covenants in the credit agreement, including financial covenants that generally require a leverage ratio of no more than 4.5 to 1.0 for the prior four fiscal quarters.2021. The credit facility isfacilities are secured by first priorityfirst-priority perfected liens on substantially all directly ownedof the assets of the PartnershipHESM Opco and its wholly-owneddirect and indirect wholly owned material domestic subsidiaries, including equity interests in subsidiaries,directly owned by such entities, subject to certain customary exclusions. OutstandingAt December 31, 2021, borrowings of $104 million were drawn
under
thisHESM Opco’s revolving credit facility,
and borrowings of $390 million, excluding deferred issuance costs, were drawn under HESM Opco’s term loan A facility. Borrowings under these credit facilities are non-recourse to Hess Corporation.
At December 31, 2018, this facility was undrawn.9.
8. Asset Retirement Obligations
The following table describes the changes to and maturity ofin our asset retirement obligations:obligations for the years ended December 31:
| | | | | 2021 | | 2020 |
| | 2018 | | | 2017 | | | | | |
| | (In millions) | | | (In millions) |
Balance at January 1 | | $ | 801 | | | $ | 2,128 | | Balance at January 1 | $ | 999 | | | $ | 1,024 | |
Liabilities incurred | | | 68 | | | | 62 | | Liabilities incurred | 229 | | | 36 | |
Liabilities settled or disposed of | | | (46 | ) | | | (1,464 | ) | Liabilities settled or disposed of | (207) | | | (161) | |
Accretion expense | | | 37 | | | | 97 | | Accretion expense | 44 | | | 46 | |
Revisions of estimated liabilities | | | 1 | | | | (54 | ) | Revisions of estimated liabilities | 126 | | | 52 | |
Foreign currency remeasurement | | | (4 | ) | | | 32 | | Foreign currency remeasurement | (1) | | | 2 | |
Balance at December 31 | | $ | 857 | | | $ | 801 | | Balance at December 31 | $ | 1,190 | | | $ | 999 | |
| | | | | | | | | | | | |
Total Asset Retirement Obligations at December 31: | | | | | | | | | Total Asset Retirement Obligations at December 31: | |
Current portion of asset retirement obligations | | $ | 116 | | | $ | 48 | | Current portion of asset retirement obligations | $ | 185 | | | $ | 105 | |
Long-term asset retirement obligations | | | 741 | | | | 753 | | Long-term asset retirement obligations | 1,005 | | | 894 | |
Total at December 31 | | $ | 857 | | | $ | 801 | | Total at December 31 | $ | 1,190 | | | $ | 999 | |
The liabilities incurred in 20182021 on Hess owned properties primarily relate to operations in the U.S. and Guyana while liabilities incurred in 2020 primarily relate to operations in Guyana, the U.S. and Malaysia. In August 2020, Fieldwood and related entities filed for bankruptcy relief under Chapter 11 of the U.S. Bankruptcy Code. Fieldwood’s Bankruptcy Plan, which was approved by the U.S. Bankruptcy Court in June 2021, includes the abandonment of certain assets, including 7 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 6 of the 7 West Delta leases. We expect to receive additional orders covering the remainder of the West Delta decommissioning obligations in the near future and are actively engaged with the BSEE to agree on the scope and timing of decommissioning activities. Our decommissioning obligation derives from our former ownership of the facilities. We are seeking contribution from other parties that owned an interest in the facilities. Liabilities incurred in 2021 include $25$147 million related to acquired participating interests. representing total estimated abandonment obligations in the West Delta Field. Potential recoveries from other parties that previously owned an interest in the West Delta Field have not been recognized as of December 31, 2021.
The liabilities settled or disposed of in 20172021 primarily relate toresult from the sale of our interests in NorwayDenmark and Equatorial Guinea. The fair valueabandonment activity completed in the Gulf of sinkingMexico and the Bakken. Liabilities settled or disposed of in 2020 primarily result from an asset sale in the Gulf of Mexico and abandonment activity completed in the Gulf of Mexico, the Bakken and the U.K. North Sea. Revisions of estimated liabilities in 2021 and 2020 primarily reflect an acceleration of planned abandonment activity in the Gulf of Mexico and changes in service and equipment rates.
Sinking fund deposits that are legally restricted for purposes of settling asset retirement obligations, which are reported in non-current Other assets in the Consolidated Balance Sheet, was $148were $233 million at December 31, 2018 (2017: $1182021 (2020: $207 million).
9. Retirement Plans
10. Retirement Plans
We have funded noncontributory defined benefit pension plans for a significant portion of our employees. In addition, we have an unfunded supplemental pension plan covering certain employees, which provides incremental payments that would have been payable from our principal pension plans, were it not for limitations imposed by income tax regulations. The plans provide defined benefits based on years of service and final average
salary.salary to our U.S. employees hired prior to January 1, 2017 and to our employees in the United Kingdom (U.K.). The U.S. employees hired on or after January 1, 2017 participate under a cash accumulation formula and receive credits to a notional account based on a percentage of pensionable wages. Interest accrues on the balance in the notional account at a rate determined in accordance with plan provisions. Additionally, we maintain an unfunded postretirement medical plan that provides health benefits to certain
U.S. qualified retirees from ages 55 through 65. The measurement date for all retirement plans is December 31.
The following table summarizes the benefit obligations, the fair value of plan assets, and the funded status of our pension and postretirement medical plans:
| | Funded | | | Unfunded | | | Postretirement | |
| | Pension Plans | | | Pension Plan | | | Medical Plan | |
| | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | |
| | (In millions) | |
Change in Benefit Obligation | | | | | | | | | | | | | | | | | | | | | | | | |
Balance at January 1, | | $ | 2,765 | | | $ | 2,560 | | | $ | 249 | | | $ | 256 | | | $ | 87 | | | $ | 84 | |
Service cost | | | 30 | | | | 36 | | | | 12 | | | | 13 | | | | 2 | | | | 4 | |
Interest cost | | | 84 | | | | 93 | | | | 7 | | | | 9 | | | | 3 | | | | 3 | |
Actuarial (gains) loss (a) | | | (237 | ) | | | 138 | | | | (29 | ) | | | 10 | | | | (24 | ) | | | 3 | |
Benefit payments (b) | | | (110 | ) | | | (113 | ) | | | (19 | ) | | | (39 | ) | | | (7 | ) | | | (7 | ) |
Plan curtailments | | | (10 | ) | | | (3 | ) | | | (4 | ) | | | — | | | | (2 | ) | | | — | |
Plan amendments | | | 4 | | | | — | | | | — | | | | — | | | | — | | | | — | |
Foreign currency exchange rate changes | | | (34 | ) | | | 54 | | | | — | | | | — | | | | — | | | | — | |
Balance at December 31, (c) | | | 2,492 | | | | 2,765 | | | | 216 | | | | 249 | | | | 59 | | | | 87 | |
Change in Fair Value of Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | |
Balance at January 1, | | $ | 2,732 | | | $ | 2,284 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Actual return on plan assets | | | (77 | ) | | | 351 | | | | — | | | | — | | | | — | | | | — | |
Employer contributions | | | 59 | | | | 158 | | | | 19 | | | | 39 | | | | 7 | | | | 7 | |
Benefit payments (b) | | | (110 | ) | | | (113 | ) | | | (19 | ) | | | (39 | ) | | | (7 | ) | | | (7 | ) |
Foreign currency exchange rate changes | | | (36 | ) | | | 52 | | | | — | | | | — | | | | — | | | | — | |
Balance at December 31, | | | 2,568 | | | | 2,732 | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Funded Status (Plan assets greater (less) than benefit obligations) at December 31, | | $ | 76 | | | $ | (33 | ) | | $ | (216 | ) | | $ | (249 | ) | | $ | (59 | ) | | $ | (87 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Unrecognized Net Actuarial (Gains) Losses | | $ | 778 | | | $ | 789 | | | $ | 47 | | | $ | 84 | | | $ | (32 | ) | | $ | (10 | ) |
(a)
| The change in discount rate in 2018 resulted in total actuarial gains of approximately $235 million (2017: $170 million of actuarial losses).
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Funded
Pension Plans | | Unfunded
Pension Plan | | Postretirement
Medical Plan |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | | | | | |
| | (In millions) |
| Change in Benefit Obligation | | | | | | | | | | | |
| Balance at January 1, | $ | 3,085 | | | $ | 2,667 | | | $ | 269 | | | $ | 242 | | | $ | 65 | | | $ | 75 | |
| Service cost | 41 | | | 37 | | | 10 | | | 13 | | | 3 | | | 3 | |
| Interest cost | 52 | | | 68 | | | 3 | | | 5 | | | 1 | | | 1 | |
| Actuarial (gains) loss (a) | (126) | | | 385 | | | (8) | | | 26 | | | (3) | | | (8) | |
| Benefit payments (b) | (100) | | | (93) | | | (26) | | | (17) | | | (7) | | | (6) | |
| | | | | | | | | | | |
| Plan amendments | 2 | | | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | |
| Foreign currency exchange rate changes | (6) | | | 21 | | | — | | | — | | | — | | | — | |
| Balance at December 31, (c) | 2,948 | | | 3,085 | | | 248 | | | 269 | | | 59 | | | 65 | |
| Change in Fair Value of Plan Assets | | | | | | | | | | | |
| Balance at January 1, | $ | 3,043 | | | $ | 2,732 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Actual return on plan assets | 417 | | | 378 | | | — | | | — | | | — | | | — | |
| Employer contributions | 6 | | | 4 | | | 26 | | | 17 | | | 7 | | | 6 | |
| Benefit payments (b) | (100) | | | (93) | | | (26) | | | (17) | | | (7) | | | (6) | |
| Foreign currency exchange rate changes | (9) | | | 22 | | | — | | | — | | | — | | | — | |
| Balance at December 31, | 3,357 | | | 3,043 | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | |
| Funded Status (Plan assets greater (less) than benefit obligations) at December 31, | $ | 409 | | | $ | (42) | | | $ | (248) | | | $ | (269) | | | $ | (59) | | | $ | (65) | |
| | | | | | | | | | | |
| Unrecognized Net Actuarial (Gains) Losses | $ | 501 | | | $ | 900 | | | $ | 66 | | | $ | 86 | | | $ | (21) | | | $ | (19) | |
(b)
| Benefit payments include lump-sum settlement payments of approximately $32 million in 2018 (2017: $57 million).
|
(a)Changes in discount rates resulted in actuarial gains of $178 million in 2021 (2020: $387 million of actuarial losses). Changes in the inflation assumptions for our U.K. pension plan resulted in actuarial losses of $36 million in 2021 (2020: $24 million of actuarial losses). Changes in mortality assumptions resulted in actuarial losses of $7 million in 2021 (2020: $18 million of actuarial gains). Changes in all other assumptions, including demographic assumptions, resulted in actuarial gains of $2 million in 2021 (2020: $10 million of actuarial losses).(c)
| At December 31, 2018, the accumulated benefit obligation for the funded and unfunded defined benefit pension plans was $2,424 million and $171 million, respectively (2017: $2,679 million and $190 million, respectively).
|
(b)Benefit payments include lump-sum settlement payments of $34 million in 2021 (2020: $23 million).(c)At December 31, 2021, the accumulated benefit obligation for the funded and unfunded defined benefit pension plans was $2,856 million and $208 million, respectively (2020: $2,993 million and $228 million, respectively).
Amounts recognized in the Consolidated Balance Sheetat December 31 consisted of the following: | | Funded | | | Unfunded | | | Postretirement | |
| | Pension Plans | | | Pension Plan | | | Medical Plan | |
| | 2018 | | | 2017 | | | 2018 | | | 2017 | | | 2018 | | | 2017 | |
| | (In millions) | |
Noncurrent assets | | $ | 76 | | | $ | 22 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Current liabilities | | | — | | | | — | | | | (30 | ) | | | (18 | ) | | | (9 | ) | | | (11 | ) |
Noncurrent liabilities | | | — | | | | (55 | ) | | | (186 | ) | | | (231 | ) | | | (50 | ) | | | (76 | ) |
Pension assets / (accrued benefit liability) | | $ | 76 | | | $ | (33 | ) | | $ | (216 | ) | | $ | (249 | ) | | $ | (59 | ) | | $ | (87 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Accumulated other comprehensive loss, pre-tax (a) | | $ | 778 | | | $ | 789 | | | $ | 47 | | | $ | 84 | | | $ | (32 | ) | | $ | (10 | ) |
(a)
| The after‑tax deficit reflected in Accumulated other comprehensive income (loss) was $581 million at December 31, 2018 (2017: $548 million deficit).
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Funded
Pension Plans | | Unfunded
Pension Plan | | Postretirement
Medical Plan |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | | | | | |
| | (In millions) |
| Noncurrent assets | $ | 409 | | | $ | 45 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Current liabilities | — | | | — | | | (34) | | | (49) | | | (6) | | | (7) | |
| Noncurrent liabilities | — | | | (87) | | | (214) | | | (220) | | | (53) | | | (58) | |
| Pension assets / (accrued benefit liability) | $ | 409 | | | $ | (42) | | | $ | (248) | | | $ | (269) | | | $ | (59) | | | $ | (65) | |
| | | | | | | | | | | |
| Accumulated other comprehensive (income) loss, pre-tax (a) | $ | 501 | | | $ | 900 | | | $ | 66 | | | $ | 86 | | | $ | (21) | | | $ | (19) | |
(a)The after‑tax deficit reflected in Accumulated other comprehensive income (loss) was $338 million at December 31, 2021 (2020: $759 million deficit).
The net periodic benefit cost for funded and unfunded pension plans, and the postretirement medical plan, is as follows:
| | Pension Plans | | | Postretirement Medical Plan | |
| | 2018 | | | 2017 | | | 2016 | | | 2018 | | | 2017 | | | 2016 | |
| | (In millions) | |
Service cost | | $ | 42 | | | $ | 49 | | | $ | 60 | | | $ | 2 | | | $ | 4 | | | $ | 4 | |
Interest cost | | | 91 | | | | 102 | | | | 107 | | | | 3 | | | | 3 | | | | 3 | |
Expected return on plan assets | | | (194 | ) | | | (168 | ) | | | (166 | ) | | | — | | | | — | | | | — | |
Amortization of unrecognized net actuarial losses (gains) | | | 39 | | | | 58 | | | | 60 | | | | (2 | ) | | | — | | | | — | |
Settlement loss | | | 4 | | | | 19 | | | | — | | | | — | | | | — | | | | — | |
Curtailment gain | | | — | | | | — | | | | — | | | | (2 | ) | | | — | | | | — | |
Special termination benefit recognized | | | — | | | | — | | | | 1 | | | | — | | | | — | | | | — | |
Net Periodic Benefit Cost (a) | | $ | (18 | ) | | $ | 60 | | | $ | 62 | | | $ | 1 | | | $ | 7 | | | $ | 7 | |
(a)
| Net non-service pension costs are | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Pension Plans | | Postretirement Medical Plan | | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | | | | | | | | | | | | | | | (In millions) | | Service cost | $ | 51 | | | $ | 50 | | | $ | 44 | | | $ | 3 | | | $ | 3 | | | $ | 2 | | | Interest cost | 55 | | | 73 | | | 89 | | | 1 | | | 1 | | | 2 | | | Expected return on plan assets | (197) | | | (180) | | | (180) | | | — | | | — | | | — | | | Amortization of unrecognized net actuarial losses (gains) | 58 | | | 48 | | | 52 | | | (1) | | | (1) | | | (1) | | | Settlement loss | 9 | | | — | | | 93 | | | — | | | — | | | — | | | Curtailment gain | — | | | — | | | — | | | — | | | — | | | — | | | | | | | | | | | | | | | Net Periodic Benefit Cost / (Income) (a) | $ | (24) | | | $ | (9) | | | $ | 98 | | | $ | 3 | | | $ | 3 | | | $ | 3 | |
(a)Net non-service cost, which is included in Other, net in the Statement of Consolidated Income. In 2018, net non-service pension costs amounted to income of $61 million (2017: $14 million of expense; 2016: $5 million of expense). |
In 2018, we recorded curtailment gains of $14 million to Accumulated other comprehensive Income (loss) and $2 million to the Statement of Consolidated Income, following workforce reductions. In connection with this curtailment, as required under accounting standards, we remeasured our U.S. retirement plans and recorded a total decrease was income of $125$75 million in 2021 (2020: $59 million of income; 2019: $55 million of expense).
In 2019, the Corporation’s U.S. post retirement liabilities. This reduction was primarily driven bytrust for the Hess Corporation Employees’ Pension Plan (the “Plan”) purchased a changesingle premium annuity contract at a cost of $249 million using assets of the Plan to settle and transfer certain of its obligations to a third party. The settlement transaction resulted in weighted average discount rates useda noncash charge of $88 million to measurerecognize unamortized pension actuarial losses that is included in Other, net in the liabilities. There was no change to the weighted average expected long-term rateStatement of return on plan assets.For the full year 2019,Consolidated Income
. In 2022, we forecast
pension service
costscost for our pension and postretirement medical plans to be approximately
$40$50 million and net non-service
pension costscost of approximately
$40$135 million of income, which is comprised of interest cost of approximately
$95$65 million, amortization of unrecognized net actuarial losses of approximately
$45$15 million, and estimated expected return on plan assets of approximately
$180$215 million.
Assumptions:The weighted average actuarial assumptions used to determine Benefitbenefit obligations at December 31 and Netnet periodic benefit cost for the three years ended December 31 for our funded and unfunded pension plans were as follows:
| | | 2018 | | | 2017 | | | 2016 | | | | 2021 | | 2020 | | 2019 |
Benefit Obligations: | | | | | | | | | | | | | Benefit Obligations: | | | | | | |
Discount rate | | | 3.9 | % | | | 3.3 | % | | | 3.7 | % | Discount rate | | 2.5% | | 2.2% | | 2.9% |
Rate of compensation increase | | | 3.8 | % | | | 4.5 | % | | | 4.6 | % | Rate of compensation increase | | 3.8% | | 3.8% | | 3.8% |
| Net Periodic Benefit Cost: | | | | | | | | | | | | | Net Periodic Benefit Cost: | |
Discount rate | | | | | | | | | | | | | Discount rate | |
Service cost | | | 3.9 | % | | | 3.7 | % | | | 4.1 | % | Service cost | | 2.6% | | 3.2% | | 3.9% |
Interest cost | | | 3.3 | % | | | 3.7 | % | | | 4.1 | % | Interest cost | | 1.7% | | 2.6% | | 3.4% |
Expected return on plan assets | | | 7.2 | % | | | 7.3 | % | | | 7.4 | % | Expected return on plan assets | | 6.6% | | 6.7% | | 7.1% |
Rate of compensation increase | | | 4.5 | % | | | 4.6 | % | | | 4.5 | % | Rate of compensation increase | | 3.8% | | 3.8% | | 3.8% |
The actuarial assumptions used to determine Benefitbenefit obligations at December 31 for the postretirement medical plan were as follows:
| | | 2018 | | | 2017 | | | 2016 | | | | 2021 | | 2020 | | 2019 |
Discount rate | | | 3.9 | % | | | 3.2 | % | | | 3.5 | % | Discount rate | | 2.4% | | 1.9% | | 2.8% |
Initial health care trend rate | | | 6.9 | % | | | 7.3 | % | | | 7.7 | % | Initial health care trend rate | | 5.5% | | 6.0% | | 6.5% |
Ultimate trend rate | | | 4.5 | % | | | 4.5 | % | | | 4.5 | % | Ultimate trend rate | | 4.0% | | 4.5% | | 4.5% |
Year in which ultimate trend rate is reached | | | 2038 | | | | 2038 | | | | 2038 | | Year in which ultimate trend rate is reached | | 2046 | | 2038 | | 2038 |
The assumptions used to determine net periodic benefit cost for each year were established at the end of each previous year while the assumptions used to determine benefit obligations were established at each year‑end. The net periodic benefit cost and the actuarial present value of benefit obligations are based on actuarial assumptions that are reviewed on an annual basis. The discount rate is developed based on a portfolio of high‑quality, fixed income debt instruments with maturities that approximate the expected payment of plan obligations.
Beginning in 2018, we have elected to use a split discount rate approach for all of our retirement plans. This involves the continued use of a single weighted-average discount rate in the calculation of the projected benefit obligation, and separate discount rates for each projected benefit payment in the calculation of service cost and interest cost. In contrast, historically, a single weighted-average discount rate was used in both the calculation of the projected benefit obligation, and service cost and interest cost.
The overall expected return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of pension assets to that asset category.
The future expected return assumptions for individual asset categories are largely based on inputs from various investment experts regarding their future return expectations for particular
asset categories.
Our investment strategy is to maximize long‑term returns at an acceptable level of risk through broad diversification of plan assets in a variety of asset classes. Asset classes and target allocations are determined by our investment committee and include domestic and foreign equities, fixed income, and other investments, including hedge funds, real estate and private equity. Investment managers are prohibited from investing in securities issued by us unless indirectly held as part of an index strategy. The majority of plan assets
are highly liquid, providing ample liquidity for benefit payment requirements. The current target allocations for plan assets are
50%45% equity securities,
30%35% fixed income securities (including cash and short‑term investment funds) and 20% to all other types of investments. Asset allocations are rebalanced on a periodic basis throughout the year to bring assets to within an acceptable
range of target levels.Fair value:The following tables provide the fair value of the financial assets of the funded pension plans at December 31, 20182021 and 20172020 in accordance with the fair value measurement hierarchy described inNote 1, Nature of Operations, Basis of Presentation and Summary of Accounting Policies. | | Level 1 | | | Level 2 | | | Level 3 | | | Net Asset Value (d) | | | Total | |
| | (In millions) | |
December 31, 2018 | | | | | | | | | | | | | | | | | | | | |
Cash and Short-Term Investment Funds | | $ | 3 | | | $ | 47 | | | $ | — | | | $ | — | | | $ | 50 | |
Equities: | | | | | | | | | | | | | | | | | | | | |
U.S. equities (domestic) | | | 654 | | | | — | | | | — | | | | — | | | | 654 | |
International equities (non-U.S.) | | | 92 | | | | 29 | | | | — | | | | 288 | | | | 409 | |
Global equities (domestic and non-U.S.) | | | 2 | | | | 203 | | | | — | | | | — | | | | 205 | |
Fixed Income: | | | | | | | | | | | | | | | | | | | | |
Treasury and government issued (a) | | | — | | | | 240 | | | | — | | | | — | | | | 240 | |
Government related (b) | | | — | | | | 37 | | | | — | | | | — | | | | 37 | |
Mortgage-backed securities (c) | | | — | | | | 159 | | | | — | | | | 27 | | | | 186 | |
Corporate | | | — | | | | 272 | | | | — | | | | 31 | | | | 303 | |
Other: | | | | | | | | | | | | | | | | | | | | |
Hedge funds | | | — | | | | — | | | | — | | | | 135 | | | | 135 | |
Private equity funds | | | — | | | | — | | | | — | | | | 170 | | | | 170 | |
Real estate funds | | | 49 | | | | — | | | | 61 | | | | 50 | | | | 160 | |
Diversified commodities funds | | | — | | | | 19 | | | | — | | | | — | | | | 19 | |
Total investments | | $ | 800 | | | $ | 1,006 | | | $ | 61 | | | $ | 701 | | | $ | 2,568 | |
| | | | | | | | | | | | | | | | | | | | |
December 31, 2017 | | | | | | | | | | | | | | | | | | | | |
Cash and Short-Term Investment Funds | | $ | 32 | | | $ | 69 | | | $ | — | | | $ | — | | | $ | 101 | |
Equities: | | | | | | | | | | | | | | | | | | | | |
U.S. equities (domestic) | | | 789 | | | | — | | | | — | | | | — | | | | 789 | |
International equities (non-U.S.) | | | 104 | | | | 34 | | | | — | | | | 296 | | | | 434 | |
Global equities (domestic and non-U.S.) | | | 2 | | | | 238 | | | | — | | | | — | | | | 240 | |
Fixed Income: | | | | | | | | | | | | | | | | | | | | |
Treasury and government issued (a) | | | — | | | | 271 | | | | — | | | | — | | | | 271 | |
Government related (b) | | | — | | | | 34 | | | | 1 | | | | — | | | | 35 | |
Mortgage-backed securities (c) | | | — | | | | 139 | | | | 1 | | | | 26 | | | | 166 | |
Corporate | | | — | | | | 182 | | | | — | | | | 6 | | | | 188 | |
Other: | | | | | | | | | | | | | | | | | | | | |
Hedge funds | | | — | | | | — | | | | — | | | | 187 | | | | 187 | |
Private equity funds | | | — | | | | — | | | | — | | | | 140 | | | | 140 | |
Real estate funds | | | 63 | | | | — | | | | 2 | | | | 92 | | | | 157 | |
Diversified commodities funds | | | — | | | | 24 | | | | — | | | | — | | | | 24 | |
Total investments | | $ | 990 | | | $ | 991 | | | $ | 4 | | | $ | 747 | | | $ | 2,732 | |
(a)
| Includes securities issued and guaranteed by U.S. and non‑U.S. governments.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Net Asset
Value (c) | | Total |
| | | | | | | | | |
| | (In millions) |
| December 31, 2021 | | | | | | | | | |
| Cash and Short-Term Investment Funds | $ | 19 | | | $ | — | | | $ | — | | | $ | — | | | $ | 19 | |
| Equities: | | | | | | | | | |
| U.S. equities (domestic) | 601 | | | — | | | — | | | 87 | | | 688 | |
| International equities (non-U.S.) | 73 | | | 56 | | | — | | | 375 | | | 504 | |
| Global equities (domestic and non-U.S.) | — | | | 7 | | | — | | | 224 | | | 231 | |
| Fixed Income: | | | | | | | | | |
| Treasury and government related (a) | — | | | 361 | | | — | | | 41 | | | 402 | |
| Mortgage-backed securities (b) | — | | | 128 | | | — | | | 63 | | | 191 | |
| Corporate | 128 | | | 452 | | | — | | | 55 | | | 635 | |
| Other: | | | | | | | | | |
| Hedge funds | — | | | — | | | — | | | 81 | | | 81 | |
| Private equity funds | — | | | — | | | — | | | 382 | | | 382 | |
| Real estate funds | 29 | | | — | | | — | | | 195 | | | 224 | |
| Total investments | $ | 850 | | | $ | 1,004 | | | $ | — | | | $ | 1,503 | | | $ | 3,357 | |
| December 31, 2020 | | | | | | | | | |
| Cash and Short-Term Investment Funds | $ | 44 | | | $ | — | | | $ | — | | | $ | — | | | $ | 44 | |
| Equities: | | | | | | | | | |
| U.S. equities (domestic) | 585 | | | — | | | — | | | 164 | | | 749 | |
| International equities (non-U.S.) | 94 | | | 43 | | | — | | | 352 | | | 489 | |
| Global equities (domestic and non-U.S.) | — | | | 8 | | | — | | | 217 | | | 225 | |
| Fixed Income: | | | | | | | | | |
| Treasury and government related (a) | — | | | 350 | | | — | | | 49 | | | 399 | |
| Mortgage-backed securities (b) | — | | | 116 | | | — | | | 70 | | | 186 | |
| Corporate | — | | | 381 | | | — | | | 62 | | | 443 | |
| Other: | | | | | | | | | |
| Hedge funds | — | | | — | | | — | | | 73 | | | 73 | |
| Private equity funds | — | | | — | | | — | | | 251 | | | 251 | |
| Real estate funds | 23 | | | — | | | — | | | 161 | | | 184 | |
| Total investments | $ | 746 | | | $ | 898 | | | $ | — | | | $ | 1,399 | | | $ | 3,043 | |
(b)
| Primarily consists of securities issued by governmental agencies and municipalities.
|
(a)Includes securities issued and guaranteed by U.S. and non‑U.S. governments, and securities issued by governmental agencies and municipalities.(c)
| Comprised of U.S. residential and commercial mortgage-backed securities.
|
(b)Comprised of U.S. residential and commercial mortgage-backed securities.(d)
| Includes certain investments that have been valued using the net asset value practical expedient, and therefore have not been categorized in the fair value hierarchy. The inclusion of such amounts in the above table is intended to aid reconciliation of investments categorized in the fair value hierarchy to total pension plan assets.
|
(c)Includes certain investments that have been valued using the net asset value (NAV) practical expedient, and therefore have not been categorized in the fair value hierarchy. The inclusion of such amounts in the above table is intended to aid reconciliation of investments categorized in the fair value hierarchy to total pension plan assets. 67
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following describes the financial assets of the funded pension plans:
Cash and short‑term investment funds -Consists of cash on hand and short-term investment funds that provide for daily investments and redemptions. Cash on hand is classified as Level 1 and short‑term investment fundsredemptions which are classified as Level 2.1.
Equities -Consists of individually held or commingledU.S. and international equity securities. This investment category also includes funds that consist primarily of U.S. and Internationalinternational equity securities. Equity securities, which are individually held and are traded actively on exchanges, are classified as Level 1. Certain funds, consisting primarily of equity securities, are classified as Level 2 if the NAV is determined and published daily, and is the basis for current transactions. Commingled funds, consisting primarily of equity securities, are valued using the net asset value (NAV)NAV per fund share derived from quoted prices in active markets of the underlying securities. These funds are classified as Level 2 where they have readily determinable fair values, otherwise they are classified under the NAV practical expedient.share.
Fixed income investments -Consists of individually held securities issued by the U.S. government, non‑U.S.non-U.S. governments, governmental agencies, municipalities and corporations, and agency and non-agency mortgage‑backedmortgage-backed securities. This investment category also includes commingled investment funds that invest inconsist of fixed income securities. Individual fixed income securities are generally priced based on
evaluated prices from independent pricing services, which are monitored and provided by the third-party custodial firm responsible for safekeeping
assets of the particular plan
assets. Individualand are classified as Level 2. Exchange-traded funds consisting of fixed income securities are classified as Level
2.1. Certain
funds, consisting primarily of fixed income
investments are commingled funds that are valued at the NAV per fund share derived indirectly from observable inputs or from quoted prices in less liquid markets of the underlying securities. These fundssecurities, are classified as Level 2
where they have readily determinable fair values, otherwise they are classified underif the NAV
practical expedient.is determined and published daily, and is the basis for current transactions. Commingled funds, consisting primarily of fixed income securities, are valued using the NAV per fund share.
Other investments-Consists of exchange‑traded real estate investment trust securities, which are classified as Level 1. Commingled funds and limited partnership investments in hedge funds, private equity and real estate funds are valued at the NAV per fund share derived using information provided by fund managers which include various inputs such as discounted future cash flows, market based comparable data and independent appraisals from third parties. These funds are classified as Level 2 or 3 where they have readily determinable fair values, otherwise they are classified under the NAV practical expedient.The following tables provide changes in financial assets that are measured at fair value based on Level 3 inputs that are held by institutional funds classified as:
share. | | Fixed | | | Real Estate | | | | | |
| | Income | | | Funds | | | Total | |
| | (In millions) | |
Balance at January 1, 2017 | | $ | 2 | | | $ | 8 | | | $ | 10 | |
Actual return on plan assets | | | — | | | | — | | | | — | |
Purchases, sales or other settlements | | | 1 | | | | (6 | ) | | | (5 | ) |
Net transfers in (out) of Level 3 | | | (1 | ) | | | — | | | | (1 | ) |
Balance at December 31, 2017 | | | 2 | | | | 2 | | | | 4 | |
Actual return on plan assets | | | — | | | | 1 | | | | 1 | |
Purchases, sales or other settlements | | | (2 | ) | | | 58 | | | | 56 | |
Net transfers in (out) of Level 3 | | | — | | | | — | | | | — | |
Balance at December 31, 2018 | | $ | — | | | $ | 61 | | | $ | 61 | |
Contributions and estimated future benefit payments:
We In 2022, we expect to contribute approximately $40$45 million to our funded pension plans in 2019.
plans.
Estimated future benefit payments by the funded and unfunded pension plans, and the postretirement medical plan, which reflect expected future service, are as follows (in millions):
2019 | | $ | 142 | |
2020 | | | 139 | |
2021 | | | 135 | |
2022 | | | 139 | |
2023 | | | 140 | |
Years 2024 to 2028 | | | 722 | |
| | | | | | | | |
| 2022 | | $ | 131 | |
| 2023 | | 132 | |
| 2024 | | 137 | |
| 2025 | | 125 | |
| 2026 | | 131 | |
| Years 2027 to 2031 | | 662 | |
We also have
several defined contribution plans for certain eligible employees. Employees may contribute a portion of their compensation to these plans and we match a portion of the employee contributions. We recorded expense of
$19$18 million in
20182021 for contributions to these plans
(2017:(2020: $22 million;
2016: $252019: $20 million).
68
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
10. Revenue
Revenue from contracts with customers on a disaggregated basis was as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exploration and Production | | Midstream | | Eliminations | | Total |
| | United States | | Guyana | | Malaysia and JDA | | Other (a) | | E&P Total | | | | | | |
| 2021 | | | | | | | | | | | | | | | |
| Sales of our net production volumes: | | | | | | | | | | | | | | | |
| Crude oil revenue | $ | 2,958 | | | $ | 765 | | | $ | 83 | | | $ | 519 | | | $ | 4,325 | | | $ | — | | | $ | — | | | $ | 4,325 | |
| Natural gas liquids revenue | 594 | | | — | | | — | | | — | | | 594 | | | — | | | — | | | 594 | |
| Natural gas revenue | 350 | | | — | | | 655 | | | 10 | | | 1,015 | | | — | | | — | | | 1,015 | |
| Sales of purchased oil and gas | 1,638 | | | 16 | | | — | | | 95 | | | 1,749 | | | — | | | — | | | 1,749 | |
| Intercompany revenue | — | | | — | | | — | | | — | | | — | | | 1,204 | | | (1,204) | | | — | |
| Total revenues from contracts with customers | 5,540 | | | 781 | | | 738 | | | 624 | | | 7,683 | | | 1,204 | | | (1,204) | | | 7,683 | |
| Other operating revenues (b) | (162) | | | (27) | | | — | | | (21) | | | (210) | | | — | | | — | | | (210) | |
| Total sales and other operating revenues | $ | 5,378 | | | $ | 754 | | | $ | 738 | | | $ | 603 | | | $ | 7,473 | | | $ | 1,204 | | | $ | (1,204) | | | $ | 7,473 | |
| 2020 | |
| Sales of our net production volumes: | | | | | | | | | | | | | | | |
| Crude oil revenue | $ | 1,898 | | | $ | 278 | | | $ | 34 | | | $ | 153 | | | $ | 2,363 | | | $ | — | | | $ | — | | | $ | 2,363 | |
| Natural gas liquids revenue | 253 | | | — | | | — | | | — | | | 253 | | | — | | | — | | | 253 | |
| Natural gas revenue | 144 | | | — | | | 477 | | | 10 | | | 631 | | | — | | | — | | | 631 | |
| Sales of purchased oil and gas | 831 | | | 5 | | | — | | | 11 | | | 847 | | | — | | | — | | | 847 | |
| Intercompany revenue | — | | | — | | | — | | | — | | | — | | | 1,092 | | | (1,092) | | | — | |
| Total revenues from contracts with customers | 3,126 | | | 283 | | | 511 | | | 174 | | | 4,094 | | | 1,092 | | | (1,092) | | | 4,094 | |
| Other operating revenues (b) | 478 | | | 67 | | | — | | | 28 | | | 573 | | | — | | | — | | | 573 | |
| Total sales and other operating revenues | $ | 3,604 | | | $ | 350 | | | $ | 511 | | | $ | 202 | | | $ | 4,667 | | | $ | 1,092 | | | $ | (1,092) | | | $ | 4,667 | |
| 2019 | |
| Sales of our net production volumes: | | | | | | | | | | | | | | | |
| Crude oil revenue | $ | 2,981 | | | $ | — | | | $ | 113 | | | $ | 566 | | | $ | 3,660 | | | $ | — | | | $ | — | | | $ | 3,660 | |
| Natural gas liquids revenue | 229 | | | — | | | — | | | — | | | 229 | | | — | | | — | | | 229 | |
| Natural gas revenue | 150 | | | — | | | 646 | | | 33 | | | 829 | | | — | | | — | | | 829 | |
| Sales of purchased oil and gas | 1,644 | | | — | | | 3 | | | 91 | | | 1,738 | | | — | | | — | | | 1,738 | |
| Intercompany revenue | — | | | — | | | — | | | — | | | — | | | 848 | | | (848) | | | — | |
| Total revenues from contracts with customers | 5,004 | | | — | | | 762 | | | 690 | | | 6,456 | | | 848 | | | (848) | | | 6,456 | |
| Other operating revenues (b) | 39 | | | — | | | — | | | — | | | 39 | | | — | | | — | | | 39 | |
| Total sales and other operating revenues | $ | 5,043 | | | $ | — | | | $ | 762 | | | $ | 690 | | | $ | 6,495 | | | $ | 848 | | | $ | (848) | | | $ | 6,495 | |
(a)Other includes our interests in Denmark, which were sold in August 2021, and Libya.
(b)Includes gains (losses) on commodity derivatives of $(243) million in 2021, $547 million in 2020, and $1 million in 2019.
At December 31, 2021, contract liabilities of $24 million (2020: NaN) resulted from a take-or-pay deficiency payment received in 2021 that is subject to a make-up period expiring in December 2023. At December 31, 2021 and 2020, there were no contract assets.
11. Dispositions
2021: We completed the sale of our interests in Denmark for net cash consideration of approximately $130 million, after normal closing adjustments, and recognized a pre-tax gain of $29 million ($29 million after income taxes). In addition, we completed the sale of our Little Knife and Murphy Creek nonstrategic acreage interests in the Bakken for net cash consideration of $297 million, after normal closing adjustments. The sale included approximately 78,700 net acres, which are located in the southernmost portion of the Corporation's Bakken position. The acreage constituted part of a larger amortization base and the sale was treated as a normal retirement. Accordingly, no gain or loss was recognized upon sale.
2020: We completed the sale of our 28% working interest in the Shenzi Field in the deepwater Gulf of Mexico for proceeds of $482 million,after normal closing adjustments, and recognizeda pre-tax gain of $79 million ($79 million after income taxes).
2019: We completed the sale of our remaining acreage in the Utica shale play in eastern Ohio for proceeds of $22 million,after normal closing adjustments, and recognizeda pre-tax gain of $22 million ($22 million after income taxes).
12. Impairment and Other
Oil and Gas Properties:
In June 2021, the U.S. Bankruptcy Court approved the bankruptcy plan for Fieldwood which includes transferring abandonment obligations of Fieldwood to predecessors in title of certain of its assets, including Hess, who are jointly and severally liable for the obligations. As a result, we recognized a charge of $147 million ($147 million after income taxes) in connection with total estimated abandonment obligations for 7 leases in the West Delta Field in the Gulf of Mexico, which we sold to a Fieldwood predecessor in 2004. See Note 8, Asset Retirement Obligations.
As a result of the significant decline in crude oil prices due to the global economic slowdown from COVID-19, we reviewed our oil and gas properties within the Exploration and Production operating segment for impairment in the first quarter of 2020. We recognized pre-tax impairment charges in the first quarter of 2020 to reduce the carrying value of our oil and gas properties and certain related right-of-use assets at the North Malay Basin in Malaysia by $755 million ($755 million after income taxes), the South Arne Field in Denmark by $670 million ($594 million after income taxes), and in the Gulf of Mexico, the Stampede Field by $410 million ($410 million after income taxes) and the Tubular Bells Field by $270 million ($270 million after income taxes) primarily as a result of a lower long-term crude oil price outlook. The impairment charges were based on estimates of fair value at March 31, 2020 determined by discounting internally developed future net cash flows, a Level 3 fair value measurement. The total of the fair value estimates was approximately $1.05 billion. Significant inputs used in determining the discounted future net cash flows include future prices, projected production volumes using risk adjusted oil and gas reserves, and discount rates. The future pricing assumptions used were based on forward strip crude oil prices as of March 31, 2020 for the remainder of 2020 through 2022, and $50 per barrel for WTI ($55 per barrel for Brent) in 2023 and thereafter to the end of field life. The weighted average crude oil benchmark price based on total projected crude oil volumes for the impaired assets was $48.82 per barrel. A discount rate of 10% was used in each of the fair value measurements which represents the estimated discount rate a market participant would use. We determined the discount rate by considering the weighted average cost of capital for a group of peer companies.
Other Assets:
In the first quarter of 2020, we recognized impairment charges totaling $21 million pre-tax ($20 million after income taxes) related to drilling rig right-of-use assets in the Bakken and surplus materials and supplies.
13. Severance Costs
We incurred employee termination costs of $27 million in 2020 related to cost reduction initiatives. All charges were based on amounts incurred under ongoing severance arrangements or other statutory requirements, plus amounts earned under enhanced benefit arrangements. Payments for termination costs were $7 million in 2021 (2020: $20 million; 2019: $4 million).
14. Share-based Compensation
We have established and maintain a Long-term Incentive Planlong term incentive plans (LTIP), as amended, for the granting of restricted common shares, (Restricted stock), performance share units (PSUs) and stock options to our employees. At December 31, 2018,2021, the total number of authorized common stock under the LTIP as amended, was 51.563.5 million shares, of which we have 19.023.6 million shares available for issuance. Share‑Share‑based compensation expense consisted of the following:
| | | | | 2021 | | 2020 | | 2019 |
| | 2018 | | | 2017 | | | 2016 | | | | | | | |
| | (In millions) | | | (In millions) |
Restricted stock | | $ | 40 | | | $ | 56 | | | $ | 45 | | Restricted stock | $ | 49 | | | $ | 51 | | | $ | 53 | |
| Performance share units | | Performance share units | 18 | | | 18 | | | 22 | |
Stock options | | | 10 | | | | 9 | | | | 7 | | Stock options | 10 | | | 10 | | | 10 | |
Performance share units | | | 22 | | | | 21 | | | | 21 | | |
Share-based compensation expense before income taxes | | $ | 72 | | | $ | 86 | | | $ | 73 | | Share-based compensation expense before income taxes | $ | 77 | | | $ | 79 | | | $ | 85 | |
Income tax benefit on share-based compensation expense | | $ | — | | | $ | 1 | | | $ | 28 | | Income tax benefit on share-based compensation expense | $ | — | | | $ | — | | | $ | — | |
Based on share‑based compensation awards outstanding at December 31,
2018,2021, unearned compensation expense, before income taxes,
willof $79 million is expected to be recognized
in future years as follows (in millions): 2019: $57, 2020: $30 and 2021: $6.over a weighted average period of 1.8 years.
Our share-based compensation plans can be summarized as follows:
Restricted stock generally vests equally on an annual basis over a three-year term and
areis valued based on the prevailing market price of our common stock on the date of grant.
The following is a summary of restricted stock award activity in 2018: | | Shares of Restricted Common Stock | | | Weighted - Average Price on Date of Grant | |
| (In thousands, except per share amounts) | |
Outstanding at January 1, 2018 | | | 3,202 | | | $ | 54.04 | |
Granted | | | 1,258 | | | | 50.78 | |
Vested (a) | | | (1,099 | ) | | | 65.80 | |
Forfeited | | | (480 | ) | | | 50.63 | |
Outstanding at December 31, 2018 | | | 2,881 | | | $ | 48.70 | |
| (a)
| In 2018, restricted stock with fair values of $54 million were vested (2017: $37 million; 2016: $41 million).
|
| | | | | | | | | | | |
| | Shares of Restricted Common Stock | | Weighted - Average Price on Date of Grant |
| | | |
| | (In thousands, except per share amounts) |
| Outstanding at January 1, 2021 | 1,917 | | | $ | 51.94 | |
| Granted | 781 | | | 75.11 | |
| Vested (a) | (980) | | | 52.72 | |
| Forfeited | (102) | | | 57.16 | |
| Outstanding at December 31, 2021 | 1,616 | | | $ | 62.33 | |
PSUs:
(a)In 2021, restricted stock with a vesting date fair value of $72 million were vested (2020: $51 million; 2019: $102 million).
Performance share units:
PSUs generally vest three years from the date of grant and are valued
based on the prevailing market price of our common stockusing a Monte Carlo simulation on the date of grant. The number of shares of common stock to be issued under a PSU agreement is based on a comparison of the Corporation’s total shareholder return (TSR) to the TSR of a predetermined group of peer companies over a
three‑yearthree-year performance period ending December 31 of the year prior to settlement of the grant.
Beginning with the PSUs granted in 2020, the Corporation's TSR is compared to the TSR of a predetermined group of peer companies and the S&P 500 index over the three-year performance period. Payouts of the performance share awards will range from 0% to 200% of the target awards based on the Corporation’s TSR ranking within the peer group. Dividend equivalents for the performance period will accrue on performance shares but will only be paid out on earned shares after the performance period.
The following is a summary of PSU activity in 2018: | | Performance Share Units | | | Weighted - Average Fair Value on Date of Grant | |
| | (In thousands, except per share amounts) | |
Outstanding at January 1, 2018 | | | 1,146 | | | $ | 58.78 | |
Granted | | | 278 | | | | 59.65 | |
Vested (a) | | | (313 | ) | | | 76.64 | |
Forfeited | | | (48 | ) | | | 53.62 | |
Outstanding at December 31, 2018 | | | 1,063 | | | $ | 53.98 | |
| (a)
| In 2018, PSU’s with fair value of $9 million were vested (2017: $10 million; 2016: $15 million).
|
| | | | | | | | | | | |
| | Performance Share Units | | Weighted - Average Fair Value on Date of Grant |
| | | |
| | (In thousands, except per share amounts) |
| Outstanding at January 1, 2021 | 806 | | | $ | 62.36 | |
| Granted | 205 | | | 86.70 | |
| Vested (a) | (274) | | | 59.65 | |
| Forfeited | (4) | | | 62.66 | |
| Outstanding at December 31, 2021 | 733 | | | $ | 70.17 | |
(a)In 2021, PSU’s with a vesting date fair value of $30 million were vested (2020: $48 million; 2019: $16 million).
The following weighted average assumptions were utilized to estimate the fair value of PSU awards:
| | | 2018 | | | 2017 | | | 2016 | | | 2021 | | 2020 | | 2019 |
Risk free interest rate | | | 2.39 | % | | | 1.55 | % | | | 0.96 | % | Risk free interest rate | 0.29 | % | | 0.52 | % | | 2.48 | % |
Stock price volatility | | | 0.400 | | | | 0.387 | | | | 0.329 | | Stock price volatility | 0.579 | | 0.374 | | 0.369 |
Contractual term in years | | | 3.0 | | | | 3.0 | | | | 3.0 | | Contractual term in years | 3.0 | | 3.0 | | 3.0 |
Grant date price of Hess common stock | | $ | 48.48 | | | $ | 51.03 | | | $ | 44.31 | | Grant date price of Hess common stock | $ | 75.04 | | | $ | 49.72 | | | $ | 56.74 | |
69
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Stock options vest over three years from the date of grant, have a 10‑year term, and the exercise price equals the market price of theour common stock on the date of grant. The following is a summary of stock options activity in 2018:2021:
| | Number of options (In thousands) | | | Weighted Average Exercise Price per Share | | | Weighted Average Remaining Contractual Term | | | | | | | | | | | | | | | |
Outstanding at January 1, 2018 | | | 6,482 | | | $ | 66.84 | | | 3.6 years | |
| | | | Number of options
(In thousands) | | Weighted Average Exercise Price per Share | | Weighted Average Remaining Contractual Term |
| Outstanding at January 1, 2021 | | Outstanding at January 1, 2021 | 4,382 | | | $ | 61.57 | | | 5.1 years |
Granted | | | 683 | | | | 48.48 | | | | Granted | 319 | | | 75.04 | | |
Exercised | | | (564 | ) | | | 55.84 | | | | Exercised | (1,538) | | | 49.87 | | |
| Cancelled | | Cancelled | (1,049) | | | 83.88 | | |
Forfeited | | | (1,431 | ) | | | 80.23 | | | | Forfeited | (27) | | | 52.07 | | |
Outstanding at December 31, 2018 | | | 5,170 | | | $ | 61.91 | | | 4.3 years | |
| Outstanding at December 31, 2021 | | Outstanding at December 31, 2021 | 2,087 | | | $ | 61.15 | | | 6.5 years |
At December 31,
2018,2021, there were
5.22.1 million outstanding stock options
(3.9(1.17 million exercisable) with
a weighted average exercise price of $61.15 per share ($62.27 per share for exercisable options), a weighted average remaining contractual life of
4.36.5 years
(2.9(5.0 years for exercisable options) and an
aggregatedaggregate intrinsic value of
0 (0$28 million ($15 million for exercisable options).
The intrinsic value of stock options exercised in 2021 was $45 million (2020: $3 million, 2019: $10 million).
The following weighted average assumptions were utilized to estimate the fair value of stock options:
| | | 2018 | | | 2017 | | | 2016 | | | 2021 | | 2020 | | 2019 |
Risk free interest rate | | | 2.74 | % | | | 2.17 | % | | | 1.47 | % | Risk free interest rate | 0.95 | % | | 0.64 | % | | 2.55 | % |
Stock price volatility | | | 0.322 | | | | 0.333 | | | 0.326 | | Stock price volatility | 0.470 | | 0.372 | | 0.359 |
Dividend yield | | | 2.06 | % | | | 1.96 | % | | | 2.26 | % | Dividend yield | 1.33 | % | | 2.01 | % | | 1.76 | % |
Expected life in years | | | 6.0 | | | | 6.0 | | | | 6.0 | | Expected life in years | 6.0 | | 6.0 | | 6.0 |
Weighted average fair value per option granted | | $ | 13.69 | | | $ | 14.51 | | | $ | 11.33 | | Weighted average fair value per option granted | $ | 29.66 | | | $ | 14.30 | | | $ | 18.08 | |
In estimating the fair value of PSUs and stock options, the risk-free interest rate is based on the vesting period of the award and is obtained from published sources. The stock price volatility is determined from the historical stock prices of the Corporation using the expected term.
12. Exit and Disposal Costs
In 2018, we incurred severance expense of $38 million (2017: $18 million; 2016: $55 million) and paid accrued severance costs of $40 million (2017: $48 million; 2016: $52 million). The severance expenses incurred during the three-year period resulted from asset sales and cost savings initiatives in response to low crude oil prices. Severance charges were based on amounts incurred under ongoing severance arrangements or other statutory requirements, plus amounts earned under enhanced benefit arrangements. We recognized the expense associated with the enhanced benefits ratably over the estimated service period required for the employee to earn the benefit upon termination. We also recorded charges for vacated office space of $73 million in 2018 (2017: $14 million).
At December 31, 2018, we had accrued liabilities for severance costs of $4 million (2017: $6 million) and accrued liabilities for exit cost provisions of $85 million (2017: $28 million). Accrued severance costs are expected to be paid in 2019, and accrued exit costs will be paid over the next several years.
13. Impairment
2017: In the third quarter, we recognized a pre-tax charge of $2,503 million ($550 million after income taxes) to impair the carrying value of our interests in Norway based on an anticipated sale of the asset, which closed in the fourth quarter of 2017. See Note 3, Dispositions. In the fourth quarter, we recognized pre-tax impairment charges to reduce the carrying value of our interests in the Stampede Field by $1,095 million ($1,095 million after income taxes), and the Tubular Bells Field by $605 million ($605 million after income taxes) primarily as a result of a lower long-term crude oil price outlook. The Stampede Field had significant capitalized exploration and appraisal costs that were incurred on a 100% working interest basis on the Pony discovery prior to unitizing into the Stampede project. The fourth quarter impairment charges were based on a total fair value estimate of approximately $1.1 billion that was determined using internal projected discounted cash flows. The determination of projected discounted cash flows depended on estimates of oil and gas reserves, future prices, operating costs, capital expenditures, discount rate and timing of future net cash flows.
2016: We recorded a pre-tax impairment charge of $67 million ($21 million after income taxes and noncontrolling interest) to impair older specification rail cars in our Midstream segment based on estimated salvage values, which approximated fair value.
Each of the valuation methods used in the determination of the impairment charges above represent Level 3 fair value measurements.
70
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
14.
The provision (benefit) for income taxes consisted of:
| | 2018 | | | 2017 | | | 2016 (a) | |
| | (In millions) | |
United States | | | | | | | | | | | | |
Federal | | | | | | | | | | | | |
Current | | $ | 1 | | | $ | (23 | ) | | $ | (27 | ) |
Deferred taxes and other accruals | | | (74 | ) | | | (6 | ) | | | 1,948 | |
State | | | (45 | ) | | | — | | | | 23 | |
| | | (118 | ) | | | (29 | ) | | | 1,944 | |
Foreign | | | | | | | | | | | | |
Current (b) | | | 455 | | | | 179 | | | | 36 | |
Deferred taxes and other accruals | | | (2 | ) | | | (1,987 | ) | | | 235 | |
| | | 453 | | | | (1,808 | ) | | | 271 | |
Total | | | 335 | | | | (1,837 | ) | | | 2,215 | |
Adjustment of deferred taxes for foreign income tax law changes | | | — | | | | — | | | | 7 | |
Total Provision (Benefit) For Income Taxes | | $ | 335 | | | $ | (1,837 | ) | | $ | 2,222 | |
(a)
| Includes charges of $3,749 million to establish valuation allowances on net deferred tax assets.
|
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
| | | | | |
| | (In millions) |
| United States | | | | | |
| Federal | | | | | |
| Current | $ | — | | | $ | (4) | | | $ | (1) | |
| Deferred taxes and other accruals | 12 | | | 6 | | | 72 | |
| State | 3 | | | (1) | | | 16 | |
| | 15 | | | 1 | | | 87 | |
| Foreign | | | | | |
| Current (a) | 478 | | | 48 | | | 447 | |
| Deferred taxes and other accruals | 107 | | | (60) | | | (73) | |
| | 585 | | | (12) | | | 374 | |
| Provision (Benefit) For Income Taxes | $ | 600 | | | $ | (11) | | | $ | 461 | |
(b)
| Primarily comprised of Libya in 2018 and 2017.
|
(a)Primarily comprised of Libya in 2021, 2020 and 2019.Income (loss) before income taxes consisted of the following:
| | 2018 | | | 2017 | | | 2016 | |
| | (In millions) | |
United States (a) | | $ | (219 | ) | | $ | (2,784 | ) | | $ | (2,431 | ) |
Foreign | | | 439 | | | | (2,994 | ) | | | (1,423 | ) |
Total Income (Loss) Before Income Taxes | | $ | 220 | | | $ | (5,778 | ) | | $ | (3,854 | ) |
(a)
| Includes substantially all of our interest expense, corporate expense and the results of commodity hedging activities.
|
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
| | | | | |
| | (In millions) |
| United States (a) | $ | 143 | | | $ | (1,509) | | | $ | (338) | |
| Foreign | 1,347 | | | (1,341) | | | 559 | |
| Income (Loss) Before Income Taxes | $ | 1,490 | | | $ | (2,850) | | | $ | 221 | |
(a)Includes substantially all of our interest expense, corporate expense and the results of commodity hedging activities.
The difference between our effective income tax rate and the U.S. statutory rate is reconciled below:
| | 2018 | | 2017 | | 2016 |
U.S. statutory rate | | | 21.0 | | % | | | 35.0 | | % | | | 35.0 | | % |
Effect of foreign operations (a) | | | 141.2 | | | | | 17.4 | | | | | 4.6 | | |
State income taxes, net of Federal income tax | | | (18.9 | ) | | | | — | | | | | 1.9 | | |
Change in enacted tax laws (b) | | | — | | | | | (23.6 | ) | | | | (0.2 | ) | |
Valuation allowance adjustment with tax law change (b) | | | — | | | | | 23.6 | | | | | — | | |
Rate differential on U.S. loss | | | — | | | | | (4.1 | ) | | | | — | | |
Gains on asset sales, net | | | — | | | | | (2.2 | ) | | | | — | | |
Impairment | | | — | | | | | — | | | | | (2.1 | ) | |
Valuation allowance on current year operations | | | 55.2 | | | | | (14.9 | ) | | | | — | | |
Valuation allowance against previously benefitted deferred tax assets | | | — | | | | | 0.1 | | | | | (97.3 | ) | |
Noncontrolling interest in partnership | | | (15.9 | ) | | | | 0.8 | | | | | 0.5 | | |
Intraperiod allocation | | | (37.3 | ) | | | | — | | | | | — | | |
Equity compensation shortfall | | | 6.3 | | | | | (0.3 | ) | | | | — | | |
Other | | | 0.8 | | | | | — | | | | | (0.1 | ) | |
Total | | | 152.4 | | % | | | 31.8 | | % | | | (57.7 | ) | % |
(a)
| The variance in effective income tax rates attributable to the effect of foreign operations primarily resulted from the mix of income among high, primarily Libya, and low tax rate jurisdictions.
|
| | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 |
| U.S. statutory rate | 21.0 | % | | 21.0 | % | | 21.0 | % |
| Effect of foreign operations (a) | 28.0 | | | 12.1 | | | 142.9 | |
| State income taxes, net of federal income tax | 0.2 | | | 0.1 | | | 5.8 | |
| Valuation allowance on current year operations | (5.3) | | | (36.5) | | | 41.8 | |
| Release valuation allowance against previously unbenefited deferred tax assets | — | | | — | | | (24.5) | |
| Noncontrolling interests in Midstream | (4.0) | | | 1.7 | | | (16.0) | |
| Intraperiod allocation | — | | | — | | | 33.7 | |
| Credits | — | | | 2.0 | | | — | |
| Equity and executive compensation | 0.4 | | | (0.1) | | | 2.2 | |
| Other | — | | | 0.1 | | | 1.2 | |
| Total | 40.3 | % | | 0.4 | % | | 208.1 | % |
(b)
| The enactment of the U.S. Tax Cuts and Jobs Act provided for a decrease in the corporate tax rate to 21% from 35% and a change to a territorial tax regime, resulting in a net $1,336 million reduction to our U.S. net deferred tax asset at December 31, 2017, with a corresponding reduction in the previously established U.S. valuation allowance.
|
(a)The variance in effective income tax rates attributable to the effect of foreign operations primarily resulted from the mix of income among high, primarily Libya, and low tax rate jurisdictions.71
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The components of deferred tax liabilities and deferred tax assets at December 31, were as follows:
| | 2018 | | | 2017 | |
| | (In millions) | |
Deferred Tax Liabilities | | | | | | | | |
Property, plant and equipment and investments | | $ | (853 | ) | | $ | (629 | ) |
Other | | | (77 | ) | | | (24 | ) |
Total Deferred Tax Liabilities | | | (930 | ) | | | (653 | ) |
Deferred Tax Assets | | | | | | | | |
Net operating loss carryforwards | | | 4,239 | | | | 4,029 | |
Tax credit carryforwards | | | 134 | | | | 138 | |
Property, plant and equipment and investments | | | 416 | | | | 746 | |
Accrued compensation, deferred credits and other liabilities | | | 232 | | | | 283 | |
Asset retirement obligations | | | 225 | | | | 212 | |
Other | | | 161 | | | | 36 | |
Total Deferred Tax Assets | | | 5,407 | | | | 5,444 | |
Valuation allowances (a) | | | (4,877 | ) | | | (5,199 | ) |
Total deferred tax assets, net of valuation allowances | | | 530 | | | | 245 | |
Net Deferred Tax Assets (Liabilities) | | $ | (400 | ) | | $ | (408 | ) |
(a)
| In 2018, the valuation allowance decreased by $322 million (2017: decrease of $251 million; 2016: increase of $3,872).
|
| | | | | | | | | | | |
| | 2021 | | 2020 |
| | | |
| | (In millions) |
| Deferred Tax Liabilities | | | |
| Property, plant and equipment and investments | $ | (1,712) | | | $ | (847) | |
| Other | (38) | | | (45) | |
| Total Deferred Tax Liabilities | (1,750) | | | (892) | |
| Deferred Tax Assets | | | |
| Net operating loss carryforwards | 4,323 | | | 5,037 | |
| Tax credit carryforwards | 89 | | | 135 | |
| Property, plant and equipment and investments | 258 | | | 55 | |
| Accrued compensation, deferred credits and other liabilities | 71 | | | 196 | |
| Asset retirement obligations | 258 | | | 252 | |
| Other | 277 | | | 325 | |
| Total Deferred Tax Assets | 5,276 | | | 6,000 | |
| Valuation allowances (a) | (3,838) | | | (5,391) | |
| Total deferred tax assets, net of valuation allowances | 1,438 | | | 609 | |
| Net Deferred Tax Assets (Liabilities) | $ | (312) | | | $ | (283) | |
(a)In 2021, the valuation allowance decreased by $1,553 million (2020: increase of $657 million; 2019: decrease of $143 million).
In the Consolidated Balance Sheet, deferred tax assets and liabilities are netted by taxing jurisdiction and are recorded at December 31, as follows:
| | | | | 2021 | | 2020 |
| | 2018 | | | 2017 | | | | | |
| | (In millions) | | | (In millions) |
Deferred income taxes (long-term asset) | | $ | 21 | | | $ | 21 | | Deferred income taxes (long-term asset) | $ | 71 | | | $ | 59 | |
Deferred income taxes (long-term liability) | | | (421 | ) | | | (429 | ) | Deferred income taxes (long-term liability) | (383) | | | (342) | |
Net Deferred Tax Assets (Liabilities) | | $ | (400 | ) | | $ | (408 | ) | Net Deferred Tax Assets (Liabilities) | $ | (312) | | | $ | (283) | |
At December 31,
2018,2021, we have recognized a gross deferred tax asset related to net operating loss carryforwards of
$4,239$4,323 million before application of valuation allowances. The deferred tax asset is comprised of
$1,382$300 million attributable to foreign net operating losses which
will begin to expire in 2025,
$2,386$3,507 million attributable to U.S.
Federalfederal operating losses which
will begin to expire in
2035,2034, and
$471$516 million attributable to losses in various U.S. states which
will begin to expire in
2019.2022. The deferred tax asset attributable to foreign net operating losses, net of valuation allowances, is $12 $166 million. A full valuation allowance is established against the deferred tax asset attributable to U.S.
Federalfederal and state net operating
losses.losses, except for $12 million of U.S. federal and $3 million of U.S. state deferred tax assets attributable to Midstream activities for which separate U.S. federal and state tax returns are filed. At December 31,
2018,2021, we have U.S.
Federal, state
and foreign alternative minimum tax credit carryforwards of
$49$18 million, which
can be carried forward indefinitely, and approximately $15will begin to expire in 2034, $71 million of other business credit
carryforwards. The deferredcarryforwards, which will begin to expire in 2036, and foreign tax
asset attributablecredit carryforwards of $1 million, which will begin to
these credits, net of valuation allowances, is $1 million.expire in 2024. A full valuation allowance is established against
our foreignthe deferred tax
credit carryforwards of $70 million, which beginasset attributable to
expire in 2019.these credits.
At December 31, 2018,2021, the Consolidated Balance Sheet reflects a $4,877$3,838 million (2020: $5,391 million) valuation allowance against the net deferred tax assets for multiple jurisdictions based on application of the relevant accounting standards. Hess continues
to maintain a full valuation allowance against its deferred tax assets in the U.S., Denmark (hydrocarbon tax only), (non-Midstream) and Malaysia, and Guyana.other certain jurisdictions, and did so against its deferred tax assets in Denmark prior to its sale in 2021 (see Note 11, Dispositions). The reduction in valuation allowance year over year is primarily due to the sale of the Denmark asset with its deferred tax asset and related valuation allowance being derecognized as part of net basis of property sold and partially due to a reduction in deferred tax asset balances in jurisdictions where we continue to maintain a full valuation allowance. Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. The cumulative loss incurred over the three-year period ending December 31, 20182021 constitutes significant objective negative evidence. Such objective negative evidence limits our ability to consider subjective positive evidence, such as our projections of future taxable income, resulting in the recognition of a valuation allowance against the net deferred tax assets for these jurisdictions. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income change or if objective negative evidence in the form of cumulative losses is no longer present and additional weight can be given to subjective evidence.The Company completed its review of previously recorded provisional income tax amounts related to the U.S. Tax Cuts and Jobs Act (“Act”) and concluded that additional information, interpretation and guidance that became available during the twelve-month measurement period did not alter the Company’s accounting as reported in its Consolidated Financial Statements as of December 31, 2017. There were no adjustments deemed necessary in the period ended December 31, 2018.
72
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Below is a reconciliation of the gross beginning and ending amounts of unrecognized tax benefits:
| | | | | 2021 | | 2020 | | 2019 |
| | 2018 | | | 2017 | | | 2016 | | | | | | | |
| | (In millions) | | | (In millions) |
Balance at January 1 | | $ | 205 | | | $ | 424 | | | $ | 604 | | Balance at January 1 | $ | 166 | | | $ | 168 | | | $ | 168 | |
Additions based on tax positions taken in the current year | | | 19 | | | | 14 | | | | 19 | | Additions based on tax positions taken in the current year | 12 | | | 2 | | | 2 | |
Additions based on tax positions of prior years | | | 36 | | | | 4 | | | | 113 | | Additions based on tax positions of prior years | 3 | | | 1 | | | 1 | |
Reductions based on tax positions of prior years | | | (78 | ) | | | (147 | ) | | | (274 | ) | Reductions based on tax positions of prior years | (48) | | | (2) | | | (1) | |
Reductions due to settlements with taxing authorities | | | (10 | ) | | | (85 | ) | | | (27 | ) | Reductions due to settlements with taxing authorities | — | | | (1) | | | — | |
Reductions due to lapses in statutes of limitation | | | (4 | ) | | | (5 | ) | | | (11 | ) | Reductions due to lapses in statutes of limitation | — | | | (2) | | | (2) | |
Balance at December 31 | | $ | 168 | | | $ | 205 | | | $ | 424 | | Balance at December 31 | $ | 133 | | | $ | 166 | | | $ | 168 | |
The December 31,
20182021 balance of unrecognized tax benefits includes
$7$15 million that, if recognized, would impact our effective income tax rate. Over the next 12 months, it is reasonably possible that the total amount of unrecognized tax benefits could decrease between
$2 million0 and
$8$15 million due to settlements with taxing authorities or other resolutions, as well as lapses in statutes of limitation. At December 31,
2018,2021, our accrued interest and penalties related to unrecognized tax benefits is
$3$6 million
(2017: $23(2020: $6 million).
We file income tax returns in the U.S. and various foreign jurisdictions. We are no longer subject to examinations by income tax authorities in most jurisdictions for years prior to
2005.15. Basic2009.
16. Outstanding and
Diluted Earnings PerWeighted Average Common
ShareShares
The Net income (loss) and weighted average number of common shares used in basic and diluted earnings per share computation were as follows:
| | | | | 2021 | | 2020 | | 2019 |
| | 2018 | | | 2017 | | | 2016 | | | | | | | |
| | (In millions) | | | (In millions except per share amounts) |
Net Income (Loss) Attributable to Hess Corporation Common Stockholders: | | | | | | | | | | | | | Net Income (Loss) Attributable to Hess Corporation Common Stockholders: | | | | | |
Net income (loss) | | $ | (115 | ) | | $ | (3,941 | ) | | $ | (6,076 | ) | Net income (loss) | $ | 890 | | | $ | (2,839) | | | $ | (240) | |
Less: Net income (loss) attributable to noncontrolling interests | | | 167 | | | | 133 | | | | 56 | | Less: Net income (loss) attributable to noncontrolling interests | 331 | | | 254 | | | 168 | |
Less: Preferred stock dividends | | | 46 | | | | 46 | | | | 41 | | Less: Preferred stock dividends | — | | | — | | | 4 | |
Net income (loss) attributable to Hess Corporation Common Stockholders | | $ | (328 | ) | | $ | (4,120 | ) | | $ | (6,173 | ) | Net income (loss) attributable to Hess Corporation Common Stockholders | $ | 559 | | | $ | (3,093) | | | $ | (412) | |
| | | | | | | | | | | | | | | | | | |
Weighted Average Number of Common Shares Outstanding: | | | | Weighted Average Number of Common Shares Outstanding: | |
Basic | | | 298.2 | | | | 314.1 | | | | 309.9 | | Basic | 307.4 | | | 304.8 | | | 301.2 | |
Effect of dilutive securities | | | | | | | | | | | | | Effect of dilutive securities | |
Restricted common stock | | | — | | | | — | | | | — | | Restricted common stock | 0.7 | | | — | | | — | |
Stock options | | | — | | | | — | | | | — | | Stock options | 0.4 | | | — | | | — | |
Performance share units | | | — | | | | — | | | | — | | Performance share units | 0.8 | | | — | | | — | |
Mandatory Convertible Preferred stock | | | — | | | | — | | | | — | | |
Diluted | | | 298.2 | | | | 314.1 | | | | 309.9 | | Diluted | 309.3 | | | 304.8 | | | 301.2 | |
| | | | | | | | | | | | | | | | | | |
Net Income (Loss) Attributable to Hess Corporation per Common Share: | | | | | | | | | | | | | Net Income (Loss) Attributable to Hess Corporation per Common Share: | |
Basic | | $ | (1.10 | ) | | $ | (13.12 | ) | | $ | (19.92 | ) | Basic | $ | 1.82 | | | $ | (10.15) | | | $ | (1.37) | |
Diluted | | $ | (1.10 | ) | | $ | (13.12 | ) | | $ | (19.92 | ) | Diluted | $ | 1.81 | | | $ | (10.15) | | | $ | (1.37) | |
| | | | | | | | | | | | | |
Antidilutive shares excluded from the computation of diluted shares: | | | | Antidilutive shares excluded from the computation of diluted shares: | |
Restricted common stock | | | 2.9 | | | | 3.3 | | | | 3.3 | | Restricted common stock | — | | | 2.1 | | | 2.2 | |
Stock options | | | 5.5 | | | | 6.4 | | | | 6.9 | | Stock options | 0.7 | | | 4.3 | | | 4.7 | |
Performance share units | | | 1.1 | | | | 0.6 | | | | 0.9 | | Performance share units | — | | | 1.1 | | | 1.7 | |
Common shares from conversion of preferred stock | | | 12.7 | | | | 12.8 | | | | 11.2 | | |
73
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
16. Common and Preferred Stock
The following table provides the changes in our outstanding common shares:
| | | | | 2021 | | 2020 | | 2019 |
| | 2018 | | | 2017 | | | 2016 | | | | | | | |
| | (In millions) | | | (In millions) |
Balance at January 1 | | | 315.1 | | | | 316.5 | | | | 286.0 | | Balance at January 1 | 307.0 | | | 304.9 | | | 291.4 | |
Shares issued | | | — | | | | — | | | | 28.8 | | |
| Conversion of preferred stock | | Conversion of preferred stock | — | | | — | | | 11.6 | |
Activity related to restricted stock awards, net | | | 0.8 | | | | 0.8 | | | | 1.1 | | Activity related to restricted stock awards, net | 0.7 | | | 1.0 | | | 0.9 | |
Stock options exercised | | | 0.6 | | | | 0.2 | | | | 0.2 | | Stock options exercised | 1.5 | | | 0.3 | | | 0.7 | |
PSU vested | | | 0.1 | | | | 0.2 | | | | 0.4 | | |
Shares repurchased | | | (25.2 | ) | | | (2.6 | ) | | | — | | |
| PSUs vested | | PSUs vested | 0.5 | | | 0.8 | | | 0.3 | |
| Balance at December 31 | | | 291.4 | | | | 315.1 | | | | 316.5 | | Balance at December 31 | 309.7 | | | 307.0 | | | 304.9 | |
Common and
Preferred Stock Issuance: In February 2016, we issued
28,750,000 shares of common stock and depositarydepository shares representing 575,000 shares of 8% Series A Mandatory Convertible Preferred Stock
(Convertible Preferred(Preferred Stock), par value $1 per share, with a liquidation preference of $1,000 per
share, for total net proceeds of approximately $1.6 billion after deducting underwriting discounts, commissions, and offering expenses. The dividends onshare. On January 31, 2019, the
Convertible Preferred Stock
are payable on a cumulative basis. Unlessautomatically converted
earlier, each share of Convertible Preferred Stock will automatically convert into
between 21.822 shares and 25.642 shares of
our common stock
based onand the
volume weighted average share price (“VWAP”) over a period of twenty-consecutive trading days ending January 28, 2019, subject to anti-dilution adjustments. See Note 15, Basic and Diluted Earnings Per Common Share and Note 22, Subsequent Event.We also entered into capped call transactions on 12.55 million covered shares that were expected generally to reduce the potential dilution to our common stock upon conversion of the Convertible Preferred Stock if the VWAP for any individual day during the period of twenty consecutive trading days ending January 28, 2019 exceeded $45.83 per share, subject to anti-dilution adjustments. On any day during the twenty consecutive trading days ending January 28, 2019, if the daily VWAP is between $45.83 and $53.625, the value of the capped call transactions for that day will be the proportionate covered shares multiplied by the difference between the VWAP for that day and $45.83. Thenet number of common shares to be deliveredissued by the counterparties to us will be the sum of each daily calculation during the twenty-consecutive trading day period. The premium paid for the capped call transactionsCorporation was $37approximately 11.6 million which was recorded against Capital in excess of par in the Statement of Consolidated Equity. See Note 22, Subsequent Event.
shares.
Common Stock Repurchase Plan:In 2018, we repurchased 25.2 million shares of our common stock (2017: 2.6 million shares) for $1,380 million (2017: $120 million), at an average cost per share of $54.85 (2017: $45.67). There were no repurchases in 2016.
At December 31,
2018,2021, we are authorized, but not required, to purchase additional common stock up to a value of $650 million.
Common stock dividendsStock Dividends:In 2018, 2017 and 2016, cash
Cash dividends declared on common stock totaled $1.00 per share ($0.25 per quarter). 74
in 2021, 2020 and 2019. See Note 21, Subsequent Events.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. Supplementary Cash Flow Information
The following information supplements the Statement of Consolidated Cash Flows:
| | 2018 | | | 2017 | | | 2016 | | | | | | | | | | | | | | | | |
| | (In millions) | | | 2021 | | 2020 | | 2019 |
Cash Flows from Operating Activities | | | | | | | | | | | | | |
| | | | | (In millions) |
| Cash Flows From Operating Activities | | Cash Flows From Operating Activities | | | | | |
Interest paid | | $ | (394 | ) | | $ | (314 | ) | | $ | (338 | ) | Interest paid | $ | (459) | | | $ | (460) | | | $ | (380) | |
Net income taxes (paid) refunded | | | (463 | ) | | | (210 | ) | | | 132 | | Net income taxes (paid) refunded | (16) | | | (64) | | | (417) | |
| | | | | | | | | | | | | |
Cash Flows from Investing Activities | | | | | | | | | | | | | |
| Cash Flows From Investing Activities | | Cash Flows From Investing Activities | |
| Additions to property, plant and equipment - E&P: | | Additions to property, plant and equipment - E&P: | |
Capital expenditures incurred - E&P | | $ | (1,909 | ) | | $ | (1,852 | ) | | $ | (1,638 | ) | Capital expenditures incurred - E&P | $ | (1,698) | | | $ | (1,678) | | | $ | (2,576) | |
Increase (decrease) in related liabilities | | | 55 | | | | 64 | | | | (336 | ) | Increase (decrease) in related liabilities | 114 | | | (218) | | | 143 | |
Additions to property, plant and equipment - E&P | | $ | (1,854 | ) | | $ | (1,788 | ) | | $ | (1,974 | ) | Additions to property, plant and equipment - E&P | $ | (1,584) | | | $ | (1,896) | | | $ | (2,433) | |
| | | | | | | | | | | | | | | | | | |
| Additions to property, plant and equipment - Midstream: | | Additions to property, plant and equipment - Midstream: | |
Capital expenditures incurred - Midstream | | $ | (271 | ) | | $ | (121 | ) | | $ | (283 | ) | Capital expenditures incurred - Midstream | $ | (183) | | | $ | (253) | | | $ | (416) | |
Increase (decrease) in related liabilities | | | 28 | | | | (28 | ) | | | 6 | | Increase (decrease) in related liabilities | 20 | | | (48) | | | 20 | |
Additions to property, plant and equipment - Midstream | | $ | (243 | ) | | $ | (149 | ) | | $ | (277 | ) | Additions to property, plant and equipment - Midstream | $ | (163) | | | $ | (301) | | | $ | (396) | |
18. Leased Assets
We and certain
In December 2019, as part of our subsidiaries lease drilling rigs, support vessels, office space and other assets for varying periods under contractual obligations accounted for as operating leases. Operating lease expenses for drilling rigs used to drill development wells and successful exploration wells are capitalized. At December 31, 2018, future minimum rental payments applicable to non‑cancelable operating leases with remaining terms in excessHESM Opco’s acquisition of one year (other than oil and gas property leases) are as follows (in millions):HIP (see Note 4, Hess Midstream LP), HESM Opco assumed $800 million of outstanding HIP notes (see Note 7, Debt). 2019 | | $ | 355 | |
2020 | | 156 | |
2021 | | 65 | |
2022 | | 64 | |
2023 | | 64 | |
Remaining years | | 198 | |
Total Minimum Lease Payments | | | 902 | |
Less: Income from subleases | | 114 | |
Net Minimum Lease Payments | | $ | 788 | |
Rental expense was as follows:
| | 2018 | | | 2017 | | | 2016 | |
| | (In millions) | |
Total rental expense | | $ | 154 | | | $ | 123 | | | $ | 106 | |
Less: Income from subleases | | 8 | | | 10 | | | 5 | |
Net Rental Expense | | $ | 146 | | | $ | 113 | | | $ | 101 | |
75
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
19.18. Guarantees, Contingencies and Commitments
Guarantees and Contingencies
We are subject to loss contingencies with respect to various claims, lawsuits and other proceedings. A liability is recognized in our consolidated financial statements when it is probable that a loss has been incurred and the amount can be reasonably estimated. If the risk of loss is probable, but the amount cannot be reasonably estimated or the risk of loss is only reasonably possible, a liability is not accrued; however, we disclose the nature of those contingencies. We cannot predict with certainty if, how or when existing claims, lawsuits and proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages.
Numerous issues may need to be resolved, including through lengthy discovery, conciliation and/or arbitration proceedings, or litigation before a loss or range of loss can be reasonably estimated. Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of such lawsuits, claims and proceedings, including the matters described below, is not expected to have a material adverse effect on our financial condition. 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.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
methyl tertiary butyl ether (MTBE)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
three2 remaining active cases, filed by Pennsylvania
Rhode Island, 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
September 2016, the State of Rhode Island also filed a lawsuit alleging that we and other major oil companies damaged the groundwater in Rhode Island by introducing thereto gasoline with MTBE. The suit filed in Rhode Island is proceeding in Federal court. 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
Federalfederal court by the defendants.
In September 2003, we received a directive from the New Jersey Department of Environmental Protection (NJDEP)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 Environmental Protection Agency (EPA)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 also agreed with the EPA to fund remediation of a portion of the site. On March 4, 2016, the EPA issued a Record of Decision (ROD)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 Federalfederal 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.
EPA has estimatedThe EPA’s original estimate was that this remedy
willwould cost $506 million; however, the ultimate costs that will be incurred in connection with the design and implementation of the remedy remain uncertain.
Our alleged liability derives from our former ownership and operation of a fuel oil terminal and connected ship-building and repair facility adjacent toWe have complied with the
Canal. We indicated to EPA that we would comply with the76
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
EPA’s March 2014 Administrative Order and are currently contributingcontributed funding for the Remedial Design based on an interim allocation of costs among the parties. Atparties determined by a third-party expert. In January 2020, we received an additional Administrative Order from the same time,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 are participatingdo not believe that this matter will result in an allocation process whereby a neutral expert selected bysignificant liability to us, and the costs will continue to be allocated amongst the parties, will determine the final shares ofas they were for the Remedial Design costs to be paid by each of the participants.
On September 28, 2017, we received a general notice letter and offer to settle from the U.S. Environmental Protection Agency relating to Superfund claims for the Ector Drum, Inc. Superfund Site in Odessa, Texas. The EPA and Texas Commission on Environmental Quality (TCEQ) took clean-up and response action at the site commencing in 2014 and concluded in December 2015. The site was determined to have improperly stored industrial waste, including drums with oily liquids. The total clean-up cost incurred by the EPA was approximately $3.5 million. We were invited to negotiate a voluntary settlement for our purported share of the clean-up costs. Our share, if any, is undetermined.
Design.
From time to time, we are involved in other judicial and administrative proceedings including proceedings relating to environmental matters. We periodically receive notices from the EPA that we are a “potential responsible party” under the Superfund legislation with respect to various waste disposal sites. Under this legislation, all potentially responsible parties may be jointly and severally liable. For any site for which we have received such a notice, the EPA’s claims or assertions of liability against us relating to these sites have not been fully developed, or the EPA’s claims have been settled or a settlement is under consideration, in all cases for amounts that are not material. Beginning in 2017, certain states, municipalities and private associations in California, Delaware, Maryland, Rhode Island and South Carolina separately filed lawsuits against oil, gas and coal producers, including us, for alleged damages purportedly caused by climate change. These proceedings include claims for monetary damages and injunctive relief. Beginning in 2013, various parishes in Louisiana filed suit against approximately 100 oil and gas companies, including us, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused contamination, subsidence and other environmental matters.damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. The ultimate impact of such climate and other aforementioned environmental proceedings, and of any related proceedings by private parties, on our business or accounts cannot be predicted at this time due to the large number of other potentially responsible parties and the speculative nature of clean-up cost estimates.
We are also involved in other judicial and administrative proceedings from time to time in addition to the matters described above, including claims related to post-production deductions from royalty payments. We may also be exposed to future decommissioning liabilities for divested assets in the event the current or future owners of facilities previously owned by us are determined to be unable to perform such actions, whether due to bankruptcy or otherwise. We cannot predict with certainty if, how or when such proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages. Numerous issues may need to be resolved, including through potentially lengthy discovery and determination of important factual matters before a loss or range of loss can be reasonably estimated for any proceeding.
Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of
lawsuits, claims and proceedings, including the
aforementioned proceedingsmatters disclosed above, is not expected to have a material adverse effect on our financial condition, results of operations or cash flows.
However, we could incur judgments, enter into settlements, or revise our opinion regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations in the period in which the amounts are accrued and our cash flows in the period in which the amounts are paid.
Unconditional Purchase Obligations and Commitments
The following table shows aggregate information for certain unconditional purchase obligations and commitments at December 31, 2018,2021, which are not included elsewhere within these Consolidated Financial Statements:
| | | | | | | Payments Due by Period | | | | | Payments Due by Period |
| | | | | | | | | | 2020 and | | | 2022 and | | | | | | | Total | | 2022 | | 2023 and
2024 | | 2025 and
2026 | | Thereafter |
| | Total | | | 2019 | | | 2021 | | | 2023 | | | Thereafter | | | | | | | | | | | |
| | (In millions) | | | (In millions) |
Capital expenditures | | $ | 1,069 | | | $ | 443 | | | $ | 551 | | | $ | 75 | | | $ | — | | Capital expenditures | $ | 3,263 | | | $ | 1,028 | | | $ | 1,458 | | | $ | 777 | | | $ | — | |
Operating expenses | | | 433 | | | | 219 | | | | 99 | | | | 61 | | | | 54 | | Operating expenses | 180 | | | 132 | | | 42 | | | 6 | | | — | |
Transportation and related contracts | | | 1,050 | | | | 212 | | | | 401 | | | | 336 | | | | 101 | | Transportation and related contracts | 2,574 | | | 390 | | | 639 | | | 453 | | | 1,092 | |
77
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)20.
We currently have
two2 operating segments,
Exploration and Production (E&P)E&P and Midstream. The E&P operating segment explores for, develops, produces, purchases and sells crude oil,
NGLsNGL and natural gas. Production operations over the three years ended December 31,
20182021 were
primarily in the
United States (U.S.)U.S.,
Denmark,Malaysia and the JDA,
Denmark (sold in August 2021), Libya, and
Malaysia, and from divested assets, including Equatorial Guinea (until November 2017) and Norway (untilGuyana commencing December
2017).2019. The Midstream operating segment provides fee-based services including crude oil and natural gas gathering, processing of natural gas and the fractionation of
NGLs,NGL, transportation of crude oil by rail car, terminaling and loading crude oil and
NGLs,NGL, storing and terminaling propane, and water handling services primarily in the Bakken shale play of North Dakota. All unallocated costs are reflected under Corporate, Interest and Other.
The following table presents operating segment financial data (in millions):
| | Exploration and Production | | | Midstream | | | Corporate, Interest and Other | | | Eliminations | | | Total | |
2018 | | | | | | | | | | | | | | | | | | | | |
Sales and Other Operating Revenues - Third-parties | | $ | 6,323 | | | $ | — | | | $ | — | | | $ | — | | | $ | 6,323 | |
Intersegment Revenues | | | — | | | | 713 | | | | — | | | | (713 | ) | | | — | |
Sales and Other Operating Revenues | | $ | 6,323 | | | $ | 713 | | | $ | — | | | $ | (713 | ) | | $ | 6,323 | |
| | | | | | | | | | | | | | | | | | | | |
Net Income (Loss) Attributable to Hess Corporation | | $ | 51 | | | $ | 120 | | | $ | (453 | ) | | $ | — | | | $ | (282 | ) |
Interest Expense | | | — | | | | 60 | | | | 339 | | | | — | | | | 399 | |
Depreciation, Depletion and Amortization | | | 1,748 | | | | 127 | | | | 8 | | | | — | | | | 1,883 | |
Provision (Benefit) for Income Taxes (a) | | | 391 | | | | 38 | | | | (94 | ) | | | — | | | | 335 | |
Investment in Affiliates | | | 126 | | | | 67 | | | | — | | | | — | | | | 193 | |
Identifiable Assets | | | 16,109 | | | | 3,285 | | | | 2,039 | | | | — | | | | 21,433 | |
Capital Expenditures | | | 1,909 | | | | 271 | | | | — | | | | — | | | | 2,180 | |
| | | | | | | | | | | | | | | | | | | | |
2017 | | | | | | | | | | | | | | | | | | | | |
Sales and Other Operating Revenues - Third-parties | | $ | 5,460 | | | $ | 6 | | | $ | — | | | $ | — | | | $ | 5,466 | |
Intersegment Revenues | | | — | | | | 611 | | | | — | | | | (611 | ) | | | — | |
Sales and Other Operating Revenues | | $ | 5,460 | | | $ | 617 | | | $ | — | | | $ | (611 | ) | | $ | 5,466 | |
| | | | | | | | | | | | | | | | | | | | |
Net Income (Loss) Attributable to Hess Corporation | | $ | (3,653 | ) | | $ | 42 | | | $ | (463 | ) | | $ | — | | | $ | (4,074 | ) |
Interest Expense | | | — | | | | 26 | | | | 299 | | | | — | | | | 325 | |
Depreciation, Depletion and Amortization | | | 2,736 | | | | 123 | | | | 24 | | | | — | | | | 2,883 | |
Impairment | | | 4,203 | | | | — | | | | — | | | | — | | | | 4,203 | |
Provision (Benefit) for Income Taxes (a) | | | (1,842 | ) | | | 31 | | | | (26 | ) | | | — | | | | (1,837 | ) |
Investment in Affiliates | | | 134 | | | | — | | | | — | | | | — | | | | 134 | |
Identifiable Assets | | | 15,613 | | | | 3,329 | | | | 4,170 | | | | — | | | | 23,112 | |
Capital Expenditures | | | 1,852 | | | | 121 | | | | — | | | | — | | | | 1,973 | |
| | | | | | | | | | | | | | | | | | | | |
2016 | | | | | | | | | | | | | | | | | | | | |
Sales and Other Operating Revenues - Third-parties | | $ | 4,755 | | | $ | 7 | | | $ | — | | | $ | — | | | $ | 4,762 | |
Intersegment Revenues | | | — | | | | 562 | | | | — | | | | (562 | ) | | | — | |
Sales and Other Operating Revenues | | $ | 4,755 | | | $ | 569 | | | $ | — | | | $ | (562 | ) | | $ | 4,762 | |
| | | | | | | | | | | | | | | | | | | | |
Net Income (Loss) Attributable to Hess Corporation | | $ | (4,964 | ) | | $ | 42 | | | $ | (1,210 | ) | | $ | — | | | $ | (6,132 | ) |
Interest Expense | | | — | | | | 19 | | | | 319 | | | | — | | | | 338 | |
Depreciation, Depletion and Amortization | | | 3,113 | | | | 121 | | | | 10 | | | | — | | | | 3,244 | |
Impairment | | | — | | | | 67 | | | | — | | | | — | | | | 67 | |
Provision (Benefit) for Income Taxes | | | 1,587 | | | | 26 | | | | 609 | | | | — | | | | 2,222 | |
Capital Expenditures | | | 1,638 | | | | 283 | | | | — | | | | — | | | | 1,921 | |
(a)
| The provision for income taxes in the Midstream segment in 2018 and 2017 is presented before consolidating its operations with other U.S. activities of the Company and prior to evaluating realizability of net U.S. deferred taxes. An offsetting impact is presented in the E&P segment.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exploration and Production | | Midstream | | Corporate, Interest and Other | | Eliminations | | Total |
| 2021 | | | | | | | | | |
| Sales and Other Operating Revenues - Third parties | $ | 7,473 | | | $ | — | | | $ | — | | | $ | — | | | $ | 7,473 | |
| Intersegment Revenues | — | | | 1,204 | | | — | | | (1,204) | | | — | |
| Sales and Other Operating Revenues | $ | 7,473 | | | $ | 1,204 | | | $ | — | | | $ | (1,204) | | | $ | 7,473 | |
| Net Income (Loss) Attributable to Hess Corporation | $ | 770 | | | $ | 286 | | | $ | (497) | | | $ | — | | | $ | 559 | |
| Interest Expense | — | | | 105 | | | 376 | | | — | | | 481 | |
| Depreciation, Depletion and Amortization | 1,361 | | | 166 | | | 1 | | | — | | | 1,528 | |
| Impairment and Other | 147 | | | — | | | — | | | — | | | 147 | |
| Provision (Benefit) for Income Taxes | 585 | | | 15 | | | — | | | — | | | 600 | |
| Investment in Affiliates | 94 | | | 102 | | | 1 | | | — | | | 197 | |
| Identifiable Assets | 14,173 | | | 3,671 | | | 2,671 | | | — | | | 20,515 | |
| Capital Expenditures | 1,698 | | | 183 | | | — | | | — | | | 1,881 | |
| | | | | | | | | |
| 2020 | | | | | | | | | |
| Sales and Other Operating Revenues - Third parties | $ | 4,667 | | | $ | — | | | $ | — | | | $ | — | | | $ | 4,667 | |
| Intersegment Revenues | — | | | 1,092 | | | — | | | (1,092) | | | — | |
| Sales and Other Operating Revenues | $ | 4,667 | | | $ | 1,092 | | | $ | — | | | $ | (1,092) | | | $ | 4,667 | |
| Net Income (Loss) Attributable to Hess Corporation | $ | (2,841) | | | $ | 230 | | | $ | (482) | | | $ | — | | | $ | (3,093) | |
| Interest Expense | — | | | 95 | | | 373 | | | — | | | 468 | |
| Depreciation, Depletion and Amortization | 1,915 | | | 157 | | | 2 | | | — | | | 2,074 | |
| Impairment and Other | 2,126 | | | — | | | — | | | — | | | 2,126 | |
| Provision (Benefit) for Income Taxes | (12) | | | 7 | | | (6) | | | — | | | (11) | |
| Investment in Affiliates | 104 | | | 108 | | | — | | | — | | | 212 | |
| Identifiable Assets | 13,688 | | | 3,599 | | | 1,534 | | | — | | | 18,821 | |
| Capital Expenditures | 1,678 | | | 253 | | | — | | | — | | | 1,931 | |
| | | | | | | | | |
| 2019 | | | | | | | | | |
| Sales and Other Operating Revenues - Third parties | $ | 6,495 | | | $ | — | | | $ | — | | | $ | — | | | $ | 6,495 | |
| Intersegment Revenues | — | | | 848 | | | — | | | (848) | | | — | |
| Sales and Other Operating Revenues | $ | 6,495 | | | $ | 848 | | | $ | — | | | $ | (848) | | | $ | 6,495 | |
| Net Income (Loss) Attributable to Hess Corporation | $ | 53 | | | $ | 144 | | | $ | (605) | | | $ | — | | | $ | (408) | |
| Interest Expense | — | | | 63 | | | 317 | | | — | | | 380 | |
| Depreciation, Depletion and Amortization | 1,977 | | | 142 | | | 3 | | | — | | | 2,122 | |
| Provision (Benefit) for Income Taxes | 375 | | | — | | | 86 | | | — | | | 461 | |
| Capital Expenditures | 2,576 | | | 416 | | | — | | | — | | | 2,992 | |
78
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents financial information by major geographic area:
| | United States | | | Europe | | | Africa | | | Asia and Other Countries | | | Corporate, Interest and other | | | Total | |
| | (In millions) | |
2018 | | | | | | | | | | | | | | | | | | | | | | | | |
Sales and Other Operating Revenues | | $ | 4,842 | | | $ | 164 | | | $ | 548 | | | $ | 769 | | | $ | — | | | $ | 6,323 | |
Net Income (Loss) Attributable to Hess Corporation | | | 131 | | | | 42 | | | | 36 | | | | (38 | ) | | | (453 | ) | | | (282 | ) |
Depreciation, Depletion and Amortization | | | 1,424 | | | | 37 | | | | 19 | | | | 395 | | | | 8 | | | | 1,883 | |
Provision (Benefit) for Income Taxes | | | (25 | ) | | | 15 | | | | 430 | | | | 9 | | | | (94 | ) | | | 335 | |
Identifiable Assets | | | 13,250 | | | | 1,033 | | | | 395 | | | | 4,716 | | | | 2,039 | | | | 21,433 | |
Property, Plant and Equipment (Net) | | | 11,653 | | | | 906 | | | | 355 | | | | 3,154 | | | | 15 | | | | 16,083 | |
Capital Expenditures | | | 1,543 | | | | 8 | | | | 9 | | | | 620 | | | | — | | | | 2,180 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
2017 | | | | | | | | | | | | | | | | | | | | | | | | |
Sales and Other Operating Revenues | | $ | 3,692 | | | $ | 629 | | | $ | 675 | | | $ | 470 | | | $ | — | | | $ | 5,466 | |
Net Income (Loss) Attributable to Hess Corporation | | | (2,433 | ) | | | (1,383 | ) | | | 259 | | | | (54 | ) | | | (463 | ) | | | (4,074 | ) |
Depreciation, Depletion and Amortization | | | 1,942 | | | | 381 | | | | 263 | | | | 273 | | | | 24 | | | | 2,883 | |
Impairment | | | 1,700 | | | | 2,503 | | | | — | | | | — | | | | — | | | | 4,203 | |
Provision (Benefit) for Income Taxes | | | — | | | | (1,999 | ) | | | 197 | | | | (9 | ) | | | (26 | ) | | | (1,837 | ) |
Identifiable Assets | | | 13,640 | | | | 1,024 | | | | 428 | | | | 3,850 | | | | 4,170 | | | | 23,112 | |
Property, Plant and Equipment (Net) | | | 11,894 | | | | 946 | | | | 365 | | | | 2,964 | | | | 23 | | | | 16,192 | |
Capital Expenditures | | | 1,387 | | | | 141 | | | | 30 | | | | 415 | | | | — | | | | 1,973 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
2016 | | | | | | | | | | | | | | | | | | | | | | | | |
Sales and Other Operating Revenues | | $ | 3,085 | | | $ | 610 | | | $ | 601 | | | $ | 466 | | | $ | — | | | $ | 4,762 | |
Net Income (Loss) Attributable to Hess Corporation | | | (2,353 | ) | | | (439 | ) | | | (355 | ) | | | (1,775 | ) | | | (1,210 | ) | | | (6,132 | ) |
Depreciation, Depletion and Amortization | | | 2,133 | | | | 502 | | | | 375 | | | | 224 | | | | 10 | | | | 3,244 | |
Impairment | | | 67 | | | | — | | | | — | | | | — | | | | — | | | | 67 | |
Provision (Benefit) for Income Taxes | | | 411 | | | | 243 | | | | 244 | | | | 715 | | | | 609 | | | | 2,222 | |
Capital Expenditures | | | 1,400 | | | | 59 | | | | 10 | | | | 452 | | | | — | | | | 1,921 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | United States | | Guyana | | Malaysia and JDA | | Other (a) | | Corporate, Interest and other | | Total |
| | | | | | | | | | | |
| | (In millions) |
| 2021 | | | | | | | | | | | |
| Sales and Other Operating Revenues | $ | 5,378 | | | $ | 754 | | | $ | 738 | | | $ | 603 | | | $ | — | | | $ | 7,473 | |
| Property, Plant and Equipment (Net) (b) | 9,721 | | | 3,064 | | | 1,035 | | | 352 | | | 10 | | | 14,182 | |
| 2020 | | | | | | | | | | | |
| Sales and Other Operating Revenues | $ | 3,604 | | | $ | 350 | | | $ | 511 | | | $ | 202 | | | $ | — | | | $ | 4,667 | |
| Property, Plant and Equipment (Net) (b) | 10,384 | | | 2,114 | | | 1,067 | | | 539 | | | 11 | | | 14,115 | |
| 2019 | | | | | | | | | | | |
| Sales and Other Operating Revenues | $ | 5,043 | | | $ | — | | | $ | 762 | | | $ | 690 | | | $ | — | | | $ | 6,495 | |
21.
(a)Other includes our interests in Denmark (sold in August 2021), Libya, Suriname and Canada.
(b)Property, plant and equipment in the United States in 2021 includes $6,596 million (2020: $7,273 million) attributable to the E&P segment and $3,125 million (2020: $3,111 million) attributable to the Midstream segment.
20. Financial Risk Management Activities
In the normal course of our business, we are exposed to commodity risks related to changes in the prices of crude oil and natural gas, as well as changes in interest rates and foreign currency values. In the disclosures that follow, corporate financial risk management activities refer to the mitigation of these risks through hedging activities. We maintain a control environment for all of our financial risk management activities under the direction of our Chief Risk Officer. Our Treasury department is responsible for administering foreign exchange rate and interest rate hedging programs using similar controls and processes, where applicable. Hedging strategies are reviewed annually by the Audit Committee of the Board of Directors.
Corporate Financial Risk Management Activities: Financial risk management activities include transactions designed to reduce risk in the selling prices of crude oil or natural gas we produce or by reducing our exposure to foreign currency or interest rate movements. Generally, futures, swaps or option strategies may be used to fix the forward selling price, ofor establish a floor price or a range banded with a floor and ceiling price, for a portion of our crude oil or natural gas production. Forward contracts may also be used to purchase certain currencies in which we conduct business with the intent of reducing exposure to foreign currency fluctuations. At December 31, 2018,2021, these forward contracts relate to the British Pound.Pound, Canadian Dollar and Malaysian Ringgit. Interest rate swaps may be used to convert interest payments on certain long-term debt from fixed to floating rates.Gross notional amounts of both long and short positions are presented in the volume tables beginning below. These amounts include long and short positions that offset in closed positions and have not reached contractual maturity. Gross notional amounts do not quantify risk or represent assets or liabilities of the Corporation, but are used in the calculation of cash settlements under the contracts.
79
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The gross notional amounts of outstanding financial risk management derivative contracts related to WTI instruments as of the dates shown below were as follows:
| | December 31, 2018 | | | December 31, 2017 | |
Calendar year program | | 2019 | | | 2018 | |
Instrument type | | Puts | | | Collars | |
Crude oil volumes (millions of barrels) | | | 34.7 | | | | 42.0 | |
Ceiling price | | N/A | | | $ | 65 | |
Floor price | | $ | 60 | | | $ | 50 | |
| | | | | | | | | | | |
| | December 31, 2021 | | December 31, 2020 |
| | | |
| | (In millions) |
| Commodity - crude oil hedge contracts (millions of barrels) | 54.8 | | | 27.4 | |
| Foreign exchange forwards | $ | 145 | | | $ | 163 | |
| Interest rate swaps | $ | 100 | | | $ | 100 | |
At December 31, 2017, we had WTI crude oil price collars for
For calendar year 20182022, we have hedged 90,000 bopd with a monthly floor price of $50 per barrel and a monthly ceiling price of $65 per barrel for 115,000 bopd. In the first quarter of 2018, we bought back the WTI $65 call options within the crude oil price collars for the period of May 1, 2018 through December 31, 2018. In 2018, we purchased WTI put options for calendar year 2019 with a WTIan average monthly floor price of $60 per barrel for 95,000 bopd.The gross notional amountsand an average monthly ceiling price of outstanding financial risk management derivative contracts, excluding commodity contracts, were as follows:
$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. | | December 31, 2018 | | | December 31, 2017 | |
| | (In millions) | |
Foreign exchange | | $ | 16 | | | $ | 52 | |
Interest rate swaps | | $ | 100 | | | $ | 450 | |
The table below reflects the gross and net fair values of risk management derivative instrumentsinstruments:
| | | | | | | | | | | |
| | Assets | | Liabilities |
| | | |
| | (In millions) |
| December 31, 2021 | | | |
| Derivative Contracts Designated as Hedging Instruments: | | | |
| Crude oil collars | $ | 155 | | | $ | — | |
| Interest rate swaps | 2 | | | — | |
| Total derivative contracts designated as hedging instruments | 157 | | | — | |
| Derivative Contracts Not Designated as Hedging Instruments: | | | |
| Foreign exchange forwards | — | | | (1) | |
| Total derivative contracts not designated as hedging instruments | — | | | (1) | |
| Gross fair value of derivative contracts | 157 | | | (1) | |
| Gross amount offset in the Consolidated Balance Sheet | — | | | — | |
| Net Amounts Presented in the Consolidated Balance Sheet | $ | 157 | | | $ | (1) | |
| | | |
| December 31, 2020 | | | |
| Derivative Contracts Designated as Hedging Instruments: | | | |
| Crude oil put options | $ | 64 | | | $ | — | |
| Crude oil swaps | — | | | (54) | |
| Interest rate swaps | 5 | | | — | |
| Total derivative contracts designated as hedging instruments | 69 | | | (54) | |
| Derivative Contracts Not Designated as Hedging Instruments: | | | |
| Foreign exchange forwards | — | | | (1) | |
| Total derivative contracts not designated as hedging instruments | — | | | (1) | |
| Gross fair value of derivative contracts | 69 | | | (55) | |
| Gross amount offset in the Consolidated Balance Sheet | (13) | | | 13 | |
| Net Amounts Presented in the Consolidated Balance Sheet | $ | 56 | | | $ | (42) | |
At December 31, 2021, the fair value of our crude oil collars is presented within Other current assets in our Consolidated Balance Sheet. At December 31, 2020, the fair value of our crude oil put options and their respective financial statement captioncrude oil swaps is presented within Other current assets and Accrued liabilities, respectively, in our Consolidated Balance Sheet. The fair value of our interest rate swaps is presented within Other assets in our Consolidated Balance Sheet. The fair value of our foreign exchange forwards is presented within Accrued liabilities in our Consolidated Balance Sheet. All fair values in the Consolidated Balance Sheet: | | Assets | | | Liabilities | |
| | (In millions) | |
December 31, 2018 | | | | | | | | |
Derivative Contracts Designated as Hedging Instruments | | | | | | | | |
Commodity - Other current assets | | $ | 484 | | | $ | — | |
Interest rate - Other liabilities and deferred credits (noncurrent) | | | — | | | | (2 | ) |
Total derivative contracts designated as hedging instruments | | | 484 | | | | (2 | ) |
Gross fair value of derivative contracts | | | 484 | | | | (2 | ) |
Master netting arrangements | | | — | | | | — | |
Net Fair Value of Derivative Contracts | | $ | 484 | | | $ | (2 | ) |
| | | | | | | | |
December 31, 2017 | | | | | | | | |
Derivative Contracts Designated as Hedging Instruments | | | | | | | | |
Commodity - Accounts payable | | $ | — | | | $ | (7 | ) |
Interest rate - Other assets (noncurrent) and Accounts payable | | | — | | | | (4 | ) |
Total derivative contracts designated as hedging instruments | | | — | | | | (11 | ) |
Derivative Contracts Not Designated as Hedging Instruments | | | | | | | | |
Commodity - Accounts payable | | | — | | | | (2 | ) |
Foreign exchange - Accounts receivable: Joint venture and other | | | 1 | | | | — | |
Total derivative contracts not designated as hedging instruments | | | 1 | | | | (2 | ) |
Gross fair value of derivative contracts | | | 1 | | | | (13 | ) |
Master netting arrangements | | | — | | | | — | |
Net Fair Value of Derivative Contracts | | $ | 1 | | | $ | (13 | ) |
All fair valuestable above are based on Level 2 inputs.
Impact on statement of consolidated income from derivative
Derivative contracts designated as hedging instruments:
Crude oil derivatives:hedge contracts: In 2018, crude2021, crude oil price hedging contractsdecreased Sales and other operating revenues by $161$243 million (2017: decrease(2020: increase of $34$547 million; 2016: $0)2019: increase of $1 million). At December 31, 2018,2021, pre-tax deferred gainslosses in Accumulated othercomprehensive income (loss) related to outstanding crude oil price hedging contracts were $365$68 million ($68 million after income taxes), all of which all will be reclassified into earnings during the next 12 months as the hedged crude oil sales are recognized in earnings.80
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Interest rate swaps designated as fair value hedges:At December 31, 2018,2021, we had interest rate swaps with gross notional amounts of $100 million (2017: $450(2020: $100 million),which were designated as fair value hedges and relate to long-term debt where we have converted interest payments on certain long-term debt from fixed to floating rates. During 2018, we terminated interest rate swaps with a gross notional amount of $350 million and paid $3 million (2017: $0; 2016: $5 million proceeds). See Note 8, Debt.rates. Changes in the fair value of interest rate swaps and the hedged fixed‑rate debt are recorded inInterest expensein theStatement of Consolidated Income. In 2018,2021, the change in fair value of interest rate swaps was an increase in the derivative liabilitya decrease of $1$3 million (2017:(2020: $4 million increase in liability; 2016: $6increase; 2019: $3 million increase in asset) increase)with a corresponding adjustment in the carrying value of the hedged fixed‑rate debt.Interest rate swaps designated as cash flow hedges: During 2017, HIP entered into interest rate swaps with gross notional amounts totaling $553 million to convert interest payments on certain long-term debt from floating to fixed rates before settling these instruments for a payment of $3 million as part of the refinancing that occurred later in the year. See Note 8, Debt.
Impact on statement of consolidated income from derivative
Derivative contracts not designated as hedging instruments:
Crude oil collars: In 2018, noncash adjustments to de-designated crude oil price hedging contracts decreased Sales and other operating revenues by $22 million (2017: decrease of $25 million).
Foreign exchange: Total foreign exchange gains and losses were alosses of $2 million in 2021 (2020: loss of $5 million in 2018 (2017:$6 million; 2019: gain of $15 million; 2016: gain of $26$3 million) and are reported inOther, netin Revenues and non-operating income in theStatement of Consolidated Income. A component of foreign exchange gains or losses is the result of foreign exchange derivative contracts that are not designated as hedges, which amounted to a net gain of $1 million in 2021 (2020: net gain of $2 million; 2019: net loss of $2 million in 2018 (2017: gain of $3 million; 2016: gain of $62 million).After‑tax foreign currency translation adjustments included in the Statement of Consolidated Comprehensive Income amounted to gains of $144 million in 2017 and $56 million in 2016. In 2017, $900 million of cumulative currency translation losses were recognized in earnings as a result of the sale of our assets in Norway. See Note 3, Dispositions.
Credit Risk: We are exposed to credit risks that may at times be concentrated with certain counterparties, groups of counterparties or customers. Accounts receivable are generated from a diverse domestic and international customer base. At December 31, 2018,2021, our Accounts receivable were concentrated with the following counterparty industry segments: Financial Institutions — 34%, Integrated companies — 24%50%, Independent E&P companies — 22%31%, Refining and marketing companies — 9%, National oil companies — 7% Refining and marketing companies — 5%3%,
Storage and transportation companies — 3%, and Others —
5%4%. We reduce risk related to certain counterparties, where applicable, by using master netting arrangements and requiring collateral, generally cash or letters of credit.
At December 31,
2018,2021, we had outstanding letters of credit totaling
$284$259 million
(2017: $246(2020: $269 million).
Fair Value Measurement: At December 31, 2018, outstanding2021, our total long-term debt, excluding capital leases,which was substantially comprised of fixed rate debt instruments, withhad a carrying value of $6,403$8,458 million and a fair value of $6,225$9,897 million, based on Level 2 inputs in the fair value measurement hierarchy. We also have short-term financial instruments, primarily cash equivalents, accounts receivable and accounts payable, for which the carrying value approximated fair value at December 31, 20182021 and December 31, 2017.22.2020.
21. Subsequent
EventOn January 31, 2019,Events
Following the 8.00% Series A Mandatory Convertible Preferred Stock (Preferred Stock) automatically converted into shares of common stock at a rate of 21.822 shares of common stock per share of Preferred Stock. In total, the Preferred Stock was converted into approximately 12.5 million shares of common stock. In connection with the Preferred Stock offering in 2016, the Company entered into capped call transactions to reduce the potential dilution to the Company’s common stock upon conversionstartup of the Preferred Stock, subjectLiza Phase 2 project in February 2022, we repaid the remaining $500 million outstanding under our $1 billion term loan and we announced a 50 percent increase in our quarterly dividend on common stock.In January 2022, we paid accrued Libyan income tax and royalties of approximately $470 million related to a cap. The Company received approximately 0.9 million shares of common stock upon settlement ofoperations for the capped call transactions. As a result, the net number of common shares issued by the Company upon conversion of the Preferred Stock was approximately 11.6 million shares.period December 2020 through November 2021.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED)
The Supplementary Oil and Gas Data that follows is presented in accordance with ASC 932, Disclosures about Oil and Gas Producing Activities, and includes (1) costs incurred, capitalized costs and results of operations relating to oil and gas producing activities, (2) net proved oil and gas reserves and (3) a standardized measure of discounted future net cash flows relating to proved oil and gas reserves, including a reconciliation of changes therein.During the three-year period ended December 31, 2018, we produced crude oil, NGLs and natural gas principally in the United States (U.S.), Europe (Norway until December 2017 and Denmark), Africa (Equatorial Guinea until November 2017 and Libya) and Asia and Other (the Malaysia/Thailand Joint Development Area (JDA), and Malaysia). Exploration activities were also conducted, or are planned, in certain of these areas as well as additional countries. See Note 3, Dispositions in the Notes to Consolidated Financial Statements.
Costs Incurred in Oil and Gas Producing Activities
For the Years Ended December 31 | | Total | | | United States | | | Europe (b) | | | Africa | | | Asia and Other | |
| | (In millions) | |
2018 | | | | | | | | | | | | | | | | | | | | |
Property acquisitions | | | | | | | | | | | | | | | | | | | | |
Unproved | | $ | 51 | | | $ | 43 | | | $ | — | | | $ | — | | | $ | 8 | |
Proved | | | 43 | | | | 43 | | | | — | | | | — | | | | — | |
Exploration | | | 442 | | | | 111 | | | | — | | | | — | | | | 331 | |
Production and development capital expenditures (a) | | | 1,577 | | | | 1,239 | | | | (7 | ) | | | 9 | | | | 336 | |
2017 | | | | | | | | | | | | | | | | | | | | |
Property acquisitions | | | | | | | | | | | | | | | | | | | | |
Unproved | | $ | 46 | | | $ | 46 | | | $ | — | | | $ | — | | | $ | — | |
Proved | | | — | | | | — | | | | — | | | | — | | | | — | |
Exploration | | | 322 | | | | 94 | | | | 1 | | | | — | | | | 227 | |
Production and development capital expenditures (a) | | | 1,687 | | | | 1,160 | | | | 146 | | | | 40 | | | | 341 | |
2016 | | | | | | | | | | | | | | | | | | | | |
Property acquisitions | | | | | | | | | | | | | | | | | | | | |
Unproved | | $ | 11 | | | $ | 11 | | | $ | — | | | $ | — | | | $ | — | |
Proved | | | — | | | | — | | | | — | | | | — | | | | — | |
Exploration | | | 491 | | | | 211 | | | | 6 | | | | (2 | ) | | | 276 | |
Production and development capital expenditures (a) | | | 1,181 | | | | 999 | | | | (64 | ) | | | (58 | ) | | | 304 | |
(a)
| Includes an increase of $44 million for asset retirement obligations related to net accruals and revisions in 2018 (2017: $8 million increase; 2016: $188 million decrease).
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31 | | Total | | United
States | | Guyana | | Malaysia and JDA | | Other (a) |
| | | | | | | | | | |
| | | (In millions) |
| 2021 | | | | | | | | | | |
| Property acquisitions | | | | | | | | | | |
| Unproved | | $ | 24 | | | $ | 4 | | | $ | 20 | | | $ | — | | | $ | — | |
| Proved | | — | | | — | | | — | | | — | | | — | |
| Exploration | | 368 | | | 92 | | | 250 | | | 7 | | | 19 | |
| Production and development capital expenditures (b) (c) | | 1,645 | | | 653 | | | 820 | | | 157 | | | 15 | |
| 2020 | | | | | | | | | | |
| Property acquisitions | | | | | | | | | | |
| Unproved | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Proved | | — | | | — | | | — | | | — | | | — | |
| Exploration | | 307 | | | 169 | | | 130 | | | 2 | | | 6 | |
| Production and development capital expenditures (b) | | 1,567 | | | 804 | | | 630 | | | 106 | | | 27 | |
| 2019 | | | | | | | | | | |
| Property acquisitions | | | | | | | | | | |
| Unproved | | $ | 26 | | | $ | 26 | | | $ | — | | | $ | — | | | $ | — | |
| Proved | | — | | | — | | | — | | | — | | | — | |
| Exploration | | 455 | | | 174 | | | 239 | | | 4 | | | 38 | |
| Production and development capital expenditures (b) | | 2,463 | | | 1,735 | | | 585 | | | 114 | | | 29 | |
(b)
| Costs incurred in oil and gas producing activities in Norway, including net accruals and revisions for asset retirement obligations, amounted to a net credit of $19 million for the year ended December 31, 2016.
|
(a)Other includes our interests in Denmark (sold in August 2021), Libya, Suriname and Canada.(b)Includes an increase of $208 million for net accruals and revisions of asset retirement obligations in 2021 (2020: $88 million increase; 2019: $201 million increase).
(c)Net accruals for asset retirement obligations in the United States exclude a charge of $147 million related to our former interests in the West Delta Field in the Gulf of Mexico which we sold to a Fieldwood predecessor in 2004. See Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements.
Capitalized Costs Relating to Oil and Gas Producing Activities
| | | | | At December 31, |
| | At December 31, | | | 2021 | | 2020 |
| | 2018 | | | 2017 | | | | | |
| | (In millions) | | | (In millions) |
Unproved properties | | $ | 394 | | | $ | 520 | | Unproved properties | $ | 184 | | | $ | 164 | |
Proved properties | | | 3,124 | | | | 3,162 | | Proved properties | 2,877 | | | 2,930 | |
Wells, equipment and related facilities | | | 26,173 | | | | 25,550 | | Wells, equipment and related facilities | 23,745 | | | 23,224 | |
Total costs | | | 29,691 | | | | 29,232 | | Total costs | 26,806 | | | 26,318 | |
Less: Reserve for depreciation, depletion, amortization and lease impairment | | | 16,361 | | | | 15,654 | | Less: Reserve for depreciation, depletion, amortization and lease impairment | 15,759 | | | 15,325 | |
Net Capitalized Costs | | $ | 13,330 | | | $ | 13,578 | | Net Capitalized Costs | $ | 11,047 | | | $ | 10,993 | |
Results of Operations for Oil and Gas Producing Activities
The results of operations shown below exclude non‑oil and gas producing activities, primarily gains (losses) on sales of oil and gas properties, sales of purchased crude oil, NGLsNGL and natural gas from third parties, interest expense and non-operating income. Sales and other operating revenues include crude oil hedging results and are net of payments for unutilized committed transportation capacity. Therefore, these results are on a different basis than the net income (loss) from E&P operations reported in Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 20,19, Segment Information in the Notes to Consolidated Financial Statements.For the Years Ended December 31 | | Total | | | United States | | | Europe (b) | | | Africa | | | Asia and Other | |
| | (In millions) | |
2018 | | | | | | | | | | | | | | | | | | | | |
Sales and Other Operating Revenues | | $ | 4,515 | | | $ | 3,141 | | | $ | 164 | | | $ | 455 | | | $ | 755 | |
Costs and Expenses | | | | | | | | | | | | | | | | | | | | |
Operating costs and expenses | | | 941 | | | | 697 | | | | 71 | | | | 32 | | | | 141 | |
Production and severance taxes | | | 171 | | | | 165 | | | | — | | | | — | | | | 6 | |
Midstream tariffs | | | 648 | | | | 648 | | | | — | | | | — | | | | — | |
Exploration expenses, including dry holes and lease impairment | | | 362 | | | | 119 | | | | — | | | | 1 | | | | 242 | |
General and administrative expenses | | | 258 | | | | 230 | | | | 22 | | | | — | | | | 6 | |
Depreciation, depletion and amortization | | | 1,748 | | | | 1,297 | | | | 37 | | | | 19 | | | | 395 | |
Total Costs and Expenses | | | 4,128 | | | | 3,156 | | | | 130 | | | | 52 | | | | 790 | |
Results of Operations Before Income Taxes | | | 387 | | | | (15 | ) | | | 34 | | | | 403 | | | | (35 | ) |
Provision (benefit) for income taxes | | | 337 | | | | (63 | ) | | | 14 | | | | 376 | | | | 10 | |
Results of Operations | | $ | 50 | | | $ | 48 | | | $ | 20 | | | $ | 27 | | | $ | (45 | ) |
| | | | | | | | | | | | | | | | | | | | |
2017 | | | | | | | | | | | | | | | | | | | | |
Sales and Other Operating Revenues | | $ | 4,128 | | | $ | 2,335 | | | $ | 628 | | | $ | 700 | | | $ | 465 | |
Costs and Expenses | | | | | | | | | | | | | | | | | | | | |
Operating costs and expenses | | | 1,250 | | | | 652 | | | | 275 | | | | 186 | | | | 137 | |
Production and severance taxes | | | 119 | | | | 116 | | | | — | | | | 1 | | | | 2 | |
Midstream tariffs | | | 543 | | | | 543 | | | | — | | | | — | | | | — | |
Exploration expenses, including dry holes and lease impairment | | | 507 | | | | 106 | | | | 1 | | | | 280 | | | | 120 | |
General and administrative expenses | | | 225 | | | | 208 | | | | 10 | | | | 4 | | | | 3 | |
Depreciation, depletion and amortization | | | 2,736 | | | | 1,819 | | | | 381 | | | | 263 | | | | 273 | |
Impairment | | | 4,203 | | | | 1,700 | | | | 2,503 | | | | — | | | | — | |
Total Costs and Expenses | | | 9,583 | | | | 5,144 | | | | 3,170 | | | | 734 | | | | 535 | |
Results of Operations Before Income Taxes | | | (5,455 | ) | | | (2,809 | ) | | | (2,542 | ) | | | (34 | ) | | | (70 | ) |
Provision (benefit) for income taxes | | | (1,873 | ) | | | (47 | ) | | | (2,014 | ) | | | 197 | | | | (9 | ) |
Results of Operations | | $ | (3,582 | ) | | $ | (2,762 | ) | | $ | (528 | ) | | $ | (231 | ) | | $ | (61 | ) |
| | | | | | | | | | | | | | | | | | | | |
2016 | | | | | | | | | | | | | | | | | | | | |
Sales and Other Operating Revenues | | $ | 3,628 | | | $ | 2,056 | | | $ | 597 | | | $ | 519 | | | $ | 456 | |
Costs and Expenses | | | | | | | | | | | | | | | | | | | | |
Operating costs and expenses | | | 1,662 | | | | 920 | | | | 321 | | | | 249 | | | | 172 | |
Production and severance taxes | | | 101 | | | | 94 | | | | 1 | | | | — | | | | 6 | |
Midstream tariffs | | | 497 | | | | 497 | | | | — | | | | — | | | | — | |
Exploration expenses, including dry holes and lease impairment | | | 1,442 | | | | 342 | | | | 6 | | | | — | | | | 1,094 | |
General and administrative expenses | | | 232 | | | | 215 | | | | 1 | | | | 7 | | | | 9 | |
Depreciation, depletion and amortization | | | 3,113 | | | | 2,012 | | | | 502 | | | | 375 | | | | 224 | |
Total Costs and Expenses | | | 7,047 | | | | 4,080 | | | | 831 | | | | 631 | | | | 1,505 | |
Results of Operations Before Income Taxes | | | (3,419 | ) | | | (2,024 | ) | | | (234 | ) | | | (112 | ) | | | (1,049 | ) |
Provision (benefit) for income taxes (a) | | | 1,549 | | | | 379 | | | | 208 | | | | 244 | | | | 718 | |
Results of Operations | | $ | (4,968 | ) | | $ | (2,403 | ) | | $ | (442 | ) | | $ | (356 | ) | | $ | (1,767 | ) |
Other includes results for Denmark (sold in August 2021), Libya, Suriname and Canada.
(a)
| Includes charges to establish valuation allowances against net deferred tax assets amounting to $2,920 million. The charge is attributed to the geographic region in which the operations occurred that gave rise to the net deferred tax asset (United States - $1,144 million, Europe - $486 million, Africa - $249 million and Asia & Other - $1,041 million).
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31 | | Total | | United
States | | Guyana (a) | | Malaysia and JDA | | Other |
| | | | | | | | | | |
| | | (In millions) |
| 2021 | | | | | | | | | | |
| Sales and Other Operating Revenues | | $ | 5,621 | | | $ | 3,638 | | | $ | 738 | | | $ | 738 | | | $ | 507 | |
| Costs and Expenses | | | | | | | | | | |
| Operating costs and expenses (b) | | 1,073 | | | 718 | | | 196 | | | 106 | | | 53 | |
| Production and severance taxes | | 172 | | | 166 | | | — | | | 6 | | | — | |
| Midstream tariffs | | 1,094 | | | 1,094 | | | — | | | — | | | — | |
| Exploration expenses, including dry holes and lease impairment | | 162 | | | 102 | | | 35 | | | 7 | | | 18 | |
| General and administrative expenses | | 191 | | | 162 | | | 12 | | | 11 | | | 6 | |
| Depreciation, depletion and amortization (b) | | 1,426 | | | 1,085 | | | 109 | | | 205 | | | 27 | |
| Impairment and other | | 147 | | | 147 | | | — | | | — | | | — | |
| Total Costs and Expenses | | 4,265 | | | 3,474 | | | 352 | | | 335 | | | 104 | |
| Results of Operations Before Income Taxes | | 1,356 | | | 164 | | | 386 | | | 403 | | | 403 | |
| Provision (benefit) for income taxes | | 534 | | | — | | | 119 | | | 31 | | | 384 | |
| Results of Operations | | $ | 822 | | | $ | 164 | | | $ | 267 | | | $ | 372 | | | $ | 19 | |
| | | | | | | | | | |
| 2020 | | | | | | | | | | |
| Sales and Other Operating Revenues | | $ | 3,794 | | | $ | 2,747 | | | $ | 345 | | | $ | 511 | | | $ | 191 | |
| Costs and Expenses | | | | | | | | | | |
| Operating costs and expenses | | 895 | | | 564 | | | 136 | | | 109 | | | 86 | |
| Production and severance taxes | | 124 | | | 118 | | | — | | | 6 | | | — | |
| Midstream tariffs | | 946 | | | 946 | | | — | | | — | | | — | |
| Exploration expenses, including dry holes and lease impairment | | 351 | | | 284 | | | 25 | | | — | | | 42 | |
| General and administrative expenses | | 206 | | | 176 | | | 9 | | | 12 | | | 9 | |
| Depreciation, depletion and amortization | | 1,915 | | | 1,480 | | | 130 | | | 268 | | | 37 | |
| Impairment and other | | 2,126 | | | 697 | | | — | | | 755 | | | 674 | |
| Total Costs and Expenses | | 6,563 | | | 4,265 | | | 300 | | | 1,150 | | | 848 | |
| Results of Operations Before Income Taxes | | (2,769) | | | (1,518) | | | 45 | | | (639) | | | (657) | |
| Provision (benefit) for income taxes | | (4) | | | — | | | 9 | | | 22 | | | (35) | |
| Results of Operations | | $ | (2,765) | | | $ | (1,518) | | | $ | 36 | | | $ | (661) | | | $ | (622) | |
| | | | | | | | | | |
| 2019 | | | | | | | | | | |
| Sales and Other Operating Revenues | | $ | 4,719 | | | $ | 3,361 | | | $ | — | | | $ | 759 | | | $ | 599 | |
| Costs and Expenses | | | | | | | | | | |
| Operating costs and expenses | | 971 | | | 693 | | | 47 | | | 139 | | | 92 | |
| Production and severance taxes | | 184 | | | 176 | | | — | | | 8 | | | — | |
| Midstream tariffs | | 722 | | | 722 | | | — | | | — | | | — | |
| Exploration expenses, including dry holes and lease impairment | | 233 | | | 144 | | | 47 | | | 3 | | | 39 | |
| General and administrative expenses | | 204 | | | 176 | | | 7 | | | 12 | | | 9 | |
| Depreciation, depletion and amortization | | 1,977 | | | 1,489 | | | 1 | | | 413 | | | 74 | |
| Total Costs and Expenses | | 4,291 | | | 3,400 | | | 102 | | | 575 | | | 214 | |
| Results of Operations Before Income Taxes | | 428 | | | (39) | | | (102) | | | 184 | | | 385 | |
| Provision (benefit) for income taxes | | 325 | | | — | | | (60) | | | 13 | | | 372 | |
| Results of Operations | | $ | 103 | | | $ | (39) | | | $ | (42) | | | $ | 171 | | | $ | 13 | |
(b)
| Results of operations for oil and gas producing activities in Norway for the year ended December 31, 2016 (in millions) were as follows:
|
(a)Production from Liza Phase 1 commenced in December 2019. Operating costs and expenses also include pre-development costs from the operator for future phases of development and Hess internal costs.Sales and Other Operating Revenues | | $ | 419 | |
Costs and Expenses | | | | |
Operating costs and expenses | | | 252 | |
Production and severance taxes | | | — | |
General and administrative expenses | | | 6 | |
Depreciation, depletion and amortization | | | 362 | |
Total Costs and Expenses | | | 620 | |
Results of Operations Before Income Taxes | | | (201 | ) |
Provision (benefit) for income taxes | | | (157 | ) |
Results of Operations | | $ | (44 | ) |
Proved Oil and Gas Reserves
Our proved oil and gas reserves are calculated in accordance with the Securities and Exchange Commission (SEC) regulations and the requirements of the Financial Accounting Standards Board. Proved oil and gas reserves are quantities, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. Our estimation of net recoverable quantities of liquid hydrocarbons and natural gas is a highly technical process performed by our internal teams of geoscience and reservoir engineering professionals. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)June 25, 2019).” The method or combination of methods used in the analysis of each reservoir is based on the maturity of the reservoir, the completeness of the subsurface data available at the time of the estimate, the stage of reservoir development and the production history. Subsurface data used included well logs, reservoir core and fluid samples, production and pressure testing, static and dynamic pressure information, and reservoir surveillance. Where applicable, reliable technologies may be used in reserve estimation, as defined in the SEC regulations. These technologies, including computational methods, must have been field tested and demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In some cases, where appropriate, use of empirical and analytical methods, combined with analog data were used. Analytic tools, including reservoir simulation, geologic modeling and seismic processing, have been used in the interpretation of the subsurface data. These technologies were used to increase the quality and confidence in the reserves estimates.
In order for reserves to be classified as proved, any required government approvals must be obtained and depending on the cost of the project, either senior management or the Board of Directors must commit to fund the development. Our proved reserves are subject to certain risks and uncertainties, which are discussed in Item 1A. Risk Factorsof this Form 10‑K. 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. The impact of these targets on our production operations was reflected in the determination of proved reserves at December 31, 2021.
The Corporation maintains internal controls over its oil and gas reserve estimation processes, which are administered by our Global Reserves group and our Chief Financial Officer. Estimates of reserves are prepared by technical staff who work directly with the oil and gas properties using industry standard reserve estimation principles, definitions and methodologies. Each year, reserve estimates of the Corporation’s assets are subject to internal technical audits and reviews. In addition, an independent third-party reserve engineer reviews and audits a significant portion of the Corporation’s reported reserves (see pages
8591 through
90)96). Reserve estimates are reviewed by senior management and the Board of Directors.
The person primarily responsible for overseeing the preparation of the Corporation’s oil and gas reserves during
20182021 was
Mr. Kenneth Kosco,the Senior Manager, Global Reserves.
Mr. KoscoHe is a member of the Society of Petroleum Engineers and has
3019 years of experience in the oil and gas industry with a
BSMSc degree in Petroleum Engineering. His experience has been primarily focused on oil and gas subsurface understanding and reserves estimation in both domestic and international areas.
Mr. KoscoHe is
also responsible for the Corporation’s Global Reserves group, which is the internal organization
responsible for establishingthat establishes the policies and processes used within the operating units to estimate reserves and perform internal technical reserve audits and reviews.
We engaged the consulting firm of DeGolyer and MacNaughton (D&M) to perform an audit of the internally prepared reserve estimates on certain fields aggregating
80%approximately 88% of
20182021 year‑end reported reserve quantities on a barrel of oil equivalent basis
(2017: 80%(2020: 92%). The purpose of this audit was to provide additional assurance on the reasonableness of internally prepared reserve estimates and compliance with SEC regulations. The D&M
letter report, dated February
6, 2019,2, 2022, on the Corporation’s estimated oil and gas reserves was prepared using standard geological and engineering methods generally recognized in the petroleum industry. D&M is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years. D&M’s letter report on the Corporation’s December 31,
20182021 oil
and gas reserves is included as an exhibit to this Form 10‑K. While the D&M report should be read in its entirety, the report concludes that for the properties reviewed by D&M, the total net proved reserve estimates prepared by Hess and auditedindependently evaluated by D&M, in the aggregate, differed by less than 2.5% (2020: less than 1% (2017: 4%) of total audited net proved reserves on a barrel of oil equivalent basis. The report also includes among other information, the qualifications of the technical person primarily responsible for overseeing the reserve audit.
Crude Oil Prices Used to Estimate Proved Reserves
Proved reserves are calculated using the average price during the twelve-month period before December 31 determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices are defined by contractual agreements, excluding escalations based on future conditions. Crude oil prices used in the determination of proved reserves at December 31,
20182021 were
$65.55$66.34 per barrel for WTI
(2017: $51.19; 2016: $42.68)(2020: $39.77; 2019: $55.73) and
$72.08$68.92 per barrel for Brent
(2017: $54.87; 2016: $44.45)(2020: $43.43; 2019: $62.54). New York Mercantile Exchange (NYMEX) natural gas prices used were
$3.01$3.68 per mcf in
2018 (2017: $3.03; 2016:2021 (2020: $2.16; 2019: $2.54).
At December 31, 2018,2021, spot prices closed at $75.21 per barrel for WTI oil closed at $45.41and $77.02 per barrel. Ifbarrel for Brent. If crude oil prices during 2019 averagein 2022 are at levels below thosethat used in determining 20182021 proved reserves, we may recognize negative revisions to our proved reserves at December 31, 2019,2022 proved undeveloped reserves. In addition, we may recognize negative revisions to proved developed reserves, which can vary significantly by asset due to differing operating cost structures. Conversely, if crude oil pricesprice increases in 2019 remain2022 above those used in determining 20182021 proved reserves we could recognizeresult in positive revisions to our proved developed and proved undeveloped reserves at December 31, 2019.2022. It is difficult to estimate the magnitude of any potential net negative or positive change in proved reserves at December 31, 2019,2022, due to a number of factors that arenumerous currently unknown factors, including 20192022 crude oil prices, the amount of any additions to proved reserves, positive or negative revisions based on 2019in proved reserves related to 2022 reservoir performance, and the levels to which industry costs will change in response to movements in commodity prices.
Following are the Corporation’s proved reserves:
| | Crude Oil & Condensate | | | Natural Gas Liquids | |
| | United States | | | Europe (b) | | | Africa | | | Asia & Other | | | Total | | | United States | | | Europe (b) | | | Asia & Other | | | Total | |
| | (Millions of bbls) | | | (Millions of bbls) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net Proved Reserves | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
At January 1, 2016 | | | 346 | | | | 203 | | | | 172 | | | | 5 | | | | 726 | | | | 74 | | | | 27 | | | | — | | | | 101 | |
Revisions of previous estimates (a) | | | 42 | | | | (14 | ) | | | 2 | | | | 1 | | | | 31 | | | | 23 | | | | (19 | ) | | | — | | | | 4 | |
Extensions, discoveries and other additions | | | 12 | | | | 33 | | | | — | | | | — | | | | 45 | | | | 5 | | | | — | | | | — | | | | 5 | |
Sales of minerals in place | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
Production | | | (45 | ) | | | (12 | ) | | | (12 | ) | | | (1 | ) | | | (70 | ) | | | (16 | ) | | | — | | | | — | | | | (16 | ) |
At December 31, 2016 | | | 355 | | | | 210 | | | | 162 | | | | 5 | | | | 732 | | | | 86 | | | | 8 | | | | — | | | | 94 | |
Revisions of previous estimates (a) | | | 13 | | | | 5 | | | | (6 | ) | | | — | | | | 12 | | | | 56 | | | | — | | | | — | | | | 56 | |
Extensions, discoveries and other additions | | | 127 | | | | 2 | | | | — | | | | 45 | | | | 174 | | | | 50 | | | | — | | | | — | | | | 50 | |
Sales of minerals in place | | | (21 | ) | | | (158 | ) | | | (15 | ) | | | — | | | | (194 | ) | | | (6 | ) | | | (8 | ) | | | — | | | | (14 | ) |
Production | | | (41 | ) | | | (10 | ) | | | (13 | ) | | | (1 | ) | | | (65 | ) | | | (15 | ) | | | — | | | | — | | | | (15 | ) |
At December 31, 2017 | | | 433 | | | | 49 | | | | 128 | | | | 49 | | | | 659 | | | | 171 | | | | — | | | | — | | | | 171 | |
Revisions of previous estimates (a) | | | (3 | ) | | | (10 | ) | | | (2 | ) | | | (2 | ) | | | (17 | ) | | | (14 | ) | | | — | | | | — | | | | (14 | ) |
Extensions, discoveries and other additions | | | 114 | | | | 2 | | | | 7 | | | | 2 | | | | 125 | | | | 39 | | | | — | | | | — | | | | 39 | |
Purchase of minerals in place | | | 3 | | | | — | | | | — | | | | — | | | | 3 | | | | 1 | | | | — | | | | — | | | | 1 | |
Sales of minerals in place | | | (3 | ) | | | — | | | | — | | | | — | | | | (3 | ) | | | (8 | ) | | | — | | | | — | | | | (8 | ) |
Production | | | (43 | ) | | | (2 | ) | | | (7 | ) | | | (1 | ) | | | (53 | ) | | | (14 | ) | | | — | | | | — | | | | (14 | ) |
At December 31, 2018 | | | 501 | | | | 39 | | | | 126 | | | | 48 | | | | 714 | | | | 175 | | | | — | | | | — | | | | 175 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net Proved Developed Reserves | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
At January 1, 2016 | | | 253 | | | | 114 | | | | 148 | | | | 5 | | | | 520 | | | | 51 | | | | 12 | | | | — | | | | 63 | |
At December 31, 2016 | | | 245 | | | | 116 | | | | 138 | | | | 5 | | | | 504 | | | | 59 | | | | 3 | | | | — | | | | 62 | |
At December 31, 2017 | | | 239 | | | | 45 | | | | 112 | | | | 5 | | | | 401 | | | | 87 | | | | — | | | | — | | | | 87 | |
At December 31, 2018 | | | 266 | | | | 38 | | | | 111 | | | | 4 | | | | 419 | | | | 85 | | | | — | | | | — | | | | 85 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net Proved Undeveloped Reserves | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
At January 1, 2016 | | | 93 | | | | 89 | | | | 24 | | | | — | | | | 206 | | | | 23 | | | | 15 | | | | — | | | | 38 | |
At December 31, 2016 | | | 110 | | | | 94 | | | | 24 | | | | — | | | | 228 | | | | 27 | | | | 5 | | | | — | | | | 32 | |
At December 31, 2017 | | | 194 | | | | 4 | | | | 16 | | | | 44 | | | | 258 | | | | 84 | | | | — | | | | — | | | | 84 | |
At December 31, 2018 | | | 235 | | | | 1 | | | | 15 | | | | 44 | | | | 295 | | | | 90 | | | | — | | | | — | | | | 90 | |
| (a)
| Revisions resulting from the impact of price changes in production sharing contracts reduced proved crude oil and condensate reserves in 2018 by 3 million, primarily in Guyana. (2017: 0 million barrels; 2016: 1 million barrels increase).
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Crude Oil & Condensate | | Natural Gas Liquids |
| | United
States | | Guyana | | Malaysia and
JDA | | Other (a) | | Total | | United
States | | Total |
| | | | | | | | | | | | | |
| | (Millions of bbls) | | (Millions of bbls) |
| Net Proved Reserves | | | | | | | | | | | | | |
| At January 1, 2019 | 501 | | 40 | | 8 | | 165 | | 714 | | 175 | | 175 |
| Revisions of previous estimates | (54) | | 13 | | — | | (6) | | (47) | | (29) | | (29) |
| Extensions, discoveries and other additions | 112 | | 33 | | 1 | | 11 | | 157 | | 40 | | 40 |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Production | (51) | | — | | (2) | | (9) | | (62) | | (17) | | (17) |
| At December 31, 2019 | 508 | | 86 | | 7 | | 161 | | 762 | | 169 | | 169 |
| Revisions of previous estimates | (94) | | 78 | | — | | (24) | | (40) | | (2) | | (2) |
| Extensions, discoveries and other additions | 58 | | 48 | | — | | — | | 106 | | 18 | | 18 |
| | | | | | | | | | | | | |
| Sales of minerals in place | (18) | | — | | — | | — | | (18) | | (1) | | (1) |
| Production | (53) | | (8) | | (1) | | (3) | | (65) | | (22) | | (22) |
| At December 31, 2020 | 401 | | 204 | | 6 | | 134 | | 745 | | 162 | | 162 |
| Revisions of previous estimates | 16 | | 3 | | — | | — | | 19 | | 23 | | 23 |
| Extensions, discoveries and other additions | 161 | | 9 | | — | | 1 | | 171 | | 73 | | 73 |
| | | | | | | | | | | | | |
| Sales of minerals in place | (40) | | — | | — | | (27) | | (67) | | (6) | | (6) |
| Production | (40) | | (11) | | (1) | | (8) | | (60) | | (19) | | (19) |
| At December 31, 2021 | 498 | | 205 | | 5 | | 100 | | 808 | | 233 | | 233 |
| | | | | | | | | | | | | |
| Net Proved Developed Reserves | | | | | | | | | | | | | |
| At January 1, 2019 | 266 | | — | | 4 | | 149 | | 419 | | 85 | | 85 |
| At December 31, 2019 | 293 | | 31 | | 5 | | 139 | | 468 | | 90 | | 90 |
| At December 31, 2020 | 282 | | 72 | | 4 | | 134 | | 492 | | 120 | | 120 |
| At December 31, 2021 | 283 | | 65 | | 3 | | 100 | | 451 | | 138 | | 138 |
| | | | | | | | | | | | | |
| Net Proved Undeveloped Reserves | | | | | | | | | | | | | |
| At January 1, 2019 | 235 | | 40 | | 4 | | 16 | | 295 | | 90 | | 90 |
| At December 31, 2019 | 215 | | 55 | | 2 | | 22 | | 294 | | 79 | | 79 |
| At December 31, 2020 | 119 | | 132 | | 2 | | — | | 253 | | 42 | | 42 |
| At December 31, 2021 | 215 | | 140 | | 2 | | — | | 357 | | 95 | | 95 |
| (b)
| Our Norwegian operations were sold in 2017. Crude oil and condensate and NGLs proved reserves in Norway for 2016 were as follows:
|
(a)Other includes our interests in Denmark, which were sold in August 2021, and Libya. | | Crude Oil & Condensate | | | Natural Gas Liquids | |
| | (Millions of bbls) | | | (Millions of bbls) | |
At January 1, 2016 | | | 171 | | | | 27 | |
Revisions of previous estimates | | | (2 | ) | | | (19 | ) |
Extensions, discoveries and other additions | | | 4 | | | | — | |
Sales of minerals in place | | | — | | | | — | |
Production | | | (8 | ) | | | — | |
At December 31,2016 | | | 165 | | | | 8 | |
Net Proved Developed Reserves at December 31, 2016 | | | 75 | | | | 3 | |
Net Proved Undeveloped Reserves at December 31, 2016 | | | 90 | | | | 5 | |
| | Natural Gas | | | Total | |
| | United States | | | Europe (c) | | | Africa | | | Asia & Other | | | Total | | | United States | | | Europe (c) | | | Africa | | | Asia & Other | | | Total | |
| | (Millions of mcf) | | | (Millions of boe) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net Proved Reserves | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
At January 1, 2016 | | | 505 | | | | 234 | | | | 148 | | | | 667 | | | | 1,554 | | | | 504 | | | | 269 | | | | 197 | | | | 116 | | | | 1,086 | |
Revisions of previous estimates (a) | | | 116 | | | | (38 | ) | | | (3 | ) | | | 160 | | | | 235 | | | | 84 | | | | (39 | ) | | | 1 | | | | 28 | | | | 74 | |
Extensions, discoveries and other additions | | | 73 | | | | 41 | | | | — | | | | — | | | | 114 | | | | 29 | | | | 40 | | | | — | | | | — | | | | 69 | |
Sales of minerals in place | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
Production (b) | | | (104 | ) | | | (17 | ) | | | (2 | ) | | | (83 | ) | | | (206 | ) | | | (78 | ) | | | (15 | ) | | | (12 | ) | | | (15 | ) | | | (120 | ) |
At December 31, 2016 | | | 590 | | | | 220 | | | | 143 | | | | 744 | | | | 1,697 | | | | 539 | | | | 255 | | | | 186 | | | | 129 | | | | 1,109 | |
Revisions of previous estimates (a) | | | 171 | | | | 31 | | | | (2 | ) | | | 28 | | | | 228 | | | | 97 | | | | 10 | | | | (6 | ) | | | 5 | | | | 106 | |
Extensions, discoveries and other additions | | | 219 | | | | 7 | | | | — | | | | 176 | | | | 402 | | | | 214 | | | | 3 | | | | — | | | | 74 | | | | 291 | |
Sales of minerals in place | | | (18 | ) | | | (153 | ) | | | (15 | ) | | | — | | | | (186 | ) | | | (29 | ) | | | (192 | ) | | | (18 | ) | | | — | | | | (239 | ) |
Production (b) | | | (82 | ) | | | (13 | ) | | | (2 | ) | | | (103 | ) | | | (200 | ) | | | (70 | ) | | | (12 | ) | | | (13 | ) | | | (18 | ) | | | (113 | ) |
At December 31, 2017 | | | 880 | | | | 92 | | | | 124 | | | | 845 | | | | 1,941 | | | | 751 | | | | 64 | | | | 149 | | | | 190 | | | | 1,154 | |
Revisions of previous estimates (a) | | | (24 | ) | | | (14 | ) | | | 1 | | | | (21 | ) | | | (58 | ) | | | (21 | ) | | | (12 | ) | | | (3 | ) | | | (5 | ) | | | (41 | ) |
Extensions, discoveries and other additions | | | 177 | | | | 3 | | | | 8 | | | | 104 | | | | 292 | | | | 183 | | | | 3 | | | | 8 | | | | 19 | | | | 213 | |
Purchase of minerals in place | | | — | | | | — | | | | — | | | | — | | | | — | | | | 4 | | | | — | | | | — | | | | — | | | | 4 | |
Sales of minerals in place | | | (145 | ) | | | — | | | | — | | | | — | | | | (145 | ) | | | (35 | ) | | | — | | | | — | | | | — | | | | (35 | ) |
Production (b) | | | (75 | ) | | | (3 | ) | | | (5 | ) | | | (132 | ) | | | (215 | ) | | | (70 | ) | | | (3 | ) | | | (7 | ) | | | (23 | ) | | | (103 | ) |
At December 31, 2018 | | | 813 | | | | 78 | | | | 128 | | | | 796 | | | | 1,815 | | | | 812 | | | | 52 | | | | 147 | | | | 181 | | | | 1,192 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net Proved Developed Reserves | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
At January 1, 2016 | | | 368 | | | | 123 | | | | 137 | | | | 643 | | | | 1,271 | | | | 365 | | | | 147 | | | | 171 | | | | 112 | | | | 795 | |
At December 31, 2016 | | | 404 | | | | 125 | | | | 132 | | | | 739 | | | | 1,400 | | | | 371 | | | | 140 | | | | 160 | | | | 128 | | | | 799 | |
At December 31, 2017 | | | 526 | | | | 80 | | | | 117 | | | | 696 | | | | 1,419 | | | | 414 | | | | 58 | | | | 132 | | | | 121 | | | | 725 | |
At December 31, 2018 | | | 432 | | | | 77 | | | | 115 | | | | 585 | | | | 1,209 | | | | 423 | | | | 51 | | | | 130 | | | | 102 | | | | 706 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net Proved Undeveloped Reserves | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
At January 1, 2016 | | | 137 | | | | 111 | | | | 11 | | | | 24 | | | | 283 | | | | 139 | | | | 122 | | | | 26 | | | | 4 | | | | 291 | |
At December 31, 2016 | | | 186 | | | | 95 | | | | 11 | | | | 5 | | | | 297 | | | | 168 | | | | 115 | | | | 26 | | | | 1 | | | | 310 | |
At December 31, 2017 | | | 354 | | | | 12 | | | | 7 | | | | 149 | | | | 522 | | | | 337 | | | | 6 | | | | 17 | | | | 69 | | | | 429 | |
At December 31, 2018 | | | 381 | | | | 1 | | | | 13 | | | | 211 | | | | 606 | | | | 389 | | | | 1 | | | | 17 | | | | 79 | | | | 486 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Natural Gas | | Total |
| | United
States | | Guyana (b) | | Malaysia and
JDA | | Other (c) | | Total | | United
States | | Guyana (b) | | Malaysia and
JDA | | Other (c) | | Total |
| | | | | | | | | | | | | | | | | | | |
| | (Millions of mcf) | | (Millions of boe) |
| Net Proved Reserves | | | | | | | | | | | | | | | | | | | |
| At January 1, 2019 | 813 | | 12 | | 784 | | 206 | | 1,815 | | 812 | | 42 | | 139 | | 199 | | 1,192 |
| Revisions of previous estimates | (197) | | (7) | | 31 | | (11) | | (184) | | (116) | | 12 | | 4 | | (7) | | (107) |
| Extensions, discoveries and other additions | 164 | | 2 | | 3 | | 15 | | 184 | | 179 | | 33 | | 2 | | 14 | | 228 |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Production (a) | (80) | | — | | (133) | | (9) | | (222) | | (81) | | — | | (24) | | (11) | | (116) |
| At December 31, 2019 | 700 | | 7 | | 685 | | 201 | | 1,593 | | 794 | | 87 | | 121 | | 195 | | 1,197 |
| Revisions of previous estimates | (17) | | 68 | | 81 | | (32) | | 100 | | (99) | | 89 | | 14 | | (29) | | (25) |
| Extensions, discoveries and other additions | 78 | | 9 | | 20 | | — | | 107 | | 89 | | 50 | | 3 | | — | | 142 |
| | | | | | | | | | | | | | | | | | | |
| Sales of minerals in place | (5) | | — | | — | | — | | (5) | | (20) | | — | | — | | — | | (20) |
| Production (a) | (103) | | (1) | | (111) | | (4) | | (219) | | (92) | | (8) | | (20) | | (4) | | (124) |
| At December 31, 2020 | 653 | | 83 | | 675 | | 165 | | 1,576 | | 672 | | 218 | | 118 | | 162 | | 1,170 |
| Revisions of previous estimates | 138 | | (33) | | (42) | | — | | 63 | | 62 | | (3) | | (6) | | — | | 53 |
| Extensions, discoveries and other additions | 282 | | — | | 27 | | — | | 309 | | 281 | | 9 | | 4 | | 1 | | 295 |
| | | | | | | | | | | | | | | | | | | |
| Sales of minerals in place | (44) | | — | | — | | (63) | | (107) | | (53) | | — | | — | | (38) | | (91) |
| Production (a) | (94) | | (2) | | (135) | | (4) | | (235) | | (75) | | (11) | | (23) | | (9) | | (118) |
| At December 31, 2021 | 935 | | 48 | | 525 | | 98 | | 1,606 | | 887 | | 213 | | 93 | | 116 | | 1,309 |
| | | | | | | | | | | | | | | | | | | |
| Net Proved Developed Reserves | | | | | | | | | | | | | | | | | | | |
| At January 1, 2019 | 432 | | — | | 585 | | 192 | | 1,209 | | 423 | | — | | 102 | | 181 | | 706 |
| At December 31, 2019 | 400 | | 3 | | 497 | | 183 | | 1,083 | | 450 | | 31 | | 88 | | 170 | | 739 |
| At December 31, 2020 | 490 | | 36 | | 543 | | 165 | | 1,234 | | 484 | | 78 | | 94 | | 162 | | 818 |
| At December 31, 2021 | 568 | | 17 | | 394 | | 98 | | 1,077 | | 516 | | 68 | | 69 | | 116 | | 769 |
| | | | | | | | | | | | | | | | | | | |
| Net Proved Undeveloped Reserves | | | | | | | | | | | | | | | | | | | |
| At January 1, 2019 | 381 | | 12 | | 199 | | 14 | | 606 | | 389 | | 42 | | 37 | | 18 | | 486 |
| At December 31, 2019 | 300 | | 4 | | 188 | | 18 | | 510 | | 344 | | 56 | | 33 | | 25 | | 458 |
| At December 31, 2020 | 163 | | 47 | | 132 | | — | | 342 | | 188 | | 140 | | 24 | | — | | 352 |
| At December 31, 2021 | 367 | | 31 | | 131 | | — | | 529 | | 371 | | 145 | | 24 | | — | | 540 |
| (a)
| Revisions resulting from the impact of price changes in production sharing contracts reduced proved natural gas reserves in 2018 by 22 million mcf (2017: 22 million mcf decrease; 2016: 12 million mcf increase).
|
(a)Natural gas production in 2021 includes 19 million mcf used for fuel (2020: 16 million mcf; 2019: 14 million mcf). | (b)
| Natural gas production in 2018 includes 13 million mcf used for fuel (2017: 11 million mcf; 2016: 15 million mcf).
|
(b)Guyana natural gas reserves will be consumed for fuel. | (c)
| Natural gas and Total proved reserves in Norway for 2016 were as follows:
|
(c)Other includes our interests in Denmark, which were sold in August 2021, and Libya. | | Natural Gas (Millions of mcf) | | | Total (Millions of boe) | |
At January 1, 2016 | | | 191 | | | | 230 | |
Revisions of previous estimates | | | (26 | ) | | | (25 | ) |
Extensions, discoveries and other additions | | | 4 | | | | 5 | |
Sales of minerals in place | | | — | | | | — | |
Production | | | (9 | ) | | | (10 | ) |
At December 31, 2016 | | | 160 | | | | 200 | |
Net Proved Developed Reserves at December 31, 2016 | | | 72 | | | | 90 | |
Net Proved Undeveloped Reserves at December 31, 2016 | | | 88 | | | | 110 | |
Extensions, discoveries and other additions (‘Additions’)
2018
2021: Total Additions were 213295 million boe, of which 625 million boe (3(14 million barrels of crude oil, 7 million barrels of NGL and 1824 million mcf of natural gas) related to proved developed reserves. Additions to proved developed reserves were primarily resulted from drilling activity in the Bakken shale play in North Dakota. Additions to proved undeveloped reserves were 207270 million boe (122(157 million barrels of crude oil, 3966 million barrels of NGLsNGL and 274285 million mcf of natural gas) and are discussed in further detail on page 89.2017:
95. 2020: Total Additions were 291142 million boe, of which 1112 million boe (4(8 million barrels of crude oil, 12 million barrels of NGLsNGL and 3714 million mcf of natural gas) related to proved developed reserves. Additions to proved developed reserves were primarily resulted from drilling activity in the Bakken andshale play in North Malay Basin.Dakota. Additions to proved undeveloped reserves were 280130 million boe (170(98 million barrels of crude oil, 4916 million barrels of NGLsNGL and 36593 million mcf of natural gas) and are discussed in further detail on page 89.2016:
95. 2019: Total Additions were 69228 million boe, of which 4525 million boe (34(13 million barrels of crude oil, 26 million barrels of NGLsNGL and 5535 million mcf of natural gas) related to proved developed reserves. Additions to proved developed reserves were primarily resulted from drilling activitynew wells drilled in the Bakken and from a 20-year extension toshale play in North Dakota. Additions in the license forU.S. also included two wells drilled in the South Arne Field, offshore Denmark, which extends expiry to 2047.Gulf of Mexico. Additions to proved undeveloped reserves were 24203 million boe (11(144 million barrels of crude oil, 334 million barrels of NGLsNGL and 59149 million mcf of natural gas) and are discussed in further detail on page 89.95.
Revisions of previous estimates
2018:
2021: Total revisions of previous estimates of proved reserves amounted to a net increase of 53 million boe, of which revisions of proved developed reserves amounted to an increase of 73 million boe (31 million barrels of crude oil, 27 million barrels of NGL and 88 million mcf of natural gas). In the U.S., net positive revisions to proved developed reserves from the Bakken of 68 million boe were due to higher commodity prices (39 million boe) and improved well performance (32 million boe), partially offset by other negative revisions of 3 million boe. In the Gulf of Mexico, positive revisions to proved developed reserves were 10 million boe, including 5 million boe of positive price revisions and 5 million boe of other revisions, primarily improved well performance. In Malaysia and JDA, net negative revisions to proved developed reserves were 6 million boe due to the impact of higher commodity prices on entitlement allocations in the production sharing contract at JDA (50%) and performance at North Malay Basin and JDA (50%). Revisions associated with proved undeveloped reserves are discussed in further detail on page 95.
2020: Total revisions of previous estimates of proved reserves amounted to a net decrease of 25 million boe, of which revisions of proved developed reserves amounted to an increase of 108 million boe(38 million barrels of crude oil, 30 million barrels of NGL and 237million mcf of natural gas). In the U.S., revisions to proved developed reserves from the Bakken were a net increase of 55 million boe, comprised of positive revisions of 77 million boe and negative price revisions of 22 million boe. The positive revisions resulted from well performance (50%), updated yield and decline factors (30%) and other changes (20%), primarily driven by cost reductions. In the Gulf of Mexico, net negative revisions were 8 million boe, including 2 million boe of negative price revisions. In Guyana, revisions increased proved developed reserves by 47 million boe related to performance (55%), improved recovery associated with water injection (35%), and increased natural gas for consumption (10%). In Malaysia and JDA, net revisions to proved developed reserves were an increase of 18 million boe due to performance at North Malay Basin and JDA (80%) and the impact of lower crude oil prices on entitlement allocations in the production sharing contract at JDA (20%). Other had negative revisions to proved developed reserves of 4 million boe, primarily in Libya. Revisions associated with proved undeveloped reserves are discussed in further detail on page 95.
2019: Total revisions of previous estimates amounted to a net decrease of 41107 million boe, of which revisions of proved developed reserves amounted to a net increasedecrease of 319 million boe(crude oil - 4 million barrels increase, NGLs - 4 million barrels decrease and natural gas - 20 million mcf increase). Revisions to proved developed reserves primarily relate to the Bakken. Revisions associated with proved undeveloped reserves are discussed in further detail on page 89.2017: Total revisions of previous estimates amounted to a net increase of 106 million boe, of which revisions of proved developed reserves amounted to a net increase of 126 million boe (41 7
million barrels of crude oil, 44 million barrels of NGLsNGL and 24372 million mcf of natural gas). Revisions to proved developed reserves from the Bakken amounted to 85were a net decrease of 25 million boe with approximately 55% resulting80% relating to changes in expected recoveries of NGL and natural gas and approximately 20% relating to the impact of lower prices. Net revisions from improved reservoir performance, and the remaining 45% resulting from higher prices andinternational assets were an improved cost structure. The Gulfincrease of Mexico and Utica had positive revisions to proved developed reserves totaling 166 million boe due to improved reservoir performance, while higher crude oil prices resulted in revisions to proved developed reserves of 15 million boe in Denmark and Utica.boe. Revisions associated with proved undeveloped reserves are discussed in further detail on page 89.2016: Total revisions of previous estimates amounted to a net increase of 74 million boe, of which net positive revisions increased proved reserves by 103 million boe (54 million barrels of crude oil, 5 million barrels of NGLs and 265 million mcf of natural gas) and negative revisions associated with lower crude oil prices reduced proved reserves by 29 million boe (23 million barrels of crude oil, 1 million barrels of NGLs and 30 million mcf of natural gas). Total revisions of proved developed reserves amounted to a net increase of 41 million boe (5 million barrels decrease of crude oil, 7 million barrels increase of NGLs and 235 million mcf increase of natural gas) reflecting improved expected recoveries in the Bakken, completion of incremental development activities at the North Malay Basin, partially offset by negative revisions at the Valhall Field offshore Norway due to changes in estimated recoveries of NGLs and natural gas, and negative price revisions mostly related to crude oil reserves. Revisions associated with proved undeveloped reserves are discussed in further detail on page 89.
95.
Sales of minerals in place (‘Asset sales’)
2018: Assets
2021: Asset sales primarily includerelate to the divestiture of our formerworking interests in Denmark and our acreage interests in the Utica BasinLittle Knife and Murphy Creek area of Ohio.2017: Assetsthe Bakken.
2020: Asset sales primarily includerelate to the divestiture of our former interests in Norway, Equatorial Guinea, and our enhanced oil recovery assets28% working interest in the Permian Basin.
Shenzi Field in the deepwater Gulf of Mexico.
Proved Undeveloped Reserves
Following are the Corporation’s proved undeveloped reserves:
| | | | | United
States | | Guyana | | Malaysia and
JDA | | Other (a) | | Total |
| | United States | | | Europe | | | Africa | | | Asia & Other | | | Total | | | | | | | | | | | |
| | (Millions of boe) | | | (Millions of boe) |
Net Proved Undeveloped Reserves | | | | | | | | | | | | | | | | | | | | | Net Proved Undeveloped Reserves | | | | | | | | | |
At January 1, 2016 | | | 139 | | | | 122 | | | | 26 | | | | 4 | | | | 291 | | |
| At January 1, 2019 | | At January 1, 2019 | 389 | | 42 | | 37 | | 18 | | 486 |
| Revisions of previous estimates | | Revisions of previous estimates | (91) | | 9 | | — | | (6) | | (88) |
| Extensions, discoveries and other additions | | Extensions, discoveries and other additions | 154 | | 34 | | — | | 15 | | 203 |
| Transfers to proved developed reserves | | Transfers to proved developed reserves | (108) | | (29) | | (4) | | (2) | | (143) |
| | At December 31, 2019 | | At December 31, 2019 | 344 | | 56 | | 33 | | 25 | | 458 |
Revisions of previous estimates | | | 50 | | | | (14 | ) | | | — | | | | (3 | ) | | | 33 | | Revisions of previous estimates | (146) | | 42 | | (4) | | (25) | | (133) |
Extensions, discoveries and other additions | | | 13 | | | | 11 | | | | — | | | | — | | | | 24 | | Extensions, discoveries and other additions | 78 | | 50 | | 2 | | — | | 130 |
Transfers to proved developed reserves | | | (34 | ) | | | (4 | ) | | | — | | | | — | | | | (38 | ) | Transfers to proved developed reserves | (85) | | (8) | | (7) | | — | | (100) |
Sales of minerals in place | | | — | | | | — | | | | — | | | | — | | | | — | | Sales of minerals in place | (3) | | — | | — | | — | | (3) |
At December 31, 2016 | | | 168 | | | | 115 | | | | 26 | | | | 1 | | | | 310 | | |
| At December 31, 2020 | | At December 31, 2020 | 188 | | 140 | | 24 | | — | | 352 |
Revisions of previous estimates | | | (8 | ) | | | (3 | ) | | | (9 | ) | | | — | | | | (20 | ) | Revisions of previous estimates | (16) | | (4) | | — | | — | | (20) |
Extensions, discoveries and other additions | | | 209 | | | | 3 | | | | — | | | | 68 | | | | 280 | | Extensions, discoveries and other additions | 257 | | 9 | | 4 | | — | | 270 |
Transfers to proved developed reserves | | | (32 | ) | | | — | | | | — | | | | — | | | | (32 | ) | Transfers to proved developed reserves | (19) | | — | | (4) | | — | | (23) |
Sales of minerals in place | | | — | | | | (109 | ) | | | — | | | | — | | | | (109 | ) | Sales of minerals in place | (39) | | — | | — | | — | | (39) |
At December 31, 2017 | | | 337 | | | | 6 | | | | 17 | | | | 69 | | | | 429 | | |
Revisions of previous estimates | | | (22 | ) | | | (7 | ) | | | (6 | ) | | | (9 | ) | | | (44 | ) | |
Extensions, discoveries and other additions | | | 178 | | | | 2 | | | | 8 | | | | 19 | | | | 207 | | |
Transfers to proved developed reserves | | | (97 | ) | | | — | | | | (2 | ) | | | — | | | | (99 | ) | |
Sales of minerals in place | | | (7 | ) | | | — | | | | — | | | | — | | | | (7 | ) | |
At December 31, 2018 | | | 389 | | | | 1 | | | | 17 | | | | 79 | | | | 486 | | |
| At December 31, 2021 | | At December 31, 2021 | 371 | | 145 | | 24 | | — | | 540 |
(a)Other includes our interests in Denmark, which were sold in August 2021, and Libya.
Extensions, discoveries and other additions (‘Additions’)
2018:
2021: In the United States, additions from the Bakken shale play in North Dakota were 168257 million boe, which resulted from additional undeveloped well locations due to improved economic conditions, planned additional drilling activity, and development plan optimization. In Guyana, additions of 9 million boe related to the deepening of the hydrocarbon contact for Liza Phase 2. In Malaysia and JDA, additions were due to additional planned wells to be drilled.
2020: In the United States, additions from the Bakken shale play in North Dakota were 78 million boe, which primarily resulted from new wells planned to be drilled in the next five years, including the impact of optimizing locations in the development plan. In Guyana, additions of 50 million boe were due to the sanction of the Payara project. In Malaysia, additions at the North Malay Basin were due to additional planned wells to be drilled.
2019: In the United States, additions from the Bakken shale play in North Dakota were 154 million boe, of which approximately 40%25% of the change results from additional planned wells to be drilled in the next five years, and approximately 35%75% results from performancenew wells moved into the five-year plan associated with improved well completion designs,optimization of drilling locations. Additions in Guyana totaling 34 million boe are from the sanction of Phase 2 development at the Liza Field on the Stabroek Block, offshore Guyana. Other additions were at the South Arne Field in Denmark and approximately 25% resultsin Libya due to additional planned wells to be drilled.
Revisions of previous estimates
2021: In the United States, net negative reserve revisions of 16 million boe were primarily from the Bakken, which included a decrease of 88 million boe largely related to wells moved outside the five-year development plan mainly based on optimization of drilling locations and other changes, primarilynet negative revisions of 8 million boe, partially offset by positive revisions of 80 million boe related to higher prices. In Guyana, net negative reserve revisions were 4 million boe, which included negative revisions of 16 million boe related to the impact of higher crude oil prices. Additionsprices on entitlement allocations in the Gulfproduction sharing contract and negative revisions of Mexico were 103 million boe due to additional planned drilling at the Tubular Bells Field. Additions in Asia include 11resulting from decreased natural gas for consumption. Positive revisions of 15 million boe at North Malay Basinin Guyana resulted from improved recovery associated with water and 8 million boe at the JDA relating to additional planned wells to be drilled within the next five years.2017: gas injection.
2020: In the United States, additionsnegative reserve revisions of 146 million boe were from the Bakken, were 180which included negative price revisions of 77 million boe, and a decrease of which approximately 70% resulted121 million boe from higherwells moved outside our management and Board approved five-year plan due to a reduction in planned rig count and optimization of drilling locations in response to the decline in crude oil prices thatin 2020. These decreases were partially offset by positive revisions of 52 million boe, primarily due to optimized development spacing and increased well productivity. In Guyana, net positive reserve revisions for Liza Phase 1 and Phase 2 totaling 42 million boe resulted from improved recovery associated with water injection (45%), the percentageimpact of proved undevelopedlower crude oil prices on entitlement allocations in the production sharing contract (40%) and increased natural gas for consumption (15%). For Other, net negative reserves revisions were 14 million boe in Libya and 11 million boe in Denmark due to moving planned wells outside our five-year plan in our planned five-year drilling program comparedresponse to the prior year. The remaining 30% of Bakken additions reflect the expected improved recoverydecline in future wells from changescrude oil prices in well completion design and reservoir performance. Additions from the Stampede Field in the Gulf of Mexico were 21 million boe, due to completion of further development activities. At the Stabroek Block, offshore Guyana, additions of 45 million boe were recognized for project sanction of the first phase of the Liza Field development. Other international additions were primarily at North Malay Basin due to higher prices.2016: In the United States, additions were at the Utica shale play in Ohio as result of changes in well design that improved both well economics and recoverability, and at the Bakken due to drilling plans. In Europe, additions were primarily from a 20-year extension to the license for the South Arne Field, offshore Denmark, which extends expiry to 2047.
Revisions of previous estimates
2018: 2020.
2019: Negative reserve revisions in the United States totaling 22of 91 million boe primarilywere largely from the Bakken (94 million boe), of which approximately 75% resulted from optimizingwells moved outside our five-year plan associated withoptimization of drilling plans atlocations. The remaining 25% of negative revisions in the Bakken. NegativeBakken were caused by lower commodity prices. The net positive reserve revisions in international assets primarily resulted from updates in drilling plans in Denmark and North Malay Basin, andGuyana of 9 million boe relate to the Liza Phase 1 development due to the impact of lower crude oil price changesprices on our PSC in Guyana.2017: Total negative reserve revisions of 20 million boe, primarily relate to changes in drilling plans in Libya and lower reserves at certain fieldsentitlement allocations in the Gulf of Mexico and Denmark.
2016: Total positive reserve revisions were 33 million boe. Technical revisions increased reserves by 44 million boe and were primarily from an improved well design at the Bakken, which was partially offset by negative revisions at the Valhall Field offshore Norway due to changes in expected recoveries of NGLs and natural gas. Negative revisions resulting from lower commodity prices totaled 11 million boe and were primarily in the Bakken.
production sharing agreement.
Transfers to proved developed reserves (‘Transfers’)
2018: Transfers2021: Transfers from proved undeveloped reserves resulting from drilling activity included 19 million boe in the Bakken, and 4 million boe at JDA. Transfers in 2021 were consistent with the development plan used to determine proved reserves at December 31, 2020.
2020: Transfers from proved undeveloped reserves resulting from drilling activity included 83 million boe in the Bakken, 2 million boe in the Gulf of Mexico, 8 million boe for Liza Phase 1 in Guyana, and 7 million boe in the North Malay Basin.
2019: Transfers from proved undeveloped reserves included 75100 million boe in the Bakken shale play associated with drilling activity, and 2229 million boe at the Stampede FieldStabroek Block in the Gulf of MexicoGuyana where first production was achieved in 2018.2017: Transfers from proved undeveloped reserves included 24 million boe in the Bakken 2019,
and 8 million boe at the Penn StateTubular Bells Field in the Gulf of Mexico associated with drilling activity.2016: Transfers from proved undeveloped reserves included 21 million boe in the Bakken and 13 million boe at the Tubular Bells and Conger Fields in the Gulf of Mexico associated with drilling activity.
In
2018,2021, capital expenditures of
$1,070$190 million were incurred to convert proved undeveloped reserves to proved developed reserves
(2017: $527(2020: $1,090 million;
2016: $5892019: $1,750 million)
.Projects
At December 31, 2021, projects that have proved reserves
whichthat have been classified as undeveloped for a period in excess of five years
total 6totaled 11 million boe, or
less than 1% of total proved reserves,
related to the multi-phase offshore developments, primarily at
December 31, 2018. Most ofNorth Malay Basin, offshore Malaysia, and the
proved undeveloped reserves in excess of five years relate to Libya.Stabroek Block, offshore Guyana.
Production Sharing Contracts
The Corporation’s proved reserves include crude oil and natural gas reserves relating to long‑term agreements with governments or authorities in which the Corporation has the legal right to produce or has a revenue interest in the production.
Proved reserves fromThe Corporation's operations with these production sharing
contractsarrangements include those in Guyana, Malaysia, and the JDA. Proved reserves for each of the three years ended December 31,
2018 are presented separately below,2021, as well as volumes produced and received during
2018, 20172021, 2020 and
20162019 from these production sharing
contracts. | | Crude Oil | | | Natural Gas | |
| | United States | | | Europe | | | Africa | | | Asia & Other (a) | | | Total | | | United States | | | Europe | | | Africa | | | Asia & Other (a) | | | Total | |
| | (Millions of bbls) | | | (Millions of mcf) | |
Production Sharing Contracts | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Proved Reserves | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
At December 31, 2016 | | | — | | | | — | | | | 24 | | | | 5 | | | | 29 | | | | — | | | | — | | | | 15 | | | | 744 | | | | 759 | |
At December 31, 2017 | | | — | | | | — | | | | — | | | | 49 | | | | 49 | | | | — | | | | — | | | | — | | | | 845 | | | | 845 | |
At December 31, 2018 | | | — | | | | — | | | | — | | | | 48 | | | | 48 | | | | — | | | | — | | | | — | | | | 796 | | | | 796 | |
Production | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2016 | | | — | | | | — | | | | 12 | | | | 1 | | | | 13 | | | | — | | | | — | | | | 2 | | | | 83 | | | | 85 | |
2017 | | | — | | | | — | | | | 9 | | | | 1 | | | | 10 | | | | — | | | | — | | | | 2 | | | | 103 | | | | 105 | |
2018 | | | — | | | | — | | | | — | | | | 1 | | | | 1 | | | | — | | | | — | | | | — | | | | 132 | | | | 132 | |
(a)
| Asia and Other includes Guyana proved undeveloped reserves of 40 million barrels of oil and 11 million mcf of natural gas at December 31, 2018 and 43 million barrels of oil and 11 million mcf of natural gas at December 31, 2017.
|
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Future net cash flows are calculated by applying prescribed oil and gas selling prices used in determining year‑end reserve estimates (adjusted for price changes provided by contractual arrangements) to estimated future production of proved oil and gas reserves, less estimated future development and production costs, which are based on year‑end costs and existing economic assumptions. Future income tax expenses are computed by applying the appropriate year‑end statutory tax rates to the pre‑tax net cash flows, as well as including the effect of tax deductions and tax credits and allowances relating to the Corporation’s proved oil and gas reserves. Future net cash flows are discounted at the prescribed rate of 10%.
The prices used for the discounted future net cash flows in
20182021 were
$65.55$66.34 per barrel for WTI
(2017: $51.19; 2016: $42.68)(2020: $39.77; 2019: $55.73) and
$72.08$68.92 per barrel for Brent
(2017: $54.87; 2016: $44.45)(2020: $43.43; 2019: $62.54) and do not include the effects of commodity hedges.
New York Mercantile Exchange (NYMEX)NYMEX natural gas prices used were
$3.01$3.68 per mcf in
2018 (2017: $3.03; 2016:2021 (2020: $2.16; 2019: $2.54). Selling prices have in the past, and can in the future, fluctuate significantly. As a result, selling prices used in the disclosure of future net cash flows may not be representative of future selling prices. In addition, the discounted future net cash flow estimates do not include exploration expenses, interest expense or corporate general and administrative expenses. The amount of tax deductions, credits, and allowances relating to the Corporation’s proved oil and gas reserves can change year to year due to factors including changes in proved reserves, variances in actual pre-tax cash flows from forecasted pre-tax cash flows in historical periods, and the impact to year-end carryforward tax attributes associated with deducting in the Corporation’s income tax returns exploration expenses, interest expense, and corporate general and administrative expenses that are not contemplated
in the standardized measure computations. The future net cash flow estimates could be materially different if other assumptions were used.
At December 31 | | Total | | | United States | | | Europe (a) | | | Africa | | | Asia & Other | |
| | (In millions) | |
2018 | | | | | | | | | | | | | | | | | | | | |
Future revenues | | $ | 50,948 | | | $ | 31,460 | | | $ | 3,036 | | | $ | 9,183 | | | $ | 7,269 | |
Less: | | | | | | | | | | | | | | | | | | | | |
Future production costs | | | 13,636 | | | | 9,718 | | | | 1,311 | | | | 678 | | | | 1,929 | |
Future development costs | | | 8,427 | | | | 6,132 | | | | 449 | | | | 301 | | | | 1,545 | |
Future income tax expenses | | | 10,950 | | | | 2,641 | | | | 246 | | | | 7,496 | | | | 567 | |
| | | 33,013 | | | | 18,491 | | | | 2,006 | | | | 8,475 | | | | 4,041 | |
Future net cash flows | | | 17,935 | | | | 12,969 | | | | 1,030 | | | | 708 | | | | 3,228 | |
Less: Discount at 10% annual rate | | | 7,285 | | | | 5,437 | | | | 444 | | | | 359 | | | | 1,045 | |
Standardized Measure of Discounted Future Net Cash Flows | | $ | 10,650 | | | $ | 7,532 | | | $ | 586 | | | $ | 349 | | | $ | 2,183 | |
| | | | | | | | | | | | | | | | | | | | |
2017 | | | | | | | | | | | | | | | | | | | | |
Future revenues | | $ | 36,746 | | | $ | 20,834 | | | $ | 2,958 | | | $ | 7,154 | | | $ | 5,800 | |
Less: | | | | | | | | | | | | | | | | | | | | |
Future production costs | | | 13,042 | | | | 8,802 | | | | 1,501 | | | | 782 | | | | 1,957 | |
Future development costs | | | 6,748 | | | | 4,601 | | | | 553 | | | | 330 | | | | 1,264 | |
Future income tax expenses | | | 6,379 | | | | 444 | | | | 137 | | | | 5,485 | | | | 313 | |
| | | 26,169 | | | | 13,847 | | | | 2,191 | | | | 6,597 | | | | 3,534 | |
Future net cash flows | | | 10,577 | | | | 6,987 | | | | 767 | | | | 557 | | | | 2,266 | |
Less: Discount at 10% annual rate | | | 4,221 | | | | 2,904 | | | | 272 | | | | 307 | | | | 738 | |
Standardized Measure of Discounted Future Net Cash Flows | | $ | 6,356 | | | $ | 4,083 | | | $ | 495 | | | $ | 250 | | | $ | 1,528 | |
| | | | | | | | | | | | | | | | | | | | |
2016 | | | | | | | | | | | | | | | | | | | | |
Future revenues | | $ | 32,814 | | | $ | 13,035 | | | $ | 10,283 | | | $ | 6,907 | | | $ | 2,589 | |
Less: | | | | | | | | | | | | | | | | | | | | |
Future production costs | | | 14,054 | | | | 6,639 | | | | 5,091 | | | | 1,440 | | | | 884 | |
Future development costs | | | 8,635 | | | | 2,910 | | | | 4,348 | | | | 992 | | | | 385 | |
Future income tax expenses | | | 2,450 | | | | — | | | | (2,064 | ) | (b) | | 4,406 | | | | 108 | |
| | | 25,139 | | | | 9,549 | | | | 7,375 | | | | 6,838 | | | | 1,377 | |
Future net cash flows | | | 7,675 | | | | 3,486 | | | | 2,908 | | | | 69 | | | | 1,212 | |
Less: Discount at 10% annual rate | | | 3,650 | | | | 1,288 | | | | 2,072 | | | | 40 | | | | 250 | |
Standardized Measure of Discounted Future Net Cash Flows | | $ | 4,025 | | | $ | 2,198 | | | $ | 836 | | | $ | 29 | | | $ | 962 | |
(a)
| The standardized measure of discounted future net cash flows relating to proved reserves in Norway for 2016 (in millions) were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| At December 31 | | Total | | United
States | | Guyana | | Malaysia and
JDA | | Other (a) |
| | | | | | | | | | |
| | | (In millions) |
| 2021 | | | | | | | | | | |
| Future revenues | | $ | 55,788 | | | $ | 32,054 | | | $ | 13,940 | | | $ | 2,759 | | | $ | 7,035 | |
| Less: | | | | | | | | | | |
| Future production costs | | 15,553 | | | 11,246 | | | 3,043 | | | 910 | | | 354 | |
| Future development costs | | 8,122 | | | 4,342 | | | 3,063 | | | 543 | | | 174 | |
| Future income tax expenses | | 11,257 | | | 3,625 | | | 1,516 | | | 151 | | | 5,965 | |
| | 34,932 | | | 19,213 | | | 7,622 | | | 1,604 | | | 6,493 | |
| Future net cash flows | | 20,856 | | | 12,841 | | | 6,318 | | | 1,155 | | | 542 | |
| Less: Discount at 10% annual rate | | 9,603 | | | 7,073 | | | 2,091 | | | 193 | | | 246 | |
| Standardized Measure of Discounted Future Net Cash Flows | | $ | 11,253 | | | $ | 5,768 | | | $ | 4,227 | | | $ | 962 | | | $ | 296 | |
| | | | | | | | | | |
| 2020 | | | | | | | | | | |
| Future revenues | | $ | 28,745 | | | $ | 11,757 | | | $ | 8,362 | | | $ | 2,578 | | | $ | 6,048 | |
| Less: | | | | | | | | | | |
| Future production costs | | 12,360 | | | 6,887 | | | 2,784 | | | 1,073 | | | 1,616 | |
| Future development costs | | 6,322 | | | 2,593 | | | 2,617 | | | 677 | | | 435 | |
| Future income tax expenses | | 4,135 | | | 45 | | | 380 | | | 110 | | | 3,600 | |
| | 22,817 | | | 9,525 | | | 5,781 | | | 1,860 | | | 5,651 | |
| Future net cash flows | | 5,928 | | | 2,232 | | | 2,581 | | | 718 | | | 397 | |
| Less: Discount at 10% annual rate | | 2,343 | | | 1,205 | | | 935 | | | 123 | | | 80 | |
| Standardized Measure of Discounted Future Net Cash Flows | | $ | 3,585 | | | $ | 1,027 | | | $ | 1,646 | | | $ | 595 | | | $ | 317 | |
| | | | | | | | | | |
| 2019 | | | | | | | | | | |
| Future revenues | | $ | 44,778 | | | $ | 25,223 | | | $ | 5,326 | | | $ | 3,473 | | | $ | 10,756 | |
| Less: | | | | | | | | | | |
| Future production costs | | 14,176 | | | 10,189 | | | 931 | | | 1,238 | | | 1,818 | |
| Future development costs | | 8,267 | | | 5,104 | | | 1,549 | | | 823 | | | 791 | |
| Future income tax expenses | | 8,560 | | | 1,291 | | | 505 | | | 162 | | | 6,602 | |
| | 31,003 | | | 16,584 | | | 2,985 | | | 2,223 | | | 9,211 | |
| Future net cash flows | | 13,775 | | | 8,639 | | | 2,341 | | | 1,250 | | | 1,545 | |
| Less: Discount at 10% annual rate | | 5,390 | | | 3,872 | | | 539 | | | 270 | | | 709 | |
| Standardized Measure of Discounted Future Net Cash Flows | | $ | 8,385 | | | $ | 4,767 | | | $ | 1,802 | | | $ | 980 | | | $ | 836 | |
Future revenues | | | | $ | 8,188 | |
Less: | | | | | | |
Future production costs | | | | | 4,004 | |
Future development costs | | | | | 3,931 | |
Future income tax expenses (b) | | | | | (2,112 | ) |
| | | | | 5,823 | |
Future net cash flows | | | | | 2,365 | |
Less: Discount at 10% annual rate | | | | | 1,969 | |
Standardized Measure of Discounted Future Net Cash Flows | | | | $ | 396 | |
(b)
| The Petroleum Tax Act provides for compensation by the Norwegian government to a company upon cessation of its E&P activities on the Norwegian Continental Shelf in an amount equal to the tax values of unutilized tax losses and certain other tax attributes, including dismantlement expenditures incurred after production has ceased that would qualify for compensation at an effective tax rate of 78%. Due to the low crude oil price used in the 2016 computation, future income taxes reflect cash inflows for Norway of $2.1 billion on an undiscounted basis. The corresponding present value reflected in the Standardized Measure of Discounted Future Net Cash Flows at December 31, 2016 is $70 million.
|
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
For the Years Ended December 31 | | 2018 | | | 2017 | | | 2016 | |
| | (In millions) | |
Standardized Measure of Discounted Future Net Cash Flows at January 1 | | $ | 6,356 | | | $ | 4,025 | | | $ | 7,190 | |
Changes during the year: | | | | | | | | | | | | |
Sales and transfers of oil and gas produced during the year, net of production costs | | | (2,755 | ) | | | (2,216 | ) | | | (1,368 | ) |
Development costs incurred during the year | | | 1,533 | | | | 1,679 | | | | 1,369 | |
Net changes in prices and production costs applicable to future production | | | 7,076 | | | | 2,330 | | | | (4,284 | ) |
Net change in estimated future development costs | | | (1,119 | ) | | | (568 | ) | | | (76 | ) |
Extensions and discoveries (including improved recovery) of oil and gas reserves, less related costs | | | 2,129 | | | | 1,282 | | | | 338 | |
Revisions of previous oil and gas reserve estimates | | | (630 | ) | | | 644 | | | | 376 | |
Net purchases (sales) of minerals in place, before income taxes | | | (83 | ) | | | 116 | | | | — | |
Accretion of discount | | | 929 | | | | 603 | | | | 779 | |
Net change in income taxes | | | (2,662 | ) | | | (709 | ) | | | 1,331 | |
Revision in rate or timing of future production and other changes | | | (124 | ) | | | (830 | ) | | | (1,630 | ) |
Total | | | 4,294 | | | | 2,331 | | | | (3,165 | ) |
Standardized Measure of Discounted Future Net Cash Flows at December 31 | | $ | 10,650 | | | $ | 6,356 | | | $ | 4,025 | |
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Following are selected quarterly results of operations (unaudited):
| | 2018 | |
| | First
Quarter | | | Second
Quarter | | | Third
Quarter | | | Fourth
Quarter | |
| | (In millions, except per share amounts) | |
Sales and other operating revenues | | $ | 1,346 | | | $ | 1,534 | | | $ | 1,793 | | | | 1,650 | |
Gross profit (loss) (a) | | $ | 244 | | | $ | 310 | | | $ | 500 | | | | 310 | |
| | | | | | | | | | | | | | | | |
Net income (loss) | | | (65 | ) | | | (87 | ) | | | 3 | | | | 34 | |
Less: Net income (loss) attributable to noncontrolling interests | | | 41 | | | | 43 | | | | 45 | | | | 38 | |
Net income (loss) attributable to Hess Corporation | | | (106 | ) | | | (130 | ) | | | (42 | ) | | | (4 | ) |
Less: Preferred stock dividends | | | 11 | | | | 12 | | | | 11 | | | | 12 | |
Net income (loss) attributable to Hess Corporation common stockholders | | $ | (117 | ) | (b) | $ | (142 | ) (c) | | | (53 | ) (d) | | | (16 | ) (e) |
| | | | | | | | | | | | | | | | |
Net income (loss) attributable to Hess Corporation per common share: | | | | | | | | | | | | | | | | |
Basic | | $ | (0.38 | ) | | $ | (0.48 | ) | | | (0.18 | ) | | | (0.05 | ) |
Diluted | | $ | (0.38 | ) | | $ | (0.48 | ) | | | (0.18 | ) | | | (0.05 | ) |
| |
| | 2017 | |
| | First
Quarter | | | Second
Quarter | | | Third
Quarter | | | Fourth
Quarter | |
| | (In millions, except per share amounts) | |
Sales and other operating revenues | | $ | 1,258 | | | $ | 1,197 | | | $ | 1,348 | | | $ | 1,663 | |
Gross profit (loss) (a) | | $ | (68 | ) | | $ | (201 | ) | | $ | (2,632 | ) | | $ | (1,548 | ) |
| | | | | | | | | | | | | | | | |
Net income (loss) | | | (296 | ) | | | (417 | ) | | | (593 | ) | | | (2,635 | ) |
Less: Net income (loss) attributable to noncontrolling interests | | | 28 | | | | 32 | | | | 31 | | | | 42 | |
Net income (loss) attributable to Hess Corporation | | | (324 | ) | | | (449 | ) | | | (624 | ) | | | (2,677 | ) |
Less: Preferred stock dividends | | | 12 | | | | 11 | | | | 11 | | | | 12 | |
Net income (loss) attributable to Hess Corporation common stockholders | | $ | (336 | ) | | $ | (460 | ) | | $ | (635 | ) (f) | | $ | (2,689 | ) (g) |
| | | | | | | | | | | | | | | | |
Net income (loss) attributable to Hess Corporation per common share: | | | | | | | | | | | | | | | | |
Basic | | $ | (1.07 | ) | | $ | (1.46 | ) | | $ | (2.02 | ) | | $ | (8.57 | ) |
Diluted | | $ | (1.07 | ) | | $ | (1.46 | ) | | $ | (2.02 | ) | | $ | (8.57 | ) |
(a)
| Gross profit represents Sales and other operating revenues, less Marketing expenses, Operating costs and expenses, Production and severance taxes, Depreciation, depletion and amortization and Impairment.
|
| | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31 | | 2021 | | 2020 | | 2019 |
| | | | | | |
| | | (In millions) |
| Standardized Measure of Discounted Future Net Cash Flows at January 1 | | $ | 3,585 | | | $ | 8,385 | | | $ | 10,650 | |
| Changes during the year: | | | | | | |
| Sales and transfers of oil and gas produced during the year, net of production costs | | (3,282) | | | (1,829) | | | (2,842) | |
| Development costs incurred during the year | | 1,437 | | | 1,479 | | | 2,262 | |
| Net changes in prices and production costs | | 11,321 | | | (10,141) | | | (5,761) | |
| Net change in estimated future development costs | | (1,695) | | | 1,860 | | | (186) | |
| Extensions and discoveries (including improved recovery) of oil and gas reserves, less related costs | | 2,419 | | | 543 | | | 1,591 | |
| Revisions of previous oil and gas reserve estimates | | 461 | | | 364 | | | (281) | |
| Net purchases (sales) of minerals in place, before income taxes | | (196) | | | (500) | | | — | |
| Accretion of discount | | 578 | | | 1,220 | | | 1,635 | |
| Net change in income taxes | | (3,477) | | | 2,091 | | | 1,305 | |
| Revision in rate or timing of future production and other changes | | 102 | | | 113 | | | 12 | |
| Total | | 7,668 | | | (4,800) | | | (2,265) | |
| Standardized Measure of Discounted Future Net Cash Flows at December 31 | | $ | 11,253 | | | $ | 3,585 | | | $ | 8,385 | |
(b)
| Includes a net after-tax severance charge of $37 million ($37 million pre-tax), an after-tax charge of $27 million ($27 million pre-tax) relating to the premium paid for the retirement of debt, and a noncash income tax benefit of $30 million to offset a noncash income tax expense recognized in other comprehensive income, resulting from a reduction in our pension liabilities.
|
(c)
| Includes an after-tax gain of $10 million ($10 million pre-tax) associated with the sale of our interests in Ghana, an after-tax charge of $26 million ($26 million pre-tax) relating to the premium paid for the retirement of debt, and an after-tax charge of $58 million ($58 million pre-tax) resulting from the settlement of legal claims related to former downstream interests.
|
(d)
| Includes an after-tax gain of $14 million ($14 million pre-tax) associated with the sale of our interests in the Utica shale play in eastern Ohio, noncash after-tax charges of $73 million ($73 million pre-tax) in connection with vacated office space, and an allocation of noncash income tax expense of $12 million to offset the recognition of a noncash income tax benefit recorded in other comprehensive income resulting from changes in fair value of our 2019 crude oil hedging program.
|
(e)
| Includes a noncash income tax benefit of $73 million to offset the recognition of a noncash income tax expense recorded in other comprehensive income primarily resulting from changes in fair value of our 2019 crude oil hedging program.
|
(f)
| Includes an after-tax impairment charge of $550 million ($2,503 million pre-tax) associated with the expected sale of our interests in Norway and an after-tax gain of $280 million ($280 million pre-tax) related to the sale of our Permian assets.
|
(g)
| Includes an after-tax impairment charge of $1,700 million ($1,700 million pre-tax) associated with certain Gulf of Mexico assets, an after-tax charge of $280 million to fully impair the carrying value of our interests in Ghana ($280 million pre-tax), and a net $371 million after-tax loss related to sales of our interests in Norway and Equatorial Guinea ($371 million pre-tax).
|
The results of operations for the periods reported herein should not be considered as indicative of future operating results.
ItemItem 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Based upon their evaluation of the Corporation’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31,
2018,2021, John B. Hess, Chief Executive Officer, and John P. Rielly, Chief Financial Officer, concluded that these disclosure controls and procedures were effective as of December 31,
2018.2021.
There was no change in internal controls over financial reporting identified in the evaluation required by paragraph (d) of Rules 13a-15 or 15d-15 in the quarter ended December 31,
20182021 that has materially affected, or is reasonably likely to materially affect, internal controls over financial reporting.
Management’s report on internal control over financial reporting and the attestation report on the Corporation’s internal controls over financial reporting are included in Item 8. Financial Statements and Supplementary Data of this annual report on Form 10‑K.
Item 9B. Other Information
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
Item 10. Directors, Executive Officers and Corporate Governance
Information relating to Directors
For information regarding our executive officers, see Part I of this Annual Report on Form 10-K. Additional information required by this item is incorporated herein by reference to
“Election of Directors” from the Corporation’s definitive proxy statement for the
20192022 annual meeting of stockholders.
The Corporation has adopted a Code of Business Conduct and Ethics applicable to the Corporation’s directors, officers (including the Corporation’s principal executive officer and principal financial officer) and employees. The Code of Business Conduct and Ethics is available on the Corporation’s website. In the event that we amend or waive any of the provisions of the Code of Business Conduct and Ethics that relate to any element of the code of ethics definition enumerated in Item 406(b) of Regulation S‑K, we intend to disclose the same on the Corporation’s website at www.hess.com.
Information relating to the audit committee is incorporated herein by reference to “Election of Directors” from the Corporation’s definitive proxy statement for the 2019 annual meeting of stockholders.
Executive Officers of the Corporation
The following table presents information as of February 21, 2019 regarding executive officers of the Corporation:
Name | | Age | | Office Held* and Business Experience | | Year Individual Became an Executive Officer |
| | |
| | |
| | |
John B. Hess | | 64 | | Chief Executive Officer and Director | | 1983 |
| | | | 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. | | |
Gregory P. Hill | | 57 | | Chief Operating Officer, Executive Vice President and President, Exploration and Production | | 2009 |
| | | | Mr. Hill has been Chief Operating Officer since 2014 and President of the Corporation's worldwide Exploration and Production business since joining the Corporation in January 2009. Prior to joining the Corporation, Mr. Hill spent 25 years at Royal Dutch Shell and its affiliates in a variety of operations, engineering, technical and managerial roles in Asia-Pacific, Europe and the United States. | | |
Timothy B. Goodell | | 61 | | Senior Vice President, General Counsel and Corporate Secretary | | 2009 |
| | | | Mr. Goodell has been the Senior Vice President and General Counsel of the Corporation since 2009 and Corporate Secretary since 2016. Prior to joining the Corporation in 2009, he was a partner at the law firm of White & Case, LLP where he spent 25 years. | | |
John P. Rielly | | 56 | | Senior Vice President and Chief Financial Officer | | 2002 |
| | | | Mr. Rielly has been the Senior Vice President and Chief Financial Officer of the Corporation since 2004. 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 16 years. | | |
Andrew Slentz | | 57 | | Senior Vice President, Human Resources | | 2016 |
| | | | Mr. Slentz has been Senior Vice President, Human Resources of the Corporation since April 2016. Prior to joining the Corporation, 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. | | |
Richard Lynch | | 60 | | Senior Vice President, Technology and Services | | 2018 |
| | | | 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. Prior to joining Hess 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. | | |
Michael R. Turner | | 59 | | Senior Vice President, Global Production | | 2014 |
| | | | Mr. Turner has been Senior Vice President, Global Production of the Corporation since 2017. He previously served as Senior Vice President, Onshore. Prior to joining the Corporation in 2009, Mr. Turner spent 28 years with Royal Dutch Shell and its affiliates in a variety of production leadership positions around the world. | | |
Barbara Lowery-Yilmaz | | 62 | | Senior Vice President, Exploration | | 2014 |
| | | | 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. | | |
| *
| 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 5, 2018.
| |
Except for Mr. Lynch, Ms. Lowery-Yilmaz and Mr. Slentz, 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. Prior to joining the Corporation, Mr. Lynch served in senior positions at BP plc, most recently as Vice President Global Wells Organizations, overseeing all upstream activities associated with drilling and completion, intervention and well integrity. Ms. Lowery-Yilmaz served in senior executive positions in Exploration and Production at BP plc. Mr. Slentz served in senior executive positions in human resources at Peabody Energy and its affiliates.
Item 11. Executive Compensation
Information relating to executive compensation is incorporated herein by reference to
“Election of Directors—Executive Compensation and Other Information,” from the Corporation’s definitive proxy statement for the
20192022 annual meeting of stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information pertaining to security ownership of certain beneficial owners and management is incorporated herein by reference to
“Election of Directors—Ownership of Voting Securities by Certain Beneficial Owners” and “Election of Directors—Ownership of Equity Securities by Management” from the Corporation’s definitive proxy statement for the
20192022 annual meeting of stockholders.
See Equity Compensation Plans in Item 5. Market for the Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities for information pertaining to securities authorized for issuance under equity compensation plans.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information relating to this item is incorporated herein by reference to
“Election of Directors” from the Corporation’s definitive proxy statement for the
20192022 annual meeting of stockholders.
Item 14. Principal Accounting Fees and Services
Information relating to this item is incorporated herein by reference to
“Ratification of Selection of Independent Auditors” from the Corporation’s definitive proxy statement for the
20192022 annual meeting of stockholders.
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are made a part of this Annual Report on Form 10-K:
1. and 2. Financial statements and financial statement schedules
The financial statements filed as part of this Annual Report on Form 10‑K are listed in the accompanying index to financial statements and schedules in Item 8. Financial Statements and Supplementary Data. All other financial statement schedules required under SEC rules that are not included in this Annual Report on Form 10-K, are omitted either because they are not applicable or the required information is contained in Item 8. Financial Statements and Supplementary Data. The exhibits required to be filed pursuant to Item 15(b) of Form 10‑K are listed in the Exhibit Index filed herewith, which Exhibit Index is incorporated herein by reference.
| | | | | | | | |
| | |
| | |
| | |
| | |
| | |
| | Five-Year CreditExtension and Amendment Agreement, dated as of January 21, 2015, as amended and restated as of December 1, 2017, April13, 2021, to Credit Agreement among Hess Corporation, the subsidiariessubsidiary party thereto, the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent incorporated by reference to Exhibit 10(1) of Form 8-K of the Registrant, filed on December 7, 2017.April13, 2021. |
| | |
| | |
| | Prospectus Supplement, dated August 8, 2001, to Prospectus dated July 27, 2001 relating to Registrant’s 5.30% Notes due 2004, 5.90% Notes due 2006, 6.65% Notes due 2011 and 7.30% Notes due 2031, incorporated by reference to Registrant’s prospectus filed pursuant to Rule 424(b)(2) under the Securities Act of 1933, as amended, on August 9, 2001. |
| | |
| | |
| | |
| | |
| | |
| | | | | | | | | | | | | | | | | | | | Amendment No.2, dated as of October 4, 2021, to the Term Loan Agreement dated as of March 16, 2020, as amended, among Hess Corporation, the subsidiary party thereto, the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent incorporated by reference to Exhibit 10(1) of Form 8-K of the Registrant, filed on October 6, 2021. Other instruments defining the rights of holders of long-term debt of Registrant and its consolidated subsidiaries are not being filed since the total amount of securities authorized under each such instrument does not exceed 10% of the total assets of Registrant and its subsidiaries on a consolidated basis. Registrant agrees to furnish to the Securities and Exchange Commission a copy of any instruments defining the rights of holders of long‑term debt of Registrant and its subsidiaries upon request. | | | | | | | | | | 10(4)* | | Hess Corporation Pension Restoration Plan, dated January 19, 1990, incorporated by reference to Exhibit 10(9) of Form 10‑K of Registrant for the fiscal year ended December 31, 1989. (P) | | | | | | | | | | | | | | | Form of Performance Award Agreement under Registrant’s 2008 Long‑term Incentive Plan incorporated by reference to Exhibit 10(2) of Form 8‑K of Registrant filed on March 13, 2012.
| 10(10)*
| | | | | Form of Performance Award Agreement for the three-year period ending December 31, 2017 under Registrant’s Amended and Restated 2008 Long-term Incentive Plan, incorporated by reference to Exhibit 10(3) of Form 10-Q of Registrant for the three months ended March 31, 2015.
| 10(12)*
| | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 101(INS) | | Inline XBRL Instance Document | 101(SCH) | | Inline XBRL Schema Document | 101(CAL) | | Inline XBRL Calculation Linkbase Document | 101(LAB) | | Inline XBRL Labels Linkbase Document | 101(PRE) | | Inline XBRL Presentation Linkbase Document | 101(DEF) | | Inline XBRL Definition Linkbase Document | | 104 | | The cover page from the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2021 has been formatted in Inline XBRL. |
* These exhibits relate to executive compensation plans and arrangements.
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 21st1st day of February 2019.March 2022. HESS CORPORATION
(Registrant)
| | | | | | | | | | | | HESS CORPORATION (Registrant) | | By
| | /S/ JOHN P. RIELLY
| | By | | /S/ JOHN P. RIELLY | | | | (John P. Rielly) Senior
Executive Vice President and
Chief Financial Officer
| |
Each person whose signature appears below constitutes and appoints John B. Hess, Timothy B. Goodell and John P. Rielly or any of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and to perform each and every act and thing requisite and necessary to be done in and about the premises, as fully and to all intents and purposes as he or she might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. Signature
| | Title
| | Date
| | | | | | | | | | | | Signature | | Title | | Date |
| | | | /s/ John B. Hess John B. Hess
| | Director and
Chief Executive Officer
(Principal Executive Officer)
| | February 21, 2019
March 1, 2022 | | John B. Hess | | |
| | | | /s/ James H. Quigley James H. Quigley
| | Director and
Chairman of the Board
| | February 21, 2019
March 1, 2022 | | James H. Quigley | | | /s/ Rodney F. Chase
Rodney F. Chase
| | Director
| | February 21, 2019
| | | | /s/ Terrence J. Checki | | Director | | March 1, 2022 | | Terrence J. Checki | | Director
| | February 21, 2019
| | | | /s/ Leonard S. Coleman Jr. | | Director | | March 1, 2022 | | Leonard S. Coleman Jr. | | Director
| | February 21, 2019
| | | | /s/ Edith E. Holiday | | Director | | March 1, 2022 | | Edith E. Holiday | | Director
| | February 21, 2019
| | | | | | /s/ dr. Risa Lavizzo-Mourey Dr. Risa Lavizzo-Mourey
| | Director
| | February 21, 2019
| | | | /s/ Marc S. Lipschultz
| | Director | | March 1, 2022 | | Marc S. Lipschultz | | Director
| | February 21, 2019
| | | | | | /s/ David Mcmanus David McManus
Raymond J. McGuire | | Director | | February 21, 2019
March 1, 2022 | | Raymond J. McGuire | | | | | | | | /s/ dr. Kevin O. Meyers David McManus | | Director | | March 1, 2022 | | David McManus | | | | | | | /s/ Dr. Kevin O. Meyers | | Director | | February 21, 2019
March 1, 2022 | | Dr. Kevin O. Meyers | | | | | | | | | /s/ Karyn F. Ovelmen | | Director | | March 1, 2022 | /s/ Fredric G. Reynolds
Fredric G. Reynolds
Karyn F. Ovelmen | | Director
| | February 21, 2019
| | | | /s/ John P. Rielly John P. Rielly
| | SeniorExecutive Vice President and Chief
Financial Officer
(Principal Financial and Accounting Officer)
| | February 21, 2019
March 1, 2022 | | John P. Rielly | | |
| | | | /s/ William G. Schrader | | Director | | March 1, 2022 | | William G. Schrader | | Director
| | February 21, 2019
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