HESS CORPORATION The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Form 10-K in Item 8, and the information set forth in Risk Factors under Item 1A. The following Management's Discussion and Analysis of Financial Condition and Results of Operations omits certain discussions of our financial condition and results of operations for the year endedDecember 31, 2021 compared with the year endedDecember 31, 2020 , which can be found in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2021 Annual Report on Form 10-K, which was filed with theSecurities and Exchange Commission onMarch 1, 2022 , and such comparisons are incorporated herein by reference. Index Overview Consolidated Results of Operations Liquidity and Capital Resources Critical Accounting Policies and Estimates
Overview
Hess Corporation is a global E&P company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located inthe United States ,Guyana , theMalaysia /Thailand Joint Development Area (JDA) andMalaysia . We conduct exploration activities primarily offshoreGuyana , in theU.S. Gulf of Mexico , and offshore Suriname andCanada . At the Stabroek Block (Hess 30%), offshoreGuyana , we and our partners have discovered a significant resource base and are executing a multi-phased development of the block. We currently plan to have six FPSOs with an aggregate expected production capacity of more than 1.2 million gross bopd on the Stabroek Block in 2027, and the potential for up to ten FPSOs to develop the current discovered recoverable resource base. Our Midstream operating segment, which is comprised ofHess Corporation's approximate 41% consolidated ownership interest in Hess Midstream LP atDecember 31, 2022 , provides fee-based services, including gathering, compressing and processing natural gas and fractionating NGL; gathering, terminaling, loading and transporting crude oil and NGL; storing and terminaling propane, and water handling services primarily in the Bakken shale play in theWilliston Basin area ofNorth Dakota .
Climate Change, Energy Transition and Our Strategy
We believe climate risks can and should be addressed while at the same time meeting the growing demand for affordable and secure energy, which is essential to ensure a just and orderly energy transition that aligns with the United Nations Sustainable Development Goals. The IEA's 2022 World Energy Outlook provides three scenarios of global energy demand in 2040 based on varying levels of global response to climate change. Under all of the IEA scenarios, oil and natural gas are expected to be needed for decades to come and we expect that significant investment will be required to meet the world's projected growing energy needs, both in renewable energy sources and in oil and gas. Our strategy is to grow our resource base, have a low cost of supply and sustain cash flow growth. Our strategy aligns with the energy transition needed to reach the energy-relatedSustainable Development Goals of theUnited 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 itsEnvironmental, Health and Safety Committee , is actively engaged in overseeingHess' sustainability practices so that sustainability risks and opportunities are taken into account when making strategic decisions. Our Board'sCompensation and Management Development Committee has tied executive compensation to advancing our environmental, health and safety goals. We also have an executive led task force to guide our medium and longer term climate strategy. We have five year GHG reduction targets for 2025, which are to reduce operated Scope 1 and 2 GHG emissions intensity by approximately 50% and methane emissions intensity by approximately 50%, both from 2017 levels. InJanuary 2022 , we announced our plan to reduce routine flaring atHess operated assets to zero by the end of 2025. InDecember 2022 , we announced an agreement with the Government ofGuyana to purchase 37.5 million REDD+ carbon credits, including current and future issuances, for a minimum of$750 million from 2022 through 2032 to prevent deforestation and support sustainable development inGuyana . This agreement adds to the Corporation's ongoing emissions reduction efforts and is an important part of our commitment to achieve net zero Scope 1 and 2 greenhouse gas emissions on a net equity basis by 2050. 25 -------------------------------------------------------------------------------- Our business planning includes actions we expect to undertake to continue reducing our carbon footprint consistent with our targets. We also conduct annual scenario planning as a methodology to assess our portfolio's resilience to differing scenarios of energy supply and demand over the longer term, and to inform our understanding of future risks and opportunities in relation to the potential evolution of energy demand, energy mix, the emergence of new technologies, and possible changes by policymakers with respect to greenhouse gas emissions and climate change.
2022 Return of Capital Highlights and 2023 Outlook
Following the startup of the Liza Phase 2 project inFebruary 2022 , we repaid the remaining$500 million outstanding under our$1.0 billion term loan, and inMarch 2022 , we announced a 50% increase to our quarterly dividend on common stock. In 2022, we repurchased approximately 5.4 million shares of common stock for$650 million . Our E&P capital and exploratory expenditures are projected to be approximately$3.7 billion in 2023, up from$2.7 billion in 2022. Capital investment for our Midstream operations is expected to be approximately$225 million , compared with$232 million in 2022. Oil and gas net production in 2023 is forecast to be in the range of 355,000 boepd to 365,000 boepd, up from 327,000 boepd in 2022, pro forma for assets sold. For 2023, we have hedged 80,000 bopd with WTI put options with an average monthly floor price of$70 per barrel, and 10,000 bopd with Brent put options with an average monthly floor price of$75 per barrel.
Consolidated Results
Net income attributable toHess Corporation was$2,096 million in 2022 compared with$559 million in 2021. Excluding items affecting comparability of earnings between periods summarized on page 29 , adjusted net income was$2,176 million in 2022 compared with$677 million in 2021. Net production averaged 344,000 boepd in 2022 and 315,000 boepd in 2021. The average realized crude oil price, including the effect of hedging, was$85.76 per barrel in 2022 and$60.08 per barrel in 2021. Total proved reserves were 1,256 million boe and 1,309 million boe atDecember 31, 2022 andDecember 31, 2021 , respectively.
Significant 2022 Activities
The following is an update of significant E&P activities during 2022:
E&P assets:
•In North Dakota, net production from the Bakken shale play averaged 154,000 boepd in 2022 (2021: 156,000 boepd). Net production was lower in 2022 primarily due to unplanned production shut-ins caused by severe winter weather partially offset by increased wells on-line. We drilled 78 wells and brought 69 wells on production in 2022, bringing the total operated production wells to 1,664 atDecember 31, 2022 . Prior to COVID-19, we were operating six rigs in the Bakken, but reduced the rig count to one inMay 2020 in response to the sharp decline in crude oil prices. We added a second operated rig in the Bakken inFebruary 2021 , a third operated rig inSeptember 2021 and a fourth operated rig inJuly 2022 . During 2023, we plan to operate four rigs, drill approximately 110 wells and bring approximately 110 wells on production. We forecast net production from the Bakken to be in the range of 165,000 boepd to 170,000 boepd in 2023. •In theGulf of Mexico , net production averaged 31,000 boepd in 2022 (2021: 45,000 boepd). Net production was lower in 2022 primarily due to field decline and unplanned downtime at the Tubular Bells, Penn State and Llano Fields. For 2023, net production from theGulf of Mexico is expected to be approximately 30,000 boepd. •At the Stabroek Block (Hess 30%), offshoreGuyana , net production from the Liza Destiny and Unity FPSOs totaled 78,000 bopd in 2022 (2021: 30,000 bopd). The Liza Unity FPSO, which commenced production inFebruary 2022 , reached its production capacity of approximately 220,000 gross bopd inJuly 2022 . In the third quarter of 2022, we used the remainder of our previously generatedGuyana net operating loss carryforwards and started incurring a current income tax liability. Pursuant to the contractual arrangements of the petroleum agreement, a portion of gross production from the block, separate from the joint venture partners' (Co-Venturers) cost oil and profit oil entitlement, is used to satisfy the Co-Venturers' income tax liability. This portion of gross production, referred to as tax barrels, is recognized as Co-Venturer production volumes and estimated proved reserves. Net production fromGuyana in 2022 included 7,000 bopd of tax barrels (2021: 0 bopd). For 2023, we forecast net production to be approximately 100,000 bopd, which includes approximately 10,000 bopd of tax barrels.
The third development, Payara, was sanctioned in 2020 and will utilize the Prosperity FPSO, which will have an expected production capacity of approximately 220,000 gross bopd, with first production expected by the end of 2023. Ten drill centers with a total of 41 wells are planned, including 20 production wells and 21 injection wells.
A fourth development, Yellowtail, was sanctioned inApril 2022 and will utilize the ONEGUYANA FPSO with an expected production capacity of approximately 250,000 gross bopd, with first production expected in 2025. Six drill centers are planned with up to 26 production wells and 25 injection wells. 26 -------------------------------------------------------------------------------- A fifth development, Uaru, was submitted to the Government ofGuyana for approval in the fourth quarter of 2022. Pending government approvals and project sanctioning, the project is expected to have a production capacity of approximately 250,000 gross bopd, with first oil anticipated at the end of 2026. In addition to the first five developments, planning is underway for additional FPSOs. The ultimate sizing and order of these potential developments will be a function of further exploration and appraisal drilling. In 2022, the operator drilled a total of ten successful exploration and appraisal wells that encountered hydrocarbons and one unsuccessful exploration well, Banjo-1, for which the well costs were expensed. Subsequent toDecember 31, 2022 , the operator completed one successful exploration well that encountered hydrocarbons, and one unsuccessful exploration well, Fish/Tarpon-1, for which well costs incurred throughDecember 31, 2022 were expensed. See Note 20, Subsequent Events in the Notes to Consolidated Financial Statements.
In 2023, the operator plans to utilize six drillships to drill approximately ten exploration and appraisal wells in addition to development wells for the sanctioned developments.
•In the Gulf ofThailand , net production from Block A18 of the JDA averaged 38,000 boepd in 2022 (2021: 36,000 boepd), including contribution from unitized acreage inMalaysia , while net production fromNorth Malay Basin averaged 26,000 boepd in 2022 (2021: 25,000 boepd). In 2023, we forecast net production fromNorth Malay Basin and JDA combined to be in the range of 60,000 boepd to 65,000 boepd. •In Libya, we completed the sale of our interest in the Waha Concession in November for net proceeds of$150 million and recognized a pre-tax gain of$76 million ($76 million after income taxes). Net production fromLibya was 17,000 boepd in 2022.
The following is an update of significant Midstream activities during 2022:
•InApril 2022 , Hess Midstream completed an underwritten public offering of approximately 10.2 million Class A shares held byHess and GIP. As a result of this transaction,Hess received net proceeds of$146 million . •Concurrent with theApril 2022 public offering, HESM Opco repurchased approximately 13.6 million Class B units held byHess and GIP for$400 million , withHess receiving net proceeds of$200 million . HESM Opco issued$400 million in aggregate principal amount of 5.500% fixed-rate senior unsecured notes due 2030 in a private offering to repay borrowings under its revolving credit facility used to finance the repurchase. 27 --------------------------------------------------------------------------------
Liquidity and Capital and Exploratory Expenditures
AtDecember 31, 2022 , cash and cash equivalents were$2,486 million (2021:$2,713 million ) and consolidated debt was$8,281 million (2021:$8,458 million ), which includes Hess Midstream debt that is nonrecourse toHess Corporation of$2,886 million atDecember 31, 2022 (2021:$2,564 million ).
Capital and exploratory expenditures were as follows (in millions):
2022 2021 2020
E&P Capital and Exploratory Expenditures:United States North Dakota$ 807 $ 522 $ 661 Offshore and other 224 103 258 Total United States 1,031 625 919 Guyana 1,345 1,016 743 Malaysia and JDA 275 154 99 Other (a) 70 34 25
Exploration Expenses Charged to Income Included Above:
$ 107 $ 90 $ 91 International 25
41 17
Total Exploration Expenses Charged to Income included above
Midstream Capital Expenditures: Midstream Capital Expenditures$ 232 $ 183 $ 253
(a)Other includes our interests in
In 2023, we project our E&P capital and exploratory expenditures will be
approximately
Consolidated Results of Operations
Results by Segment:
The after-tax income (loss) by major operating activity is summarized below:
2022 2021 2020
(In
millions, except per share amounts)
Net Income (Loss) Attributable to
$ 2,396 $ 770 $ (2,841) Midstream 269 286 230 Corporate, Interest and Other (569) (497) (482) Total$ 2,096
$ 6.77
(a)Calculated as net income (loss) attributable to
In the following discussion and elsewhere in this report, the financial effects
of certain transactions are disclosed on an after-tax basis. Management reviews
segment earnings on an after-tax basis and uses after-tax amounts in its review
of variances in segment earnings. Management believes that after-tax amounts are
a preferable method of explaining variances in earnings, since they show the
entire effect of a transaction rather than only the pre-tax amount. After-tax
amounts are determined by applying the income tax rate in each tax jurisdiction
to pre-tax amounts.
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Items Affecting Comparability of Earnings Between Periods:
The following table summarizes items of income (expense) that are included in net income (loss) and affect comparability of earnings between periods. The items in the table below are explained on pages 34 through 36 .
2022 2021 2020
(In millions)
Items Affecting Comparability of Earnings Between Periods, After
Income Taxes:
Exploration and Production $ 22 $ (118) $ (2,198)
Midstream - - -
Corporate, Interest and Other (102) - (1)
Total $ (80) $ (118) $ (2,199)
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 52 . The items in the table below are explained
on pages 34 through 36 .
Before Income Taxes
2022 2021 2020
(In millions)
Gains on asset sales, net $ 98 $ 29 $ 79
Marketing, including purchased oil and gas - - (53)
Operating costs and expenses - - (20)
Exploration expenses, including dry holes and lease impairment -
- (153)
General and administrative expenses (124) - (6)
Impairment and other (54) (147) (2,126)
Total Items Affecting Comparability of Earnings Between Periods, Pre-Tax
$ (80)
Reconciliations of GAAP and Non-GAAP Measures:
The following table reconciles reported net income (loss) attributable toHess Corporation and adjusted net income (loss) attributable toHess Corporation : 2022 2021 2020
(In millions)
Adjusted Net Income (Loss) Attributable to
$ 2,096
(80) (118) (2,199)
Adjusted Net Income (Loss) Attributable to
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:
2022 2021 2020
(In millions)
Net cash provided by operating activities before changes in
operating assets and liabilities:
Net cash provided by (used in) operating activities $ 3,944 $ 2,890 $ 1,333
Changes in operating assets and liabilities 1,177 101 470
Net cash provided by (used in) operating activities before changes in operating assets and liabilities
$ 5,121
Adjusted net income (loss) attributable to
.
Management uses adjusted net income (loss) to evaluate the Corporation's
operating performance and believes that investors' understanding of our
performance is enhanced by disclosing this measure, which excludes certain items
that management believes are not directly related to ongoing operations and are
not indicative of future business trends and operations.
Net cash provided by (used in) operating activities before changes in operating
assets and liabilities presented in this report is a non-GAAP measure, which we
define as reported net cash provided by (used in) operating activities excluding
changes in operating assets and liabilities. Management uses net cash provided
by (used in) operating activities before changes in operating assets and
liabilities to evaluate the Corporation's ability to internally fund capital
expenditures, pay dividends and service debt and believes that
29
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investors' understanding of our ability to generate cash to fund these items is
enhanced by disclosing this measure, which excludes working capital and other
movements that may distort assessment of our performance between periods.
These measures are not, and should not be viewed as, substitutes for GAAP net income (loss) and net cash provided by (used in) operating activities.
Comparison of Results
Exploration and Production
Following is a summarized statement of income for our E&P operations:
2022 2021 2020
(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues $ 11,324 $ 7,473 $ 4,667
Gains on asset sales, net 76 29 79
Other, net 102 64 31
Total revenues and non-operating income 11,502 7,566 4,777
Costs and Expenses
Marketing, including purchased oil and gas 3,394 2,119 1,067
Operating costs and expenses 1,186 965 895
Production and severance taxes 255 172 124
Midstream tariffs 1,193 1,094 946
Exploration expenses, including dry holes and lease impairment 208
162 351
General and administrative expenses 224 191 206
Depreciation, depletion and amortization 1,520 1,361 1,915
Impairment and other 54 147 2,126
Total costs and expenses 8,034 6,211 7,630
Results of Operations Before Income Taxes 3,468 1,355 (2,853)
Provision (benefit) for income taxes 1,072 585 (12)
Net Income (Loss) Attributable to Hess Corporation $ 2,396
Excluding the E&P items affecting comparability of earnings between periods in
the table on page 34 , the changes in E&P results are primarily attributable
to changes in selling prices, production and sales volumes, marketing expenses,
cash operating costs, Midstream tariffs, DD&A expense, exploration expenses and
income taxes, as discussed below.
30
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Selling Prices: Average worldwide realized crude oil selling prices, including
hedging, were 43% higher in 2022 compared with the prior year, primarily due to
the increase in Brent and WTI crude oil prices. In addition, realized worldwide
selling prices for NGL increased in 2022 by 15% and worldwide natural gas prices
increased in 2022 by 23%, compared with the prior year. In total, higher
realized selling prices improved after-tax results by approximately
$1,490 million , compared with 2021. Our average selling prices were as follows:
2022 2021 2020
Average Selling Prices (a)
Crude Oil - Per Barrel (Including Hedging)
United States
North Dakota $ 81.06 $ 55.57 $ 42.63
Offshore 81.38 60.09 45.92
Total United States 81.14 56.64 43.56
Guyana 89.86 68.57 46.41
Malaysia and JDA 89.77 71.00 37.91
Other (b) 93.67 66.39 51.37
Worldwide 85.76 60.08 44.28
Crude Oil - Per Barrel (Excluding Hedging)
United States
North Dakota $ 91.26 $ 59.90 $ 33.87
Offshore 91.51 64.77 36.55
Total United States 91.32 61.05 34.63
Guyana 96.52 71.07 37.40
Malaysia and JDA 89.77 71.00 37.91
Other (b) 101.92 69.25 43.42
Worldwide 94.15 63.90 35.52
Natural Gas Liquids - Per Barrel
United States
North Dakota $ 35.09 $ 30.74 $ 11.29
Offshore 35.24 26.40 8.94
Worldwide 35.09 30.40 11.10
Natural Gas - Per Mcf
United States
North Dakota $ 5.50 $ 4.08 $ 1.27
Offshore 6.21 3.25 1.23
Total United States 5.66 3.82 1.26
Malaysia and JDA 5.62 5.15 4.47
Other (b) 5.93 3.40 3.41
Worldwide 5.64 4.60 2.98
(a)Selling prices in the United States and Guyana are adjusted for certain
processing and distribution fees included in Marketing expenses. Excluding these
fees worldwide selling prices for 2022 would be $89.50 per barrel for crude oil
(including hedging) (2021: $64.25 ; 2020: $47.54 ), $97.89 per barrel for crude
oil (excluding hedging) (2021: $68.07 ; 2020: $38.78 ), $35.44 per barrel for NGL
(2021: $30.61 ; 2020: $11.29 ) and $5.76 per mcf for natural gas (2021: $4.71 ;
2020: $3.11 ).
(b)Other includes our interests in Libya (sold in November 2022 ) and Denmark
(sold in August 2021 ).
Crude oil hedging activities in 2022 were a net loss of $585 million before and
after income taxes, and a net loss of $243 million before and after income taxes
in 2021. For 2023, we have hedged 80,000 bopd with WTI put options with an
average monthly floor price of $70 per barrel, and 10,000 bopd with Brent put
options with an average monthly floor price of $75 per barrel. We expect option
premium amortization, which will be reflected in realized selling prices, to
reduce our results by approximately $30 million in the first quarter and by
approximately $140 million for the full year 2023.
31
--------------------------------------------------------------------------------Production Volumes: Our daily worldwide net production was as follows:
2022 2021 2020
(In thousands)
Crude Oil - Barrels
United States
North Dakota 75 80 107
Offshore (a) 22 29 38
Total United States 97 109 145
Guyana 78 30 20
Malaysia and JDA 4 3 4
Other (b) 15 21 9
Total 194 163 178
Natural Gas Liquids - Barrels
United States
North Dakota 53 49 56
Offshore (a) 2 4 5
Total United States 55 53 61
Natural Gas - Mcf
United States
North Dakota 156 162 180
Offshore (a) 44 72 76
Total United States 200 234 256
Malaysia and JDA 360 347 291
Other (b) 10 10 7
Total 570 591 554
Barrels of Oil Equivalent 344 315 331
Crude oil and natural gas liquids as a share of total production
72 % 69 % 72 %
(a)In 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 .
(b)Other includes our interests in Libya (sold in November 2022 ) and Denmark
(sold in August 2021 ). Net production from Libya was 17,000 boepd for 2022
(2021: 20,000 boepd; 2020: 4,000 boepd). Net production from Denmark was 3,000
boepd for 2021 and 6,000 boepd for 2020.
In 2023, we expect net production to be in the range of 355,000 boepd to 365,000
boepd, compared with 2022 net production of 327,000 boepd, proforma for assets
sold.
Net production variances related to 2022 and 2021 are summarized as follows:
United States :North Dakota net production was lower in 2022 by 2,000 boepd primarily due to unplanned production shut-ins caused by severe winter weather partially offset by increased wells on-line. Total offshore net production was lower in 2022 primarily due to field decline and unplanned downtime at the Tubular Bells, Penn State, and Llano Fields. International: Net production inGuyana was higher in 2022 primarily due to production ramp up from the Liza Unity FPSO, which commenced production inFebruary 2022 and reached its expected production capacity of 220,000 gross bopd inJuly 2022 . Net production fromGuyana included 7,000 bopd of tax barrels in 2022. There were no tax barrels in 2021. 32 --------------------------------------------------------------------------------
Sales Volumes: Higher sales volumes in 2022 increased after-tax earnings by
approximately
2022 2021 2020
(In thousands)
Crude oil - barrels (a) 69,679 63,540 60,924
Natural gas liquids - barrels 19,843 19,406 22,397
Natural gas - mcf 208,001 215,589 202,917
Barrels of Oil Equivalent 124,189 118,878 117,141
Crude oil - barrels per day 191 174 167
Natural gas liquids - barrels per day 54 53 61
Natural gas - mcf per day 570 591
554
Barrels of Oil Equivalent Per Day 340 326
320
(a)Sales volumes in 2021 include 4.2 million barrels of crude oil that were
stored on VLCCs at
Marketing, including purchased oil and gas (Marketing expense): Marketing expense is mainly comprised of costs to purchase crude oil, NGL and natural gas from our partners inHess operated wells or other third parties, primarily in theU.S. , and transportation and other distribution costs forU.S. andGuyana marketing activities. Marketing expense was higher in 2022 compared to 2021 primarily due to higher third party crude oil volumes purchased and higher prices paid for purchased volumes. Marketing expense in 2021 included$173 million related to the cost of 4.2 million barrels of crude oil stored on two VLCCs in 2020 that were sold in 2021. Cash Operating Costs: Cash operating costs consist of operating costs and expenses, production and severance taxes and E&P general and administrative expenses. Cash operating costs increased primarily due to the production ramp up inGuyana from the Liza Unity FPSO, higher production and severance taxes associated with higher crude oil prices, increased maintenance activity inNorth Dakota , and higher workover costs in theGulf of Mexico . On a per-unit basis, cash operating costs in 2022 reflect the higher costs partially offset by the impact of the higher production volumes compared with 2021. Midstream Tariffs Expense: Tariffs expense increased from 2021, primarily due to higher throughput volumes and minimum volume commitments in 2022. In 2023, we estimate Midstream tariffs expense to be in the range of$1,230 million to$1,250 million . DD&A Expense: DD&A expense and per-unit rates were higher in 2022 compared with 2021 primarily due to higher production fromGuyana following the startup of Liza Phase 2 inFebruary 2022 . Unit Costs: Unit cost per boe information is based on total E&P net production volumes and excludes items affecting comparability of earnings as disclosed on page 34 . Actual and forecast unit costs are as follows: Actual Forecast range 2022 2021 2020 2023 Cash operating costs (a)$ 13.28 $ 11.55 $ 9.91 $13.50 -$14.50 DD&A expense (b) 12.13 11.84 15.80$13.00 -$14.00 Total Production Unit Costs$ 25.41 $ 23.39 $ 25.71 $26.50 -$28.50
(a)Cash operating costs per boe, excluding
(b)DD&A expense per boe, excluding
Exploration Expenses: Exploration expenses, including items affecting comparability of earnings described below, were as follows:
2022 2021 2020
(In millions)
Exploratory dry hole costs (a) $ 56 $ 11 $ 192
Exploration lease impairment 20 20 51
Geological and geophysical expense and exploration overhead 132 131 108
$ 208 $ 162 $ 351
(a)Dry hole costs primarily related to the Fish/Tarpon-1 well and Banjo-1 well
in 2022 and the Koebi-1 well in 2021 at 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).
In 2023, we estimate exploration expenses, excluding dry hole expense, to be in
the range of
33
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Income Taxes: In 2022, E&P income tax expense was $1,072 million compared with
income tax expense of $585 million in 2021, primarily due to higher pre-tax
income in Libya and Guyana . Income tax expense from Libya operations was $527
million in 2022 compared with $436 million in 2021. We are generally not
recognizing deferred tax benefit or expense in certain countries, primarily the
United States (non-Midstream) and Malaysia , while we maintain valuation
allowances against net deferred tax assets in these jurisdictions in accordance
with the requirements of GAAP.
On August 16, 2022 the United States enacted the Inflation Reduction Act of
2022, which includes a 15% book-income alternative minimum tax on corporations
with average adjusted financial statement income over $1 billion for any 3-year
period ending with 2022 or later and a 1% excise tax on the fair market value of
stock that is repurchased by publicly traded U.S. corporations. The alternative
minimum tax and the excise tax are effective in taxable years beginning after
December 31, 2022 . The alternative minimum tax is designed to be a temporary
acceleration of cash tax as amounts paid under such regime are creditable
against the regular U.S. corporate income tax liability in following tax years.
The impact of the excise tax provision will be reflected as a component of the
cost of the repurchased shares and will be dependent on the extent of share
repurchases made in future periods. We continue to evaluate the corporate
alternative minimum tax and its potential impact on our future U.S. tax expense,
cash taxes, and effective tax rate, as well as any other impacts the IRA may
have on our financial position and results of operations.
Actual effective tax rates are as follows:
2022 2021 2020
% % %
Effective income tax benefit (expense) rate (31) (43)
-
Adjusted effective income tax benefit (expense) rate (a) (19) (15)
(5)
(a)Excludes any contribution from
In 2023, we estimate E&P income tax expense, excluding items affecting
comparability of earnings between periods, to be in the range of
Items Affecting Comparability of Earnings Between Periods: Reported E&P earnings include the following items affecting comparability of income (expense):
Before Income Taxes After Income Taxes
2022 2021 2020 2022 2021 2020
(In millions)
Impairment and other $ (54) $ (147) $ (2,126) $ (54) $ (147) $ (2,049)
Dry hole and lease impairment expenses - - (152) - - (150)
Crude oil inventories write-down - - (53) - - (52)
Severance costs - - (26) - - (26)
Gains on asset sales, net 76 29 79 76 29 79
$ 22 $ (118) $ (2,278) $ 22 $ (118) $ (2,198) The pre-tax amounts of E&P items affecting comparability of income (expense) as presented in the Statement of Consolidated Income are as follows:
Before Income Taxes
2022 2021 2020
(In millions)
Gains on asset sales, net $ 76 $ 29 $ 79
Marketing, including purchased oil and gas - - (53)
Operating costs and expenses - - (20)
Exploration expenses, including dry holes and lease impairment - - (153)
General and administrative expenses - - (5)
Impairment and other (54) (147) (2,126)
$ 22 $ (118) $ (2,278)
2022:
•Gains on asset sales, net: We recognized a pre-tax gain of
•Impairment and other: We recorded charges of$28 million ($28 million after income taxes) that resulted from updates to our estimated abandonment liabilities for non-producing properties in theGulf of Mexico and$26 million ($26 million after 34 --------------------------------------------------------------------------------
income taxes) related to the Penn State Field in the
2021:
•Gains on asset sales, net: We recognized a pre-tax gain of
•Impairment and other: We recorded a charge of$147 million ($147 million after income taxes) in connection with estimated abandonment obligations in the WestDelta Field in theGulf of Mexico . These abandonment obligations were assigned to us as a former owner after they were discharged fromFieldwood as part ofFieldwood's approved bankruptcy plan. 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 atNorth Malay Basin inMalaysia , the SouthArne Field inDenmark , and the Stampede and Tubular Bells Fields in theGulf 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 theGulf 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
•Gains on asset sales, net: We recorded a pre-tax gain of$79 million ($79 million after income taxes) associated with the sale of our 28% working interest in the Shenzi Field in the deepwaterGulf of Mexico .
Midstream
Following is a summarized statement of income for our Midstream operations:
2022 2021 2020
(In millions)
Revenues and Non-Operating Income
Sales and other operating revenues $ 1,273 Other, net 8 10 10 Total revenues and non-operating income 1,281 1,214 1,102 Costs and Expenses Operating costs and expenses 280 289 338 General and administrative expenses 23 22 21 Depreciation, depletion and amortization 181 166 157 Interest expense 150 105 95 Total costs and expenses 634 582 611 Results of Operations Before Income Taxes 647 632 491 Provision (benefit) for income taxes 27 15 7 Net income (loss) 620 617 484
Less: Net income (loss) attributable to noncontrolling interests 351
331 254
Net Income (Loss) Attributable to Hess Corporation $ 269 Sales and other operating revenues increased from 2021 primarily due to higher throughput volumes and minimum volume commitments. Operating costs and expenses decreased primarily due to a planned maintenance turnaround at theTioga Gas Plant in 2021, partially offset by increased operating and maintenance expenditures on expanded infrastructure in 2022. DD&A expense increased from 2021 primarily due to additional assets placed in service. Interest expense increased from 2021 primarily due to the$400 million of 5.500% fixed-rate senior unsecured notes issued inApril 2022 and the$750 million of 4.250% fixed-rate senior unsecured notes issued inAugust 2021 . 35 --------------------------------------------------------------------------------
Excluding items affecting comparability of earnings, we estimate net income
attributable to
Corporate, Interest and Other
The following table summarizes Corporate, Interest and Other expenses:
2022 2021 2020
(In millions)
Corporate and other expenses (excluding items affecting
comparability) $ 124 $ 121 $ 114
Interest expense 353 376 373
Less: Capitalized interest (10) - -
Interest expense, net 343 376 373
Corporate, Interest and Other expenses before income taxes 467 497 487
Provision (benefit) for income taxes - - (6)
Corporate, Interest and Other expenses after income taxes 467 497 481
Items affecting comparability of earnings between periods, after income taxes
102 - 1
Total Corporate, Interest and Other Expenses After Income Taxes
Corporate and other expenses, excluding items affecting comparability, were higher in 2022 compared to 2021 primarily due to higher legal and professional fees partially offset by higher interest income. Interest expense, net was lower in 2022 compared to 2021 due to the repayment of the Corporation's$1.0 billion term loan, and capitalized interest that commenced upon sanctioning of the Yellowtail development inGuyana inApril 2022 . In 2023, after-tax Corporate and other expenses, excluding items affecting comparability of earnings between periods, are estimated to be in the range of$120 million to$130 million . Interest expense, net is estimated to be in the range of$305 million to$315 million in 2023. Items Affecting Comparability of Earnings Between Periods: Corporate, Interest and Other results included the following items affecting comparability of income (expense): 2022: •Gains on asset sales, net: We recorded a pre-tax gain of$22 million ($22 million after income taxes) associated with the sale of real property related to our former downstream business. •Litigation costs: We incurred pre-tax charges totaling$124 million ($124 million after income taxes) for litigation related costs associated with our former downstream business,HONX, Inc. , which are included in General and administrative expenses in the Statement of Consolidated Income. See Note 17, Guarantees, Contingencies and Commitments and Note 20, Subsequent Events in the Notes to Consolidated Financial Statements.
2020:
•Severance costs: We incurred a pre-tax charge of
Liquidity and Capital Resources
The following table sets forth certain relevant measures of our liquidity and
capital resources at
2022 2021
(In millions, except ratio)
Cash and cash equivalents (a) $ 2,486 $ 2,713
Current portion of long-term debt 3 517
Total debt (b) 8,281 8,458
Total equity 8,496 7,026
Debt to capitalization ratio for debt covenants (c) 36.1 % 42.3 %
(a)Includes $4 million of cash attributable to our Midstream Segment at
December 31, 2022 (2021: $2 million ) of which, $3 million is held by Hess
Midstream LP at December 31, 2022 (2021: $2 million ).
(b)Includes $2,886 million of debt outstanding from our Midstream Segment at
December 31, 2022 (2021: $2,564 million ) that is non-recourse to Hess
Corporation .
(c)Total Consolidated Debt of Hess Corporation (including finance leases and
excluding Midstream non-recourse debt) as a percentage of Total Capitalization
of Hess Corporation as defined under Hess Corporation's revolving credit
facility financial covenants. Total Capitalization excludes the impact of
noncash impairment charges and non-controlling interests. See Note 7, Debt in
the Notes to Consolidated Financial Statements.
36
--------------------------------------------------------------------------------Cash Flows
The following table sets forth a summary of our cash flows:
2022 2021 2020
(In millions)
Net cash provided by (used in):
Operating activities $ 3,944 $ 2,890 $ 1,333
Investing activities (2,555) (1,325) (1,707)
Financing activities (1,616) (591) 568
Net Increase (Decrease) in Cash and Cash Equivalents $ (227) $ 974 Operating Activities: Net cash provided by operating activities was$3,944 million in 2022 (2021:$2,890 million ), while net cash provided by operating activities before changes in operating assets and liabilities was$5,121 million in 2022 (2021:$2,991 million ). Net cash provided by operating activities before changes in operating assets and liabilities increased from 2021 primarily due to higher realized selling prices and higher sales volumes. Changes in operating assets and liabilities in 2022 reduced net cash provided by operating activities by$1,177 million (2021:$101 million ) reflecting payments of approximately$470 million for accrued Libyan income tax and royalties atDecember 31, 2021 , premiums paid for crude oil hedge contracts, payments for abandonment activities, and the purchase of REDD+ carbon credits. Investing Activities: Additions to Property, Plant and Equipment were$2,725 million in 2022 (2021:$1,747 million ). The increase is primarily due to higher drilling and development activities inGuyana , the Bakken,Malaysia and JDA, and theGulf of Mexico . Proceeds from asset sales were$178 million in 2022 (2021:$427 million ). Financing Activities: In 2022, we paid$630 million for settled common stock repurchases (2021: nil) and$465 million for common stock dividends (2021:$311 million ). In 2021, we repaid$500 million of our$1 billion term loan, and in 2022, we repaid the remaining$500 million . In 2022, we received net proceeds of$146 million from the public offering of Class A shares in Hess Midstream LP (2021:$178 million ). Borrowings in 2022 resulted from the issuance by HESM Opco of$400 million of 5.500% fixed-rate senior unsecured notes due 2030 while borrowings in 2021 related to the issuance by HESM Opco of$750 million of 4.250% fixed-rate senior unsecured notes due 2030. Net cash outflows to noncontrolling interests were$510 million in 2022 (2021:$664 million ).
Future Capital Requirements and Resources
AtDecember 31, 2022 , we had$2.48 billion in cash and cash equivalents, excluding Midstream, and total liquidity, including available committed credit facilities, of approximately$5.7 billion . We plan to return up to 75% of our annual adjusted free cash flow (defined as net cash provided by operating activities less capital expenditures and adjusted for debt repayments and net Midstream financing activities) to shareholders through dividends and common stock repurchases. InMarch 2022 , we announced a 50% increase to our quarterly dividend on common stock, and in 2022, we repurchased approximately 5.4 million shares of common stock for$650 million ($20 million was paid subsequent toDecember 31, 2022 ). AtDecember 31, 2022 , we have fully utilized our Board authorized common stock repurchase program. Net production in 2023 is forecast to be in the range of 355,000 boepd to 365,000 boepd, and we expect our 2023 E&P capital and exploratory expenditures will be approximately$3.7 billion , up from$2.7 billion in 2022. In 2023, based on current forward strip crude oil prices, we expect cash flow from operating activities and cash and cash equivalents atDecember 31, 2022 will be sufficient to fund our capital investment and capital return programs. Depending on market conditions, we may take any of the following steps, or a combination thereof, to improve our liquidity and financial position: reduce the planned capital program and other cash outlays, including dividends, pursue asset sales, borrow against our committed revolving credit facility, or issue debt or equity securities. 37 --------------------------------------------------------------------------------
The table below summarizes the capacity, usage, and available capacity of our
borrowing and letter of credit facilities at
Letters of
Credit Total Available
Expiration Date Capacity Borrowings Issued Used Capacity
(In millions)
Hess Corporation
Revolving credit facility July 2027 $ 3,250 $ - $ - $ - $ 3,250
Uncommitted lines Various (a) 83 - 83 83 -
Total - Hess Corporation $ 3,333 $ - $ 83 $ 83 $ 3,250
Midstream
Revolving credit facility (b) July 2027 $ 1,000 $ 18 $ - $ 18 $ 982
Total - Midstream $ 1,000 $ 18 $ - $ 18 $ 982 (a)Uncommitted lines have expiration dates through 2023.
(b)This credit facility may only be utilized by HESM Opco and is non-recourse to
Hess Corporation : InJuly 2022 , we replaced our$3.5 billion revolving credit facility expiring inMay 2024 with a new$3.25 billion revolving credit facility maturing inJuly 2027 . The new facility, which is fully undrawn, can be used for borrowings and letters of credit. Borrowings on the new facility will generally bear interest at 1.400% above SOFR, though the interest rate is subject to adjustment based on the credit rating of the Corporation's senior, unsecured, non-credit enhanced long-term debt. AtDecember 31, 2022 ,Hess Corporation had no outstanding borrowings or letters of credit under its revolving credit facility. In 2020, we entered into a$1 billion three year term loan agreement with a maturity date ofMarch 16, 2023 . Borrowings under the term loan generally bear interest at LIBOR plus an initial applicable margin of 2.25%. InJuly 2021 , we repaid$500 million of the term loan, and inFebruary 2022 , we repaid the remaining$500 million . The revolving credit facility is subject to customary representations, warranties, customary events of default and covenants, including a financial covenant limiting the ratio of Total Consolidated Debt to Total Capitalization of the Corporation and its consolidated subsidiaries to 65%, and a financial covenant limiting the ratio of secured debt to Consolidated Net Tangible Assets of the Corporation and its consolidated subsidiaries to 15% (as these capitalized terms are defined in the credit agreement for the revolving credit facility). The indentures for the Corporation's fixed-rate senior unsecured notes limit the ratio of secured debt to Consolidated Net Tangible Assets (as that term is defined in the indentures) to 15%. As ofDecember 31, 2022 ,Hess Corporation was in compliance with these financial covenants. The most restrictive of the financial covenants relating to our fixed-rate senior unsecured notes and our revolving credit facility would allow us to borrow up to an additional$2,146 million of secured debt atDecember 31, 2022 .
We have a shelf registration under which we may issue additional debt securities, warrants, common stock or preferred stock.
Midstream:
InJuly 2022 , HESM Opco, a consolidated subsidiary of Hess Midstream LP, amended and restated its credit agreement for its$1.4 billion senior secured syndicated credit facilities, consisting of a$1.0 billion revolving credit facility and a$400 million term loan facility. The amended and restated credit agreement, among other things, extended the maturity date fromDecember 2024 toJuly 2027 , increased the accordion feature to up to an additional$750 million , which does not represent a lending commitment from the lenders, and replaced LIBOR as the benchmark interest rate with SOFR. Borrowings under the term loan facility will generally bear interest at SOFR plus an applicable margin ranging from 1.650% to 2.550%, while the applicable margin for the syndicated revolving credit facility ranges from 1.375% to 2.050%. Pricing levels for the facility fee and interest-rate margins are based on HESM Opco's ratio of total debt to EBITDA (as defined in the credit facilities). If HESM Opco obtains an investment grade credit rating, the pricing levels will be based on HESM Opco's credit ratings in effect from time to time. The credit facilities contain covenants that require HESM Opco to maintain a ratio of total debt to EBITDA (as defined in the credit facilities) for the prior four fiscal quarters of not greater than 5.00 to 1.00 as of the last day of each fiscal quarter (5.50 to 1.00 during the specified period following certain acquisitions) and, prior to HESM Opco obtaining an investment grade credit rating, a ratio of secured debt to EBITDA for the prior four fiscal quarters of not greater than 4.00 to 1.00 as of the last day of each fiscal quarter. The credit facilities are secured by first-priority perfected liens on substantially all of the assets of HESM Opco and its direct and indirect wholly owned material domestic subsidiaries, including equity interests directly owned by such entities, subject to certain customary exclusions. AtDecember 31, 2022 , borrowings of$18 million were drawn under HESM Opco's revolving credit facility, and borrowings of$400 million , excluding deferred issuance costs, were drawn under HESM Opco's Term Loan A facility. Borrowings under these credit facilities are non-recourse toHess Corporation . 38 --------------------------------------------------------------------------------
Credit Ratings
All three major credit rating agencies that rate the senior unsecured debt ofHess Corporation have assigned an investment grade credit rating. InJune 2022 , Moody's Investors Service upgraded our senior unsecured ratings from Ba1 to Baa3 with a stable outlook. InMarch 2022 ,Standard and Poor's Ratings Services affirmed our credit rating at BBB- with stable outlook. Fitch Ratings affirmed our BBB- credit rating with a positive outlook inAugust 2022 .
At
Cash Requirements:
Our cash obligations and commitments over the next twelve months include accounts payable, accrued liabilities, the current portion of long-term debt, interest, lease payments, and purchase obligations which cover a portion of our planned capital expenditure program in 2023 and include commitments for oil and gas production expenses, carbon credits, transportation and related contracts, seismic purchases and other normal business expenses.
Our long-term cash obligations and commitments include:
•Debt and interest: See Note 7, Debt in the Notes to Consolidated Financial Statements.
•Operating and finance leases: The Corporation and certain of its subsidiaries lease drilling rigs, equipment, logistical assets (offshore vessels, aircraft, and shorebases), and office space for varying periods. See Note 6, Leases in the Notes to Consolidated Financial Statements. •Purchase obligations: We were contractually committed atDecember 31, 2022 for certain long-term capital expenditures and operating expenses. Long-term obligations for operating expenses include commitments for oil and gas production expenses, transportation and related contracts, carbon credits, seismic purchases and other normal business expenses. See Note 17, Guarantees, Contingencies and Commitments in the Notes to Consolidated Financial Statements.
•Asset retirement obligations: See Note 8, Asset Retirement Obligations in the Notes to Consolidated Financial Statements.
•Post-retirement plan liabilities: We have certain unfunded post-retirement plans, including our post-retirement medical plan. See Note 9, Retirement Plans in the Notes to Consolidated Financial Statements.
•Uncertain income tax positions: See Note 14, Income Taxes in the Notes to Consolidated Financial Statements.
Off-Balance Sheet Arrangements
See Note 17, Guarantees, Contingencies and Commitments in the Notes to Consolidated Financial Statements.
Foreign Operations
We conduct E&P activities outside the
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
39
--------------------------------------------------------------------------------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 update reserve estimates throughout the year based on evaluations of new wells, performance reviews, new technical data and other studies. To provide consistency throughout the Corporation, standard reserve estimation guidelines, definitions, reporting reviews and approval practices are used. The internal reserve estimates are subject to internal technical audits and senior management review. We also engage an independent third-party consulting firm to audit approximately 80% of our total proved reserves each year. Proved reserves are calculated using the average price during the twelve-month period endingDecember 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 atDecember 31, 2022 were$94.13 per barrel for WTI (2021:$66.34 ) and$97.98 per barrel for Brent (2021:$68.92 ). AtDecember 31, 2022 , spot prices closed at$80.26 per barrel for WTI and$81.33 per barrel for Brent. If crude oil prices in 2023 are at levels below that used in determining 2022 proved reserves, we may recognize negative revisions to ourDecember 31, 2023 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 2023 above those used in determining 2022 proved reserves could result in positive revisions to proved developed and proved undeveloped reserves atDecember 31, 2023 . It is difficult to estimate the magnitude of any potential net negative or positive change in proved reserves atDecember 31, 2023 , due to numerous currently unknown factors, including 2023 crude oil prices, the amount of any additions to proved reserves, positive or negative revisions in proved reserves related to 2023 reservoir performance, the levels to which industry costs will change in response to 2023 crude oil prices, and management's plans as ofDecember 31, 2023 for developing proved undeveloped reserves. A 10% change in proved developed and proved undeveloped reserves atDecember 31, 2022 would result in an approximate$175 million pre-tax change in depreciation, depletion, and amortization expense for 2023 based on projected production volumes. See the Supplementary Oil and Gas Data on pages 87 through 96 in the accompanying financial statements for additional information on our oil and gas reserves. Impairment of Long-lived Assets: We review longlived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. Longlived assets are tested based on identifiable cash flows that are largely independent of the cash flows of other assets and liabilities. If the carrying amounts of the long-lived assets are not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is measured based on the estimated fair value of the assets generally determined by discounting anticipated future net cash flows, an income valuation approach, or by a marketbased valuation approach, which are Level 3 fair value measurements. In the case of oil and gas fields, the present value of future net cash flows is based on management's best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a stipulated amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairment will generally differ from those used in the standardized measure of discounted future net cash flows, since the standardized measure requires the use of historical twelve-month average prices. Our impairment tests of long-lived E&P producing assets are based on our best estimates of future production volumes (including recovery factors), selling prices, operating and capital costs, the timing of future production and other factors, which are updated each time an impairment test is performed. We could experience an impairment in the future if one or a combination of the following occur: the projected production volumes from oil and gas fields decrease, crude oil and natural gas selling prices decline significantly for an extended period or future estimated capital and operating costs increase significantly. As a result of the 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 atMarch 31, 2020 . We impaired various oil and gas fields located inMalaysia ,Denmark , and theGulf 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. 40 -------------------------------------------------------------------------------- Hess Midstream LP: We consolidate the activities of our interest in Hess Midstream LP, which qualifies as a variable interest entity (VIE) underU.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 throughHess Corporation's approximate 41% consolidated ownership interest in Hess Midstream LP to direct those activities that most significantly impact the economic performance of Hess Midstream LP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to Hess Midstream LP. This conclusion was based on a qualitative analysis that considered Hess Midstream LP's governance structure, the commercial agreements between Hess Midstream LP and us, and the voting rights established between the members, which provide us the ability to control the operations of Hess Midstream 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 recognize the financial statement effect of a tax position only when management believes it is more likely than not, based on the technical merits, that the position will be sustained upon examination. We have net operating loss carryforwards or credit carryforwards in multiple jurisdictions and have 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 period so brief that a significant deductible temporary difference expected to reverse in a single year would limit realization of tax benefits. We remained in a recent cumulative loss position inthe United States (non-Midstream) andMalaysia atDecember 31, 2022 . A recent cumulative loss constitutes objective negative evidence to which the accounting standards require we assign significant weight relative to subjective evidence such as our estimates of future taxable income. We are generally not recognizing deferred tax benefit or expense in certain countries, primarilythe United States (non-Midstream), andMalaysia , while we maintain valuation allowances against net deferred tax assets in these jurisdictions. AtDecember 31, 2022 , the Consolidated Balance Sheet reflects a$3,658 million valuation allowance against the net deferred tax assets for multiple jurisdictions based on the evaluation of the accounting standards described above. The amount of the deferred tax asset considered realizable, however, could be adjusted if objective negative evidence in the form of cumulative losses is no longer present and additional weight can be given to subjective evidence. There is a reasonable possibility that if anticipated future earnings come to fruition and no other unforeseen negative evidence materializes, sufficient positive evidence may become available to support the release of all or a portion of the Company's valuation allowance in these jurisdictions in the near term. This would result in the recognition of certain deferred tax assets and a decrease to income tax expense for the period in which the release is recorded. Asset Retirement Obligations: We have legal obligations to remove and dismantle longlived assets and to restore land or seabed at certain E&P locations. In accordance with generally accepted accounting principles, we recognize a liability for the fair value of required asset retirement obligations. In addition, the fair value of any legally required conditional asset retirement obligation is recorded if the liability can be reasonably estimated. We capitalize such costs as a component of the carrying amount of the underlying assets in the period in which the liability is incurred. In subsequent periods, the liability is accreted, and the asset is depreciated over the useful life of the related asset. We estimate the fair value of these obligations by discounting projected future payments that will be required to satisfy the obligations. In determining these estimates, we are required to make several assumptions and judgments related to the scope of dismantlement, timing of settlement, interpretation of legal requirements, inflationary factors and discount rate. In addition, there are other external factors, which could significantly affect the ultimate settlement costs or timing for these obligations including changes in environmental regulations and other statutory requirements, fluctuations in industry costs and foreign currency exchange rates and advances in technology. As a result, our estimates of asset retirement obligations are subject to revision due to the factors described above. Changes in estimates prior to settlement result in adjustments to both the liability and related asset values, unless the field has ceased production, in which case changes are recognized in our Consolidated Statement of Income. See Note 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 the Consolidated Balance Sheet. The determination of the obligations and expenses related to these plans are based on several actuarial assumptions. These assumptions represent estimates made by us, some of which can be affected by external factors. The most significant assumptions relate to: 41 -------------------------------------------------------------------------------- Discount rates used for measuring the present value of future plan obligations and net periodic benefit cost: The discount rates used to estimate our projected benefit obligations and net periodic benefit cost is based on a portfolio of highquality, fixed income debt instruments with maturities that approximate the expected payment of plan obligations. AtDecember 31, 2022 , a 0.25% decrease in the discount rate assumptions would increase projected benefit obligations by approximately$65 million and would increase forecasted 2023 annual net periodic benefit expense by approximately$2 million . The increase in the projected benefit obligations would decrease the funded status of our pension plans, but any decrease in the funded status would be partially mitigated by increases in the fair value of fixed income investments in the asset portfolios. Expected long-term rates of returns on plan assets: The expected rate of return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of plan assets to that asset category. The future expected rate of return assumptions for individual asset categories are largely based on inputs from various investment experts regarding their future return expectations for particular asset categories. AtDecember 31, 2022 , a 0.25% decrease in the expected long-term rates of return on plan assets assumption would increase forecasted 2023 annual net periodic benefit expense by approximately$5 million .
Other assumptions include the rate of future increases in compensation levels and expected participant mortality.
Derivatives: We utilize derivative instruments, including futures, forwards, options and swaps, individually or in combination to mitigate our exposure to fluctuations in the prices of crude oil and natural gas, as well as changes in interest and foreign currency exchange rates. All derivative instruments are recorded at fair value in our Consolidated Balance Sheet. Our policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not designated as hedges are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges), or hedges of changes in fair value of recognized assets and liabilities or of unrecognized firm commitments (fair value hedges). Changes in fair value of derivatives that are designated as cash flow hedges are recorded as a component of other comprehensive income (loss). Amounts included in Accumulated other comprehensive income (loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged item is recorded as an adjustment to its carrying amount and recognized currently in earnings. Fair Value Measurements: We use various valuation approaches in determining fair value for financial instruments, including the market and income approaches. Our fair value measurements also include non-performance risk and time value of money considerations. Counterparty credit is considered for financial assets, and our credit is considered for financial liabilities. We also record certain nonfinancial assets and liabilities at fair value when required by generally accepted accounting principles. These fair value measurements are recorded in connection with business combinations, qualifying non-monetary exchanges, the initial recognition of asset retirement obligations and any impairment of long-lived assets, equity method investments or goodwill. We determine fair value in accordance with the fair value measurements accounting standard which established a hierarchy for the inputs used to measure fair value based on the source of the inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3), including discounted cash flows and other unobservable data. Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market. Multiple inputs may be used to measure fair value; however, the level assigned to a fair value measurement is based on the lowest significant input level within this fair value hierarchy.
Environment, Health and Safety
Our long-term vision and values provide a foundation for how we do business and define our commitment to meeting high standards of corporate citizenship and creating a long lasting positive impact on the communities where we do business. Our strategy is reflected in our EHS & SR policies and by a management system framework that helps protect our workforce, customers and local communities. Our management systems are intended to promote internal consistency, adherence to policy objectives and continual improvement in EHS & SR performance. Improved performance may, in the shortterm, 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. TheEPA has adopted a series of GHG monitoring, reporting, and emissions control rules for the oil and natural gas industry, and theU.S. Congress has, from time to time, considered adopting further legislation to reduce GHG emissions. For example, inNovember 2021 , theEPA proposed new regulations to establish comprehensive standards of 42 -------------------------------------------------------------------------------- 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. TheEPA issued a supplemental proposed rule onNovember 15, 2022 , which provided additional information, including regulatory text, about theNovember 2021 proposed rule. The supplemental proposed rule would impose more stringent requirements than are currently applicable on the natural gas and oil industry. In addition, the IRA includes a methane emissions reduction program for petroleum and natural gas systems, which requires theEPA to impose a "waste emissions charge" on excess methane emissions from certain natural gas and oil sources that are required to report underEPA 's Greenhouse Gas Reporting Program beginningJanuary 1, 2024 and also provides significant funding and incentives for research and development of competing low carbon energy production methods. Furthermore, states have taken measures to reduce emissions of GHGs, primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs. 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 GHG emissions regulations that apply to our operations, including those related to venting or flaring of natural gas, and the responsible management of GHG emissions at our facilities. While we monitor climate-related regulatory initiatives and international public policy issues, the current state of ongoing international climate initiatives and any related domestic actions make it difficult to assess the timing or effect on our operations or to predict with certainty the future costs that we may incur in order to comply with future international treaties, legislation or new regulations. However, future restrictions on emissions of GHGs, or related measures to encourage use of low carbon energy could result in higher capital expenditures and operating expenses for us and the oil and gas industry in general and may reduce demand for our products, as described under Regulatory, Legal and Environmental Risks in Item 1A. Risk Factors. We will have continuing expenditures for environmental assessment and remediation. Sites where corrective action may be necessary include E&P facilities, sites from discontinued operations where we retained liability and, although not currently significant,EPA "Superfund" sites where we have been named a potentially responsible party. We accrue for environmental assessment and remediation expenses when the future costs are probable and reasonably estimable. For additional information, see Item 3. Legal Proceedings. AtDecember 31, 2022 , our reserve for estimated remediation liabilities was approximately$55 million . We expect that existing reserves for environmental liabilities will adequately cover costs to assess and remediate known sites. Our remediation spending was approximately$23 million in 2022 (2021:$16 million ; 2020:$15 million ). The amount of other expenditures incurred to comply with federal, state, local and foreign country environmental regulations is difficult to quantify as such costs are captured as mostly indistinguishable components of our capital expenditures and operating expenses. As an element of our EHS and SR strategy, we purchase carbon credits annually to offset 100 percent of our estimated Scope 3 business travel emissions and 100 percent of our estimated Scope 1 and Scope 3 emissions associated with operating the Corporation's truck fleet, aviation activities (aircraft and helicopters) and personal and rental vehicle miles driven on company business. We also offset purchased electricity used in our operations from nonrenewable sources by purchasing renewable energy certificates. The cost of these purchased and retired renewable energy certificates was not material to our financial results in 2022 and was included in Operating costs and expenses in the Statement of Consolidated Income. InDecember 2022 , we announced an agreement with the Government ofGuyana to purchase 37.5 million REDD+ carbon credits, including current and future issuances, for a minimum of$750 million from 2022 through 2032 to prevent deforestation and support sustainable development inGuyana . These credits will be on the ART Registry and will be independently verified to represent permanent and additional emissions reductions under ART's REDD+ Environmental Standard 2.0 (TREES). This agreement adds to the Corporation's ongoing emissions reduction efforts and is an important part of our commitment to achieve net zero Scope 1 and 2 greenhouse gas emissions on a net equity basis by 2050. InDecember 2022 , we purchased 5 million REDD+ carbon credits registered on the ART Registry for$75 million under this agreement, which is included in non-current Other assets in the Consolidated Balance Sheet.
Health and Safety Matters
The crude oil and natural gas industry is regulated at federal, state, local and foreign government levels regarding the health and safety of E&P operations. Such laws and regulations relate to, among other matters, occupational safety, the use of hydraulic fracturing to stimulate crude oil and natural gas production, well control and integrity, process safety and equipment integrity, and may include permitting and disclosure requirements, operating restrictions and other conditions on the development of crude oil and natural gas. The level of our expenditures to comply with federal, state, local and foreign country health and safety regulations is difficult to quantify as such costs are captured as mostly indistinguishable components of our capital expenditures and operating expenses. While compliance with laws and regulations relating to health and safety matters increases the overall cost of business for us and the oil and gas industry in general, it has not had, to date, a material adverse effect on our operations, financial condition or results of operations. Occupational Safety: We are subject to the requirements set forth under federal workplace standards by theOSHA and comparable state statutes that regulate the protection of the health and safety of workers. UnderOSHA 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. 43 -------------------------------------------------------------------------------- Production and Well Integrity: OurU.S. onshore production facilities are subject toU.S. federal government, state and local regulations regarding the use of hydraulic fracturing and well control and integrity. Our offshore production facilities in theGulf of Mexico are subject to theU.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, includingOSHA'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. 44
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