Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements, which are included in this Form 10-K in Item 8, and the information set forth in Risk Factors under Item 1A.
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations omits certain discussions of our financial condition and results of operations for the year ended December 31, 2018 compared with the year ended December 31, 2019, which can be found in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2019 Annual Report on Form 10-K, which was filed with the Securities and Exchange Commission on February 20, 2020, and such comparisons are incorporated herein by reference.
Index
Overview
Hess Corporation is a global E&P company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located primarily in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA), Malaysia, and Denmark. We conduct exploration activities primarily offshore Guyana, in the U.S. Gulf of Mexico, and offshore Suriname and Canada. At the Stabroek Block (Hess 30%), offshore Guyana, we have announced eighteen significant discoveries. The Liza Phase 1 development achieved first production in December 2019, and reached its nameplate production capacity of approximately 120,000 gross bopd in December 2020. The Liza Phase 2 development was sanctioned in the second quarter of 2019 and is expected to achieve first production by early 2022, with production capacity of approximately 220,000 gross bopd. A third development, Payara, was sanctioned in the third quarter of 2020 and is expected to achieve first production in 2024, with production capacity of approximately 220,000 gross bopd. The discovered resources to date on the Stabroek Block are expected to underpin up to ten FPSOs with the first five FPSOs producing more than 750,000 gross bopd by 2026.
Our Midstream operating segment, which is comprised of Hess Corporation’s 47% consolidated ownership interest in Hess Midstream LP at December 31, 2020, provides fee-based services, including gathering, compressing and processing natural gas and fractionating NGL; gathering, terminaling, loading and transporting crude oil and NGL; storing and terminaling propane, and water handling services primarily in the Bakken shale play in the Williston Basin area of North Dakota.
Hess Response to COVID-19 and Market Conditions
COVID-19 continues to have a profound impact on society and industry. The Corporation’s first priority in the midst of the pandemic has been the health and safety of the Hess workforce and local communities where the Corporation operates. 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 implemented 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. In July 2020, Hess Midstream LP announced that the planned maintenance turnaround at the Tioga Gas Plant originally scheduled for the third quarter of 2020 will be deferred until 2021 to ensure safe execution in light of COVID-19.
In addition to the global health concerns of COVID-19, the pandemic has severely impacted demand for oil. Our realized crude oil selling prices, including hedging, were $44.28 per barrel in 2020 (2019: $56.77; 2018: $60.77). In response to the resulting sharp decline in oil prices, the Corporation’s focus is on preserving cash and capability, while protecting the long-term value of its assets. In the first quarter of 2020, we reduced our E&P capital and exploratory budget of $3.0 billion for 2020 to $1.9 billion, and we ended the year with actual capital and exploratory expenditures of $1.8 billion. This reduction was achieved primarily by shifting from a six rig program to one rig in the Bakken, which was accomplished in May, deferral of some 2020 development activities on the Stabroek Block, offshore Guyana, and deferring discretionary spending across the portfolio. In March 2020, Hess entered into a $1.0 billion three year term loan agreement, and in November, we sold our 28% working interest in the Shenzi Field for net proceeds of $482 million, after closing adjustments.
2021 Outlook
Our E&P capital and exploratory expenditures are projected to be approximately $1.9 billion in 2021. Capital investment for our Midstream operations is expected to be approximately $160 million. Oil and gas net production in 2021 is forecast to be approximately 310,000 boepd excluding Libya. For 2021, we have WTI put options with an average monthly floor price of $50 per barrel for 120,000 bopd, and Brent put options with an average monthly floor price of $55 per barrel for 30,000 bopd.
Net cash provided by operating activities was $1,333 million in 2020, compared with $1,642 million in 2019, while net cash provided by operating activities before changes in operating assets and liabilities was $1,803 million in 2020 and $2,237 million in 2019. Capital expenditures for 2020 and 2019 were $1,931 million and $2,992 million, respectively. In 2021, based on current forward strip crude oil prices, we expect cash flow from operating activities, proceeds from the first quarter 2021 sale of 4.2 million barrels of crude oil stored on two VLCCs at year-end, and cash and cash equivalents existing at December 31, 2020 of $1.74 billion will be sufficient to fund our capital investment program and dividends. Due to the volatile commodity price environment, we may take any of the following steps, or a combination thereof, to improve our liquidity and financial position: reduce the planned capital program and other cash outlays, including dividends, pursue asset sales, borrow against our committed revolving credit facility, or issue debt or equity securities.
Consolidated Results
Net loss attributable to Hess Corporation was $3,093 million in 2020 (2019: $408 million). Excluding items affecting comparability of earnings between periods summarized on page 33, the adjusted net loss was $894 million in 2020 (2019: $281 million). Annual net production averaged 331,000 boepd in 2020 (2019: 311,000 boepd). Total proved reserves were 1,170 million boe at December 31, 2020 (2019: 1,197 million boe).
Significant 2020 Activities
The following is an update of significant E&P activities during 2020:
E&P assets:
•In North Dakota, net production from the Bakken shale play averaged 193,000 boepd in 2020 (2019: 152,000 boepd), with net oil production up 15% to 107,000 bopd from 93,000 bopd primarily due to increased wells online and improved well performance. Natural gas and NGL production also increased from higher wells online, additional natural gas captured and processed, and approximately 7,000 boepd of additional volumes received under percentage of proceeds contracts resulting from lower prices. During the year, we operated six rigs in the Bakken through May, before reducing to one rig for the remainder of 2020 in response to the sharp decline in oil prices resulting from the COVID-19 pandemic. We drilled 71 wells and brought 111 wells on production, bringing the total operated production wells to 1,686 by year-end. We reduced the average cost of a plug and perf well in 2020 to $6.2 million per well from $6.8 million per well in 2019. We forecast net production from the Bakken to average approximately 170,000 boepd in 2021.
In the second quarter, we chartered three VLCCs and loaded a total of 6.3 million barrels of oil for sale in Asian markets to enhance cash flow and maximize value from our Bakken production. The first VLCC cargo of 2.1 million barrels was sold in China in September. We have agreements in place to sell the remaining two VLCC cargos totaling 4.2 million barrels in the first quarter of 2021. We expect to recognize net income of approximately $60 million in the first quarter of 2021 from these sales, including associated hedging gains and costs.
•In the Gulf of Mexico, net production averaged 56,000 boepd (2019: 66,000 boepd) reflecting the effect of increased hurricane-related downtime, higher planned maintenance and lower production from the Shenzi Field, which was sold in November 2020, partially offset by initial production from the Esox-1 well, which commenced in February of 2020. Net production from the Shenzi Field was 9,000 boepd in 2020 (2019: 12,000 boepd). We forecast Gulf of Mexico net production for 2021 to average approximately 45,000 boepd.
We participated in two outside operated exploration wells that were completed in 2020, the Oldfield-1 well and the Galapagos Deep well, both located in the Mississippi Canyon area. Both wells were unsuccessful.
•At the Stabroek Block (Hess 30%), offshore Guyana, net production from the Liza Phase 1 development averaged 20,000 bopd in 2020 following first production in December 2019 from the Liza Destiny FPSO. During the fourth quarter, the operator Esso Exploration and Production Guyana Limited, reached its nameplate capacity of 120,000 gross bopd. For 2021, net production from Guyana is expected to average approximately 30,000 bopd.
The Liza Phase 2 development was sanctioned in 2019 and will utilize the Liza Unity FPSO to produce up to 220,000 gross bopd, with first production expected by early 2022. A total of 30 wells are planned at six drill centers, including 15 production wells, nine water injection wells and six gas injection wells. In 2021, the operator plans to continue development
drilling, complete installation of subsea flow lines and equipment, complete installation of topside facilities on the FPSO and sail the Liza Unity FPSO from Singapore to the Liza Field.
On September 30, 2020, we announced the final investment decision to proceed with development of the Payara Field on the Stabroek Block after the development plan received approval from the government of Guyana. Payara will utilize the Prosperity FPSO, which will have the capacity to produce up to 220,000 gross bopd, with first production expected in 2024. Ten drill centers with a total of 41 wells are planned, including 20 production wells and 21 injection wells. Excluding pre-sanction costs and FPSO purchase cost, our net share of development costs is forecast to be approximately $1.8 billion.
In addition to the first three developments, planning is underway for additional FPSOs. The ultimate sizing and timing of these potential developments will be a function of further exploration and appraisal drilling.
In 2020, two successful exploration wells and one successful appraisal well were drilled on the Stabroek Block. For 2021, the operator plans to bring in a fifth drillship in March and a sixth drillship in April and drill 12 to 15 exploration and appraisal wells during the year.
•At the Kaieteur Block (Hess 15%), offshore Guyana, the operator, Esso Exploration and Production Guyana Limited, completed drilling of the Tanager-1 exploration well. The well did encounter hydrocarbons but was not a commercial success on a stand-alone basis.
•In the Gulf of Thailand, net production from Block A‑18 of the JDA averaged 29,000 boepd for the year (2019: 35,000 boepd), including contribution from unitized acreage in Malaysia, while net production from North Malay Basin averaged 23,000 boepd for the year (2019: 28,000 boepd). During 2020, we drilled seven production wells at North Malay Basin, and plan to continue the drilling program and development activities in 2021. We also expect to commence a multi-year drilling program in the first half of 2021 at the JDA. Combined net production from our JDA and North Malay Basin assets is forecast to average approximately 60,000 boepd in 2021.
The following is an update of significant Midstream activities during 2020:
•In 2019, Hess Midstream LP announced plans to expand processing capacity at the Tioga Gas Plant by 150 mmcfd for total processing capacity of 400 mmcfd. In 2020, the facility construction was completed for the expansion. The incremental gas processing capacity is expected to be available in 2021 upon completion of a scheduled plant maintenance turnaround, during which the expansion and residue and NGL takeaway pipelines will be tied in. The plant maintenance turnaround was originally planned to occur in the third quarter of 2020 but was deferred to 2021 to ensure safe execution in light of the COVID-19 pandemic.
•On December 30, 2020, Hess Midstream LP 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.
Liquidity and Capital and Exploratory Expenditures
In 2020, net cash provided by operating activities was $1,333 million (2019: $1,642 million). At December 31, 2020, cash and cash equivalents were $1,739 million (2019: $1,545 million), consolidated debt was $8,296 million (2019: $7,142 million), and our debt to capitalization ratio (as defined in the credit agreement for our revolving credit facility and the term loan agreement) was 47.5% (2019: 39.6%). Hess Midstream debt, which is nonrecourse to Hess Corporation, was $1,910 million at December 31, 2020 (2019: $1,753 million).
Capital and exploratory expenditures were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
E&P Capital and Exploratory Expenditures:
|
|
|
|
|
|
United States
|
|
|
|
|
|
North Dakota
|
$
|
661
|
|
|
$
|
1,312
|
|
|
$
|
967
|
|
Offshore and other
|
258
|
|
|
471
|
|
|
411
|
|
Total United States
|
919
|
|
|
1,783
|
|
|
1,378
|
|
Guyana
|
743
|
|
|
783
|
|
|
383
|
|
Malaysia and JDA
|
99
|
|
|
109
|
|
|
123
|
|
Other (a)
|
25
|
|
|
68
|
|
|
185
|
|
E&P Capital and Exploratory Expenditures
|
$
|
1,786
|
|
|
$
|
2,743
|
|
|
$
|
2,069
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration Expenses Charged to Income Included Above:
|
|
|
|
|
|
United States
|
$
|
91
|
|
|
$
|
105
|
|
|
$
|
106
|
|
International
|
17
|
|
|
62
|
|
|
54
|
|
Total Exploration Expenses Charged to Income included above
|
$
|
108
|
|
|
$
|
167
|
|
|
$
|
160
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream Capital Expenditures:
|
|
|
|
|
|
Midstream Capital Expenditures (b)
|
$
|
253
|
|
|
$
|
416
|
|
|
$
|
271
|
|
(a)Other includes our interests in Denmark, Libya and other non-producing countries.
(b)Excludes equity investments of $33 million in 2019 and $67 million in 2018.
In 2021, we project our E&P capital and exploratory expenditures will be approximately $1.9 billion and Midstream capital expenditures to be approximately $160 million.
Consolidated Results of Operations
Results by Segment:
The after-tax income (loss) by major operating activity is summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions, except per share amounts)
|
Net Income (Loss) Attributable to Hess Corporation:
|
|
|
|
|
|
Exploration and Production
|
$
|
(2,841)
|
|
|
$
|
53
|
|
|
$
|
51
|
|
Midstream
|
230
|
|
|
144
|
|
|
120
|
|
Corporate, Interest and Other
|
(482)
|
|
|
(605)
|
|
|
(453)
|
|
Total
|
$
|
(3,093)
|
|
|
$
|
(408)
|
|
|
$
|
(282)
|
|
Net Income (Loss) Attributable to Hess Corporation Per Common Share - Diluted (a)
|
$
|
(10.15)
|
|
|
$
|
(1.37)
|
|
|
$
|
(1.10)
|
|
(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 38 through 41.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
Items Affecting Comparability of Earnings Between Periods, After Income Taxes:
|
|
|
|
|
|
Exploration and Production
|
$
|
(2,198)
|
|
|
$
|
63
|
|
|
$
|
(86)
|
|
Midstream
|
—
|
|
|
(16)
|
|
|
—
|
|
Corporate, Interest and Other
|
(1)
|
|
|
(174)
|
|
|
(20)
|
|
Total
|
$
|
(2,199)
|
|
|
$
|
(127)
|
|
|
$
|
(106)
|
|
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 57. The items in the table below are explained on pages 38 through 41.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before Income Taxes
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
Gains on asset sales, net
|
$
|
79
|
|
|
$
|
22
|
|
|
$
|
24
|
|
Other, net
|
—
|
|
|
(88)
|
|
|
—
|
|
Marketing, including purchased oil and gas
|
(53)
|
|
|
(21)
|
|
|
—
|
|
Operating costs and expenses
|
(20)
|
|
|
—
|
|
|
(19)
|
|
Exploration expenses, including dry holes and lease impairment
|
(153)
|
|
|
—
|
|
|
(3)
|
|
General and administrative expenses
|
(6)
|
|
|
(30)
|
|
|
(130)
|
|
Loss on debt extinguishment
|
—
|
|
|
—
|
|
|
(53)
|
|
Depreciation, depletion and amortization
|
—
|
|
|
—
|
|
|
(16)
|
|
Impairment
|
(2,126)
|
|
|
—
|
|
|
—
|
|
Total Items Affecting Comparability of Earnings Between Periods, Pre-Tax
|
$
|
(2,279)
|
|
|
$
|
(117)
|
|
|
$
|
(197)
|
|
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
Adjusted Net Income (Loss) Attributable to Hess Corporation:
|
|
|
|
|
|
Net income (loss) attributable to Hess Corporation
|
$
|
(3,093)
|
|
|
$
|
(408)
|
|
|
$
|
(282)
|
|
Less: Total items affecting comparability of earnings between periods, after-tax
|
(2,199)
|
|
|
(127)
|
|
|
(106)
|
|
Adjusted Net Income (Loss) Attributable to Hess Corporation
|
$
|
(894)
|
|
|
$
|
(281)
|
|
|
$
|
(176)
|
|
The following table reconciles reported net cash provided by (used in) operating activities and net cash provided by (used in) operating activities before changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
Net cash provided by operating activities before changes in operating assets and liabilities:
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
$
|
1,333
|
|
|
$
|
1,642
|
|
|
$
|
1,939
|
|
Changes in operating assets and liabilities
|
470
|
|
|
595
|
|
|
190
|
|
Net cash provided by (used in) operating activities before changes in operating assets and liabilities
|
$
|
1,803
|
|
|
$
|
2,237
|
|
|
$
|
2,129
|
|
Adjusted net income (loss) attributable to Hess Corporation is a non-GAAP financial measure, which we define as reported net income (loss) attributable to Hess Corporation excluding items identified as affecting comparability of earnings between periods, which are summarized on pages 38 through 41. 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 investors’ understanding of our ability to generate cash to fund these items is enhanced by disclosing this measure, which excludes working capital and other movements that may distort assessment of our performance between periods.
These measures are not, and should not be viewed as, substitutes for U.S. GAAP net income (loss) and net cash provided by (used in) operating activities.
Comparison of Results
Exploration and Production
Following is a summarized statement of income for our E&P operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
Revenues and Non-Operating Income
|
|
|
|
|
|
Sales and other operating revenues
|
$
|
4,667
|
|
|
$
|
6,495
|
|
|
$
|
6,323
|
|
Gains on asset sales, net
|
79
|
|
|
22
|
|
|
27
|
|
Other, net
|
31
|
|
|
51
|
|
|
53
|
|
Total revenues and non-operating income
|
4,777
|
|
|
6,568
|
|
|
6,403
|
|
Costs and Expenses
|
|
|
|
|
|
Marketing, including purchased oil and gas
|
1,067
|
|
|
1,849
|
|
|
1,833
|
|
Operating costs and expenses
|
895
|
|
|
971
|
|
|
941
|
|
Production and severance taxes
|
124
|
|
|
184
|
|
|
171
|
|
Midstream tariffs
|
946
|
|
|
722
|
|
|
648
|
|
Exploration expenses, including dry holes and lease impairment
|
351
|
|
|
233
|
|
|
362
|
|
General and administrative expenses
|
206
|
|
|
204
|
|
|
258
|
|
Depreciation, depletion and amortization
|
1,915
|
|
|
1,977
|
|
|
1,748
|
|
Impairment
|
2,126
|
|
|
—
|
|
|
—
|
|
Total costs and expenses
|
7,630
|
|
|
6,140
|
|
|
5,961
|
|
Results of Operations Before Income Taxes
|
(2,853)
|
|
|
428
|
|
|
442
|
|
Provision (benefit) for income taxes (a)
|
(12)
|
|
|
375
|
|
|
391
|
|
Net Income (Loss) Attributable to Hess Corporation
|
$
|
(2,841)
|
|
|
$
|
53
|
|
|
$
|
51
|
|
(a)Commencing January 1, 2019, management changed its measurement of segment earnings to reflect income taxes on a post U.S. tax consolidation and valuation allowance assessment basis. See footnote (a) in the table on page 87 for further details.
Excluding the E&P items affecting comparability of earnings between periods in the table on page 38, 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, exploration expenses and income taxes, as discussed below.
Selling Prices: Average worldwide realized crude oil selling prices, including hedging, were 22% lower in 2020 compared with the prior year, primarily due to the decrease in Brent and WTI crude oil prices. In addition, realized worldwide selling prices for NGL decreased in 2020 by 16% and worldwide natural gas prices decreased in 2020 by 24%, compared with the prior year. In total, lower realized selling prices decreased financial results by approximately $780 million after income taxes, compared with 2019. Our average selling prices were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
Average Selling Prices (a)
|
|
|
|
|
|
Crude Oil - Per Barrel (Including Hedging)
|
|
|
|
|
|
United States
|
|
|
|
|
|
North Dakota
|
$
|
42.63
|
|
|
$
|
53.19
|
|
|
$
|
56.90
|
|
Offshore
|
45.92
|
|
|
59.18
|
|
|
62.02
|
|
Total United States
|
43.56
|
|
|
55.15
|
|
|
58.69
|
|
Guyana
|
46.41
|
|
|
—
|
|
|
—
|
|
Malaysia and JDA
|
37.91
|
|
|
61.81
|
|
|
70.42
|
|
Other (b)
|
51.37
|
|
|
65.22
|
|
|
69.76
|
|
Worldwide
|
44.28
|
|
|
56.77
|
|
|
60.77
|
|
|
|
|
|
|
|
Crude Oil - Per Barrel (Excluding Hedging)
|
|
|
|
|
|
United States
|
|
|
|
|
|
North Dakota
|
$
|
33.87
|
|
|
$
|
53.18
|
|
|
$
|
60.64
|
|
Offshore
|
36.55
|
|
|
59.17
|
|
|
65.73
|
|
Total United States
|
34.63
|
|
|
55.14
|
|
|
62.41
|
|
Guyana
|
37.40
|
|
|
—
|
|
|
—
|
|
Malaysia and JDA
|
37.91
|
|
|
61.81
|
|
|
70.42
|
|
Other (b)
|
43.42
|
|
|
65.22
|
|
|
69.76
|
|
Worldwide
|
35.52
|
|
|
56.76
|
|
|
63.80
|
|
|
|
|
|
|
|
Natural Gas Liquids - Per Barrel
|
|
|
|
|
|
United States
|
|
|
|
|
|
North Dakota
|
$
|
11.29
|
|
|
$
|
13.20
|
|
|
$
|
21.48
|
|
Other Onshore (c)
|
—
|
|
|
—
|
|
|
18.55
|
|
Offshore
|
8.94
|
|
|
13.31
|
|
|
25.58
|
|
Worldwide
|
11.10
|
|
|
13.21
|
|
|
21.81
|
|
|
|
|
|
|
|
Natural Gas - Per Mcf
|
|
|
|
|
|
United States
|
|
|
|
|
|
North Dakota
|
$
|
1.27
|
|
|
$
|
1.59
|
|
|
$
|
2.42
|
|
Other Onshore (c)
|
—
|
|
|
—
|
|
|
2.02
|
|
Offshore
|
1.23
|
|
|
2.12
|
|
|
2.68
|
|
Total United States
|
1.26
|
|
|
1.83
|
|
|
2.43
|
|
Malaysia and JDA
|
4.47
|
|
|
5.04
|
|
|
5.07
|
|
Other (b)
|
3.41
|
|
|
4.63
|
|
|
4.41
|
|
Worldwide
|
2.98
|
|
|
3.90
|
|
|
4.18
|
|
(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 2020 would be $47.54 per barrel for crude oil (including hedging) (2019: $59.95; 2018: $63.77), $38.78 per barrel for crude oil (excluding hedging) (2019: $59.94; 2018: $66.80), $11.29 per barrel for NGL (2019: $13.40; 2018: $22.00) and $3.11 per mcf for natural gas (2019: $3.97; 2018: $4.25).
(b)Other includes our interests in Denmark and Libya.
(c)In August 2018, we sold our interests in the Utica shale play, onshore U.S.
Crude oil hedging activities in 2020 were a net gain of $547 million before and after income taxes, and a net gain of $1 million before and after income taxes in 2019. For 2021, we have WTI put options with an average monthly floor price of $50 per barrel for 120,000 bopd, and Brent put options with an average monthly floor price of $55 per barrel for 30,000 bopd. We expect put option premium amortization, which will be reflected in realized selling prices, to reduce our 2021 results by approximately $205 million.
Production Volumes: Our daily worldwide net production was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In thousands)
|
Crude Oil - Barrels
|
|
|
|
|
|
United States
|
|
|
|
|
|
North Dakota
|
107
|
|
|
94
|
|
|
77
|
|
Offshore (a)
|
38
|
|
|
46
|
|
|
41
|
|
Total United States
|
145
|
|
|
140
|
|
|
118
|
|
Guyana
|
20
|
|
|
—
|
|
|
—
|
|
Malaysia and JDA
|
4
|
|
|
4
|
|
|
4
|
|
Other (b)
|
9
|
|
|
25
|
|
|
24
|
|
Total
|
178
|
|
|
169
|
|
|
146
|
|
Natural Gas Liquids - Barrels
|
|
|
|
|
|
United States
|
|
|
|
|
|
North Dakota
|
56
|
|
|
42
|
|
|
31
|
|
Other Onshore (c)
|
—
|
|
|
—
|
|
|
3
|
|
Total Onshore
|
56
|
|
|
42
|
|
|
34
|
|
Offshore (a)
|
5
|
|
|
5
|
|
|
5
|
|
Total United States
|
61
|
|
|
47
|
|
|
39
|
|
|
|
|
|
|
|
Natural Gas - Mcf
|
|
|
|
|
|
United States
|
|
|
|
|
|
North Dakota
|
180
|
|
|
110
|
|
|
76
|
|
Other Onshore (c)
|
—
|
|
|
—
|
|
|
38
|
|
Total Onshore
|
180
|
|
|
110
|
|
|
114
|
|
Offshore (a)
|
76
|
|
|
91
|
|
|
67
|
|
Total United States
|
256
|
|
|
201
|
|
|
181
|
|
Malaysia and JDA
|
291
|
|
|
351
|
|
|
352
|
|
Other (b)
|
7
|
|
|
20
|
|
|
20
|
|
Total
|
554
|
|
|
572
|
|
|
553
|
|
|
|
|
|
|
|
Barrels of Oil Equivalent
|
331
|
|
|
311
|
|
|
277
|
|
|
|
|
|
|
|
Crude oil and natural gas liquids as a share of total production
|
72
|
%
|
|
69
|
%
|
|
67
|
%
|
(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 (2019: 12,000 boepd; 2018: 16,000 boepd).
(b)Other includes our interests in Denmark and Libya. Net production from Libya was 4,000 boepd for 2020 (2019: 21,000 boepd; 2018: 20,000 boepd). Net production from Denmark was 6,000 boepd for 2020 (2019: 7,000 boepd; 2018: 7,000 boepd).
(c)In August 2018, we sold our interests in the Utica shale play, onshore U.S. Production was 9,000 boepd for the year ended December 31, 2018.
In 2021, we expect net production, excluding Libya, to be approximately 310,000 boepd, compared with 2020 net production, excluding Libya and assets sold, of 318,000 boepd.
Net production variances related to 2020 and 2019 are summarized as follows:
United States: North Dakota net oil production was higher in 2020, primarily due to increased wells online and improved well performance. North Dakota net natural gas and NGL production was higher in 2020, due to increased wells online and improved well performance, additional natural gas captured and processed, and additional volumes received under percentage of proceeds contracts resulting from lower prices. Offshore net production was down in 2020 compared to 2019 due to the effect of increased hurricane-related downtime and higher planned maintenance in 2020 and lower production from the Shenzi Field, which was sold in November 2020, partially offset by initial production from the Esox-1 well, which commenced in February of 2020.
International: Net crude oil production from Guyana was higher in 2020, due to the start-up of the Liza Phase 1 development in December 2019, while net crude oil production in Libya was largely shut in during 2020 due to force majeure caused by civil unrest. Net natural gas production was lower from Malaysia and JDA due to COVID-19 impacts on economic activity in Malaysia and Thailand which reduced natural gas nominations from the buyers.
Sales Volumes: Higher sales volumes from our net production in 2020 improved after-tax results by approximately $130 million, compared with 2019. Net worldwide sales volumes from Hess net production, which excludes sales volumes of crude oil, NGL and natural gas purchased from third parties, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In thousands)
|
Crude oil – barrels (a)
|
60,924
|
|
|
61,061
|
|
|
52,742
|
|
Natural gas liquids – barrels
|
22,397
|
|
|
17,067
|
|
|
14,019
|
|
Natural gas – mcf
|
202,917
|
|
|
208,665
|
|
|
202,041
|
|
Barrels of Oil Equivalent
|
117,141
|
|
|
112,906
|
|
|
100,435
|
|
|
|
|
|
|
|
Crude oil - barrels per day
|
167
|
|
|
167
|
|
|
144
|
|
Natural gas liquids - barrels per day
|
61
|
|
|
47
|
|
|
39
|
|
Natural gas - mcf per day
|
554
|
|
|
572
|
|
|
553
|
|
Barrels of Oil Equivalent Per Day
|
320
|
|
|
309
|
|
|
275
|
|
(a)In 2020, 6.3 million barrels of Bakken crude oil were loaded on VLCCs for sale in Asian markets. The first VLCC cargo of 2.1 million barrels was sold during the third quarter of 2020 and the remaining two VLCC cargos totaling 4.2 million barrels have been sold for delivery in the first quarter of 2021.
Marketing, including purchased oil and gas (Marketing expense): Marketing expense is mainly comprised of costs to purchase crude oil, NGL and natural gas from our partners in Hess operated wells or other third parties, primarily in the U.S., and transportation and other distribution costs for U.S. marketing activities. Marketing expense was lower in 2020 compared to 2019 primarily due to lower crude oil prices paid for purchased volumes from third parties.
Cash Operating Costs: Cash operating costs consist of operating costs and expenses, production and severance taxes and E&P general and administrative expenses. Excluding items affecting comparability described in Items Affecting Comparability of Earnings Between Periods below, cash operating costs decreased $159 million, or 12%, in 2020 compared to 2019 primarily from the impact of cost reduction initiatives and lower production and severance taxes associated with lower crude oil prices. On a per-unit basis, cash operating costs improved 17% from 2019 reflecting lower costs and the impact of higher production volumes.
Midstream Tariffs Expense: Tariffs expense increased from 2019, primarily due to higher throughput volumes and tariff rates in 2020. In 2021, we estimate Midstream tariffs expense to be in the range of $1,090 million to $1,115 million.
DD&A: DD&A expenses decreased by $62 million from 2019, primarily due to a lower portfolio average DD&A rate, due in part to impairment charges in the first quarter of 2020, partially offset by higher production volumes. DD&A expense on a per-unit basis was lower in 2020, compared to 2019, primarily due to the year-over-year mix of production and the impact of reduced DD&A rates for assets impaired in the first quarter of 2020.
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 below. Actual and forecast unit costs are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
|
|
Forecast range (a)
|
|
2020
|
|
2019
|
|
2018
|
|
2021
|
Cash operating costs (b)
|
$
|
9.91
|
|
|
$
|
11.99
|
|
|
$
|
12.66
|
|
|
$10.50 — $11.50
|
DD&A (c)
|
15.80
|
|
|
17.43
|
|
|
17.14
|
|
|
12.00 — 13.00
|
Total Production Unit Costs
|
$
|
25.71
|
|
|
$
|
29.42
|
|
|
$
|
29.80
|
|
|
$22.50 — $24.50
|
(a)Forecast information excludes any contribution from Libya.
(b)Cash operating costs per boe, excluding Libya, was $9.85 in 2020 (2019: $12.54; 2018: $13.32).
(c)DD&A per boe, excluding Libya, was $15.98 in 2020 (2019: $18.52; 2018: $18.29).
Exploration Expenses: Exploration expenses, including items affecting comparability of earnings described below, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
Exploratory dry hole costs (a)
|
$
|
192
|
|
|
$
|
49
|
|
|
$
|
165
|
|
Exploration lease and other impairment (b)
|
51
|
|
|
17
|
|
|
37
|
|
Geological and geophysical expense and exploration overhead
|
108
|
|
|
167
|
|
|
160
|
|
|
$
|
351
|
|
|
$
|
233
|
|
|
$
|
362
|
|
(a)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 2019, dry hole costs primarily related to the Jill-1 well on License 6/16 in Denmark and the Oldfield-1 well in the Gulf of Mexico. Dry hole expense for the Oldfield-1 well was $15 million in 2019 and $12 million in 2020.
(b)In 2020, exploration lease and other impairment included impaired leasehold costs due to a reprioritization of the Corporation’s forward capital program (see Items Affecting Comparability of Earnings Between Periods below).
In 2021, we estimate exploration expenses, excluding dry hole expense, to be in the range of $170 million to $180 million.
Income Taxes: In 2020, income tax benefit was $12 million compared with expense of $375 million in 2019, primarily due to reduced activity in Libya resulting from force majeure on operations for the majority of the year. We are generally not recognizing deferred tax benefit or expense in certain countries, primarily the U.S., Denmark, and Malaysia, while we maintain valuation allowances against net deferred tax assets in these jurisdictions in accordance with the requirements of U.S. accounting standards. The valuation allowance established against the net deferred tax asset in Guyana for the Stabroek Block was released as a result of the positive evidence from first production in December 2019, and the significant forecasted pre-tax income from operations. The cumulative pre-tax losses in Guyana were driven by pre-production activities. See E&P Items Affecting Comparability of Earnings Between Periods below.
Actual effective tax rates are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
%
|
|
%
|
|
%
|
Effective income tax benefit (expense) rate
|
0
|
|
(88)
|
|
(88)
|
Adjusted effective income tax benefit (expense) rate (a)
|
(5)
|
|
(36)
|
|
60
|
(a)Excludes any contribution from Libya and items affecting comparability of earnings.
In 2021, we estimate income tax expense, excluding Libya and items affecting comparability of earnings between periods, to be in the range of $80 million to $90 million.
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
|
|
2020
|
|
2019
|
|
2018
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Impairment
|
$
|
(2,126)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(2,049)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Dry hole and lease impairment expenses
|
(152)
|
|
|
—
|
|
|
—
|
|
|
(150)
|
|
|
—
|
|
|
—
|
|
Crude oil inventories write-down
|
(53)
|
|
|
—
|
|
|
—
|
|
|
(52)
|
|
|
—
|
|
|
—
|
|
Exit costs and other
|
(26)
|
|
|
—
|
|
|
(110)
|
|
|
(26)
|
|
|
—
|
|
|
(110)
|
|
Cost recovery settlement
|
—
|
|
|
(21)
|
|
|
—
|
|
|
—
|
|
|
(19)
|
|
|
—
|
|
Reversal of deferred tax asset valuation allowance
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
60
|
|
|
—
|
|
Gains on asset sales, net
|
79
|
|
|
22
|
|
|
24
|
|
|
79
|
|
|
22
|
|
|
24
|
|
|
$
|
(2,278)
|
|
|
$
|
1
|
|
|
$
|
(86)
|
|
|
$
|
(2,198)
|
|
|
$
|
63
|
|
|
$
|
(86)
|
|
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
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
Gains on asset sales, net
|
$
|
79
|
|
|
$
|
22
|
|
|
$
|
24
|
|
|
|
|
|
|
|
Marketing, including purchased oil and gas
|
(53)
|
|
|
(21)
|
|
|
—
|
|
Operating costs and expenses
|
(20)
|
|
|
—
|
|
|
(19)
|
|
Exploration expenses, including dry holes and lease impairment
|
(153)
|
|
|
—
|
|
|
(3)
|
|
General and administrative expenses
|
(5)
|
|
|
—
|
|
|
(72)
|
|
Depreciation, depletion and amortization
|
—
|
|
|
—
|
|
|
(16)
|
|
Impairment
|
(2,126)
|
|
|
—
|
|
|
—
|
|
|
$
|
(2,278)
|
|
|
$
|
1
|
|
|
$
|
(86)
|
|
2020:
•Impairment: 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 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.
•Exit costs and other: We recorded a pre-tax charge of $26 million ($26 million after income taxes) for employee termination benefits incurred related to cost reduction initiatives.
•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 deepwater Gulf of Mexico.
2019:
•Cost recovery settlement: We recorded a pre-tax charge of $21 million ($19 million after income taxes) related to a settlement on historical cost recovery balances in the JDA that was paid in cash.
•Reversal of deferred tax asset valuation allowance: We recorded a noncash income tax benefit of $60 million, which resulted from the reversal of a valuation allowance against net deferred tax assets in Guyana upon achieving first production from the Liza Phase 1 development.
•Gains on asset sales, net: We recorded a pre-tax gain of $22 million ($22 million after income taxes) associated with the sale of our remaining acreage in the Utica shale play.
2018:
•Exit costs and other: 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 charge of $37 million ($37 million after income taxes) for employee termination benefits related to a cost reduction program undertaken to reflect the reduced scale of our business following significant asset sales in 2017.
•Gains on asset sales, net: We recorded a pre-tax gain of $14 million ($14 million after income taxes) associated with the sale of our joint venture interests in the Utica shale play in eastern Ohio and a pre-tax gain of $10 million ($10 million after income taxes) associated with the sale of our interests in Ghana.
Midstream
Following is a summarized statement of income for our Midstream operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
Revenues and Non-Operating Income
|
|
|
|
|
|
Sales and other operating revenues
|
$
|
1,092
|
|
|
$
|
848
|
|
|
$
|
713
|
|
|
|
|
|
|
|
Other, net
|
10
|
|
|
4
|
|
|
6
|
|
Total revenues and non-operating income
|
1,102
|
|
|
852
|
|
|
719
|
|
Costs and Expenses
|
|
|
|
|
|
Operating costs and expenses
|
338
|
|
|
279
|
|
|
193
|
|
General and administrative expenses
|
21
|
|
|
56
|
|
|
14
|
|
Depreciation, depletion and amortization
|
157
|
|
|
142
|
|
|
127
|
|
Interest expense
|
95
|
|
|
63
|
|
|
60
|
|
Total costs and expenses
|
611
|
|
|
540
|
|
|
394
|
|
Results of Operations Before Income Taxes
|
491
|
|
|
312
|
|
|
325
|
|
Provision (benefit) for income taxes (a)
|
7
|
|
|
—
|
|
|
38
|
|
Net income (loss)
|
484
|
|
|
312
|
|
|
287
|
|
Less: Net income (loss) attributable to noncontrolling interests
|
254
|
|
|
168
|
|
|
167
|
|
Net Income (Loss) Attributable to Hess Corporation
|
$
|
230
|
|
|
$
|
144
|
|
|
$
|
120
|
|
(a)Commencing January 1, 2019, management changed its measurement of segment earnings to reflect income taxes on a post U.S. tax consolidation and valuation allowance assessment basis. See footnote (a) in the table on page 87 for further details.
Sales and other operating revenues increased from 2019 primarily due to higher throughput volumes and tariff rates. Operating costs and expenses increased from 2019 primarily due to increased operating and maintenance expenditures on expanded infrastructure and initial costs incurred related to the Tioga Gas Plant turnaround planned for 2021. General and administrative expenses decreased from 2019 as a result of expenditures incurred from Hess Midstream LP’s acquisition of HIP and its corporate restructuring. See Items Affecting Comparability of Earnings below. DD&A expenses increased from 2019 primarily due to additional assets placed in service. The increase in interest expense from 2019 reflects higher borrowings by the Midstream business.
In 2021, we estimate net income attributable to Hess Corporation from the Midstream segment to be in the range of $280 million to $290 million.
Items Affecting Comparability of Earnings Between Periods: In 2019, we recognized a pre-tax charge of $30 million ($16 million after income taxes and noncontrolling interests) in General and Administrative Expenses for transaction related costs for Hess Midstream Partners LP’s acquisition of HIP and the associated corporate restructuring. See Note 4, Hess Midstream LP in the Notes to Consolidated Financial Statements.
Corporate, Interest and Other
The following table summarizes Corporate, Interest and Other expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
Corporate and other expenses (excluding items affecting comparability)
|
$
|
114
|
|
|
$
|
114
|
|
|
$
|
97
|
|
Interest expense
|
373
|
|
|
355
|
|
|
359
|
|
Less: Capitalized interest
|
—
|
|
|
(38)
|
|
|
(20)
|
|
Interest expense, net
|
373
|
|
|
317
|
|
|
339
|
|
Corporate, Interest and Other expenses before income taxes
|
487
|
|
|
431
|
|
|
436
|
|
Provision (benefit) for income taxes
|
(6)
|
|
|
—
|
|
|
(3)
|
|
Net Corporate, Interest and Other expenses after income taxes
|
481
|
|
|
431
|
|
|
433
|
|
Items affecting comparability of earnings between periods, after income taxes
|
1
|
|
|
174
|
|
|
20
|
|
Total Corporate, Interest and Other Expenses After Income Taxes
|
$
|
482
|
|
|
$
|
605
|
|
|
$
|
453
|
|
Corporate and other expenses, excluding items affecting comparability, were comparable in 2020 compared to the corresponding period in 2019. In 2021, after-tax Corporate and other expenses, excluding items affecting comparability of earnings between periods, are estimated to be in the range of $130 million to $140 million.
Interest expense, net was higher in 2020 due to interest incurred on the $1.0 billion three year term loan entered into in March 2020 and lower capitalized interest. In 2021, after-tax interest expense, net is estimated to be in the range of $380 million to $390 million.
Items Affecting Comparability of Earnings Between Periods: Corporate, Interest and Other results included the following items affecting comparability of income (expense):
2020:
•Exit costs and other: We included a pre-tax charge of $1 million ($1 million after income taxes) for employee termination benefits related to cost reduction initiatives.
2019:
•Pension settlement: We recorded a noncash pension settlement charge of $88 million ($88 million after income taxes) associated with the purchase of a single premium annuity contract by the Hess Corporation Employees’ Pension Plan to settle and transfer certain of its obligations to a third party. The charge is included in Other, net in the Statement of Consolidated Income.
•Income tax: We recorded an allocation of noncash income tax expense of $86 million that was previously a component of accumulated other comprehensive income related to our 2019 crude oil hedge contracts.
2018:
•Loss on debt extinguishment: We recorded a pre-tax charge of $53 million ($53 million after income taxes) related to the premium paid for debt repurchases.
•Exit costs and other: We recorded a pre-tax charge of $58 million ($58 million after income taxes) resulting from the settlement of legal claims related to former downstream interests.
•Income tax: We recorded an allocation of noncash income tax benefit of $91 million to offset the recognition of a noncash income tax expense recorded in other comprehensive income resulting primarily from changes in fair value of our 2019 crude oil hedge contracts.
Liquidity and Capital Resources
The following table sets forth certain relevant measures of our liquidity and capital resources at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
|
|
|
|
(In millions, except ratio)
|
Cash and cash equivalents (a)
|
$
|
1,739
|
|
|
$
|
1,545
|
|
Current maturities of long-term debt
|
10
|
|
|
—
|
|
Total debt (b)
|
8,296
|
|
|
7,142
|
|
Total equity
|
6,335
|
|
|
9,706
|
|
Debt to capitalization ratio for debt covenants (c)
|
47.5
|
%
|
|
39.6
|
%
|
(a)Includes $4 million of cash attributable to our Midstream Segment at December 31, 2020 (2019: $3 million).
(b)Includes $1,910 million of debt outstanding from our Midstream Segment at December 31, 2020 (2019: $1,753 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 term loan and revolving credit facility financial covenants. Total Capitalization excludes the impact of noncash impairment charges and non-controlling interests. See Note 7 in the Notes to Consolidated Financial Statements.
Cash Flows
The following table sets forth a summary of our cash flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
Net cash provided by (used in):
|
|
|
|
|
|
Operating activities
|
$
|
1,333
|
|
|
$
|
1,642
|
|
|
$
|
1,939
|
|
Investing activities
|
(1,707)
|
|
|
(2,843)
|
|
|
(1,566)
|
|
Financing activities
|
568
|
|
|
52
|
|
|
(2,526)
|
|
Net Increase (Decrease) in Cash and Cash Equivalents
|
$
|
194
|
|
|
$
|
(1,149)
|
|
|
$
|
(2,153)
|
|
Operating Activities: Net cash provided by operating activities was $1,333 million in 2020 (2019: $1,642 million), while net cash provided by operating activities before changes in operating assets and liabilities was $1,803 million in 2020 (2019: $2,237 million). Net cash provided by operating activities before changes in operating assets and liabilities decreased from 2019 primarily due to lower realized selling prices. Changes in operating assets and liabilities in 2020 reduced net cash provided by operating activities by $470 million, primarily from a 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. Changes in operating
assets and liabilities in 2019 reduced net cash provided by operating activities by $595 million primarily related to premiums on crude oil hedge contracts, abandonment expenditures, pension contributions and an increase in accounts receivable.
Investing Activities: Total Additions to Property, Plant and Equipment were $2,197 million in 2020 (2019: $2,829 million). The decrease primarily reflects lower drilling activity in the Bakken, partially offset by payments in the first quarter of 2020 to settle capital expenditures accrued in the fourth quarter of 2019. In 2019, Midstream equity investments in its 50/50 joint venture with Targa Resources were $33 million. Proceeds from asset sales were $493 million in 2020 (2019: $22 million).
Financing Activities: Borrowings in 2020 related to our $1.0 billion three year term loan while borrowings in 2019 related to our Midstream operating segment. Repayments of debt were $8 million in 2019. Net borrowings (repayments) of debt with maturities of 90 days or less related to our Midstream operating segment revolving credit facilities. Common stock dividends paid were $309 million in 2020 compared to common and preferred dividends of $316 million in 2019. Net cash outflows to noncontrolling interests were $261 million in 2020 (2019: $353 million).
Future Capital Requirements and Resources
At December 31, 2020, Hess Corporation, had $1.74 billion in cash and cash equivalents, excluding Midstream, and total liquidity, including available committed credit facilities, of approximately $5.4 billion. Our fully undrawn $3.5 billion committed revolving credit facility matures in May 2023, and we have no debt maturities until 2023 when the three year term loan matures.
Net production in 2021 is forecast to be approximately 310,000 boepd, excluding Libya, and we expect our 2021 E&P capital and exploratory expenditures will be approximately $1.9 billion. For 2021, we have WTI put options with an average monthly floor price of $50 per barrel for 120,000 bopd, and Brent put options with an average monthly floor price of $55 per barrel for 30,000 bopd.
In 2021, based on current forward strip crude oil prices, we expect cash flow from operating activities, proceeds from the first quarter 2021 sale of 4.2 million barrels of crude oil stored on two VLCCs at year-end, and cash and cash equivalents existing at December 31, 2020 of $1.74 billion, will be sufficient to fund our capital investment program and dividends. Due to the volatile commodity price environment, 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.
The table below summarizes the capacity, usage, and available capacity of our borrowing and letter of credit facilities at December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expiration
Date
|
|
Capacity
|
|
Borrowings
|
|
Letters of
Credit
Issued
|
|
Total
Used
|
|
Available
Capacity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Hess Corporation
|
|
|
|
|
|
|
|
|
|
|
|
Revolving credit facility
|
May 2023
|
|
$
|
3,500
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,500
|
|
Committed lines
|
Various (a)
|
|
175
|
|
|
—
|
|
|
54
|
|
|
54
|
|
|
121
|
|
Uncommitted lines
|
Various (a)
|
|
215
|
|
|
—
|
|
|
215
|
|
|
215
|
|
|
—
|
|
Total - Hess Corporation
|
|
|
$
|
3,890
|
|
|
$
|
—
|
|
|
$
|
269
|
|
|
$
|
269
|
|
|
$
|
3,621
|
|
Midstream
|
|
|
|
|
|
|
|
|
|
|
|
Revolving credit facility (b)
|
December 2024
|
|
$
|
1,000
|
|
|
$
|
184
|
|
|
$
|
—
|
|
|
$
|
184
|
|
|
$
|
816
|
|
Total - Midstream
|
|
|
$
|
1,000
|
|
|
$
|
184
|
|
|
$
|
—
|
|
|
$
|
184
|
|
|
$
|
816
|
|
(a)Committed and uncommitted lines have expiration dates through 2021.
(b)This credit facility may only be utilized by HESM Opco and is non-recourse to Hess Corporation.
Hess Corporation:
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 applicable margin of 2.25% until the term loan's first anniversary. The applicable margin varies based on the credit rating of the Corporation’s senior unsecured long-term debt and will increase by 0.25% on each anniversary of the term loan.
In 2019, we entered into a new $3.5 billion revolving credit facility with a maturity date of May 15, 2023, which replaced the Corporation’s previous revolving credit facility. The new facility can be used for borrowings and letters of credit. Borrowings will generally bear interest at 1.30% above LIBOR, though the interest rate is subject to adjustment if the Corporation’s credit rating changes. At December 31, 2020, 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). 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, 2020, Hess Corporation was in compliance with these financial covenants. For additional information regarding the alteration or discontinuation of LIBOR on our borrowing costs, see Financial Risks in Item 1A. Risk Factors.
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 $1,730 million of secured debt at December 31, 2020.
We had $269 million in letters of credit outstanding at December 31, 2020 (2019: $272 million), which primarily relate to our international operations. We have a shelf registration under which we may issue additional debt securities, warrants, common stock or preferred stock.
Midstream:
At December 31, 2020, Hess Midstream Operations LP (formerly Hess Midstream Partners LP, or HESM Opco), a consolidated subsidiary of Hess Midstream LP, had $1.4 billion of senior secured syndicated credit facilities maturing December 16, 2024, consisting of a $1.0 billion five year revolving credit facility and a fully drawn $400 million five year term loan A facility. The revolving credit facility can be used for borrowings and letters of credit to fund HESM Opco’s operating activities, capital expenditures, distributions and for other general corporate purposes. Borrowings under the five 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 five year syndicated revolving credit facility ranges from 1.275% to 2.000%. Pricing levels for the facility fee and interest-rate margins are based on HESM Opco’s ratio of total debt to EBITDA (as defined in the credit facilities). If HESM Opco obtains an investment grade credit rating, the pricing levels will be based on HESM Opco’s credit ratings in effect from time to time. The credit facilities contain covenants that require HESM Opco to maintain a ratio of total debt to EBITDA (as defined in the credit facilities) for the prior four fiscal quarters of not greater than 5.00 to 1.00 as of the last day of each fiscal quarter (5.50 to 1.00 during the specified period following certain acquisitions) and, prior to HESM Opco obtaining an investment grade credit rating, a ratio of secured debt to EBITDA for the prior four fiscal quarters of not greater than 4.00 to 1.00 as of the last day of each fiscal quarter. HESM Opco was in compliance with these financial covenants at December 31, 2020. The credit facilities are secured by first-priority perfected liens on substantially all the presently owned and after-acquired assets of HESM Opco and its direct and indirect wholly owned material domestic subsidiaries, including equity interests directly owned by such entities, subject to certain customary exclusions. At December 31, 2020, borrowings of $184 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 to Hess Corporation.
Credit Ratings
Two of the three major credit rating agencies that rate our debt have assigned an investment grade rating. Standard and Poor’s Ratings Services affirmed our credit rating at BBB- with negative outlook in October 2020 while Fitch Ratings affirmed a BBB- credit rating and stable outlook in August 2020. Moody’s Investors Service affirmed our credit rating at Ba1 with stable outlook, which is below investment grade, in March 2020.
At December 31, 2020, 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.
Contractual Obligations and Contingencies
The following table sets forth aggregate information about certain of the Corporation's consolidated contractual obligations at December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
Total
|
|
2021
|
|
2022 and
2023
|
|
2024 and
2025
|
|
Thereafter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Total Debt (excluding deferred financing costs, discounts, and interest) (a)
|
|
$
|
8,372
|
|
|
$
|
10
|
|
|
$
|
1,050
|
|
|
$
|
824
|
|
|
$
|
6,488
|
|
Finance Leases (b)
|
|
356
|
|
|
36
|
|
72
|
|
72
|
|
176
|
Operating Leases (b)
|
|
663
|
|
|
83
|
|
155
|
|
138
|
|
287
|
Purchase Obligations:
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures (b)
|
|
2,837
|
|
|
868
|
|
1,469
|
|
|
500
|
|
—
|
|
Operating expenses (b)
|
|
236
|
|
|
167
|
|
63
|
|
5
|
|
1
|
Transportation and related contracts (b)
|
|
2,867
|
|
|
310
|
|
756
|
|
493
|
|
1,308
|
Asset retirement obligations
|
|
2,116
|
|
|
105
|
|
170
|
|
86
|
|
1,755
|
|
Other liabilities
|
|
583
|
|
|
79
|
|
95
|
|
75
|
|
334
|
(a)We anticipate cash payments for interest on Total Debt of $440 million for 2021, $850 million for 2022-2023, $784 million for 2024-2025, and $3,231 million thereafter for a total of $5,305 million. These interest payments reflect our contractual obligations at December 31, 2020.
(b)Comprises obligations, including where we, as operator, have contracted directly with suppliers.
Capital expenditures represent amounts for which we were contractually committed at December 31, 2020, and include a portion of our planned capital expenditure program for 2021. Obligations for operating expenses include commitments for oil and gas production expenses, seismic purchases and other normal business expenses. Other liabilities reflect contractually committed obligations in the Consolidated Balance Sheet at December 31, 2020, including post-retirement plan liabilities for our unfunded plans and estimates for uncertain income tax positions. The Corporation and certain of its subsidiaries primarily 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.
Off-Balance Sheet Arrangements
At December 31, 2020, we had $269 million in letters of credit. See also Note 18, Guarantees, Contingencies and Commitments in the Notes to Consolidated Financial Statements.
Foreign Operations
We conduct E&P activities outside the U.S., principally in Guyana, the Joint Development Area of Malaysia/Thailand, Malaysia, Denmark, Libya, 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 update reserve estimates throughout the year based on evaluations of new wells, performance reviews, new technical data and other studies. To provide consistency throughout the Corporation, standard reserve estimation guidelines, definitions, reporting reviews and approval practices are used. The internal reserve estimates are subject to internal technical audits and senior management review. We also engage an independent third-party consulting firm to audit approximately 80% of our total proved reserves each year.
Proved reserves are calculated using the average price during the twelve-month period ending December 31 determined as an unweighted arithmetic average of the price on the first day of each month within the year, unless prices are defined by contractual agreements, excluding escalations based on future conditions. As discussed in Item 1A. Risk Factors, crude oil prices are volatile which can have an impact on our proved reserves. If crude oil prices in 2021 are at levels below that used in determining 2020 proved reserves, we may recognize negative revisions to our December 31, 2021 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 2021 above those used in determining 2020 proved reserves could result in positive revisions to proved developed and proved undeveloped reserves at December 31, 2021. It is difficult to estimate the magnitude of any potential net negative or positive change in proved reserves at December 31, 2021, due to numerous currently unknown factors, including 2021 crude oil prices, the amount of any additions to proved reserves, positive or negative revisions in proved reserves related to 2021 reservoir performance, the levels to which industry costs will change in response to 2021 crude oil prices, and management’s plans as of December 31, 2021 for developing proved undeveloped reserves. A 10% change in proved developed and proved undeveloped reserves at December 31, 2020 would result in an approximate $150 million pre-tax change in depreciation, depletion, and amortization expense for 2021 based on projected production volumes. See the Supplementary Oil and Gas Data on pages 91 through 99 in the accompanying financial statements for additional information on our oil and gas reserves.
Impairment of Long-lived Assets: We review long‑lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. Long‑lived assets are tested based on identifiable cash flows that are largely independent of the cash flows of other assets and liabilities. If the carrying amounts of the long-lived assets are not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is measured based on the estimated fair value of the assets generally determined by discounting anticipated future net cash flows, an income valuation approach, or by a market‑based valuation approach, which are Level 3 fair value measurements.
In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a stipulated amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairment will generally differ from those used in the standardized measure of discounted future net cash flows, since the standardized measure requires the use of historical twelve-month average prices.
Our impairment tests of long-lived E&P producing assets are based on our best estimates of future production volumes (including recovery factors), selling prices, operating and capital costs, the timing of future production and other factors, which are updated each time an impairment test is performed. As a result of the significant decline in crude oil prices due to the economic slowdown from the COVID-19 pandemic, we reviewed our oil and gas fields and midstream operating segment asset groups for impairment at 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 in the Notes to Consolidated Financial Statements for further details. 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 below the long-term crude oil price outlook used in the March 31, 2020 impairment test, or future estimated capital and operating costs increase significantly.
Hess Midstream LP: We consolidate the activities of our interest in Hess Midstream LP, which qualifies as a variable interest entity (VIE) under U.S. generally accepted accounting principles. We have concluded that we are the primary beneficiary of the VIE, as defined in the accounting standards, since we have the power through Hess Corporation’s 47% 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. Due to a sustained low commodity price environment, we remained in a three-year cumulative consolidated loss position at December 31, 2020. 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., Denmark, and Malaysia, while we maintain valuation allowances against net deferred tax assets in these jurisdictions. In December 2019, we reversed the valuation allowance of $60 million for Guyana upon achieving first production from the Liza Phase 1 development.
At December 31, 2020, the Consolidated Balance Sheet reflects a $5,391 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 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:
Discount rates used for measuring the present value of future plan obligations and net periodic benefit cost: The discount rates used to estimate our projected benefit obligations and net periodic benefit cost is based on a portfolio of high‑quality, fixed income debt instruments with maturities that approximate the expected payment of plan obligations. At December 31, 2020, a 0.25% decrease in the discount rate assumptions would increase projected benefit obligations by approximately $145 million and would decrease forecasted 2021 annual net periodic benefit income by approximately $10 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 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 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, 2020, a 0.25% decrease in the expected long-term rates of return on plan assets assumption would decrease forecasted 2021 annual net periodic benefit income by approximately $10 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 receivable balances, and our credit is considered for accrued 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 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. 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 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. At December 31, 2020, our reserve for estimated remediation liabilities was approximately $65 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 million in 2020 (2019: $20 million; 2018: $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.
Health and Safety Matters
The crude oil and natural gas industry is regulated at federal, state, local and foreign government levels regarding the health and safety of E&P operations. Such laws and regulations relate to, among other matters, occupational safety, the use of hydraulic fracturing to stimulate crude oil and natural gas production, well control and integrity, process safety and equipment integrity, and may include permitting and disclosure requirements, operating restrictions and other conditions on the development of crude oil and natural gas. The level of our expenditures to comply with federal, state, local and foreign country health and safety regulations is difficult to quantify as such costs are captured as mostly indistinguishable components of our capital expenditures and operating expenses. While compliance with laws and regulations relating to health and safety matters increases the overall cost of business for us and the oil and gas industry in general, it has not had, to date, a material adverse effect on our operations, financial condition or results of operations.
Occupational Safety: We are subject to the requirements set forth under federal workplace standards by the OSHA and comparable state statutes that regulate the protection of the health and safety of workers. Under OSHA and other federal and state occupational safety and health laws and laws of foreign countries in which we operate, we must develop, maintain and disclose certain information about hazardous materials used, released, or produced in our operations.
Production and Well Integrity: Our U.S. onshore production facilities are subject to U.S. federal government, state and local regulations regarding the use of hydraulic fracturing and well control and integrity. Our offshore production facilities in the Gulf of 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 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, 2020.
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, 2020, as stated in their report, which is included herein.
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By
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/s/ John P. Rielly
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By
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/s/ John B. Hess
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John P. Rielly
Executive Vice President and
Chief Financial Officer
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John B. Hess
Chief Executive Officer
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March 1, 2021
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Hess Corporation
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, 2020, 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, 2020, 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, 2020 and 2019, the related statements of consolidated income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2020, and the related notes and our report dated March 1, 2021 expressed an unqualified opinion thereon.
Basis for Opinion
The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
New York, New York
March 1, 2021
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Hess Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Hess Corporation and consolidated subsidiaries (the “Corporation”) as of December 31, 2020 and 2019, the related statements of consolidated income, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the consolidated financial position of the Corporation at December 31, 2020 and 2019, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, 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, 2020, 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 March 1, 2021 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on the Corporation’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission (SEC) 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 Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
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Depreciation, depletion and amortization of proved oil and natural gas properties
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Description of the Matter
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The net book value of the Corporation’s exploration and production assets was $10,993 million at December 31, 2020, and depreciation, depletion and amortization (DD&A) expense was $1,915 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
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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 92% of the Corporation’s proved reserves at December 31, 2020 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.
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How We Addressed the Matter in Our Audit
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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. For proved undeveloped reserves, we evaluated management’s development plans for compliance with the SEC rule that undrilled locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time, by assessing consistency of the development projection with the Corporation’s drill plan and the availability of capital relative to the drill plan. 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.
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Impairment of oil and natural gas properties
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Description of the
Matter
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The net book value of the Corporation’s exploration and production assets was $10,993 million at December 31, 2020, and impairment expense was $2,105 million for the year then ended. As described in Notes 1 and 12 to the financial statements, the Corporation reviews 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 impairments recorded in 2020 were based on estimates of fair value determined by discounting internally developed future net cash flows, a Level 3 fair value measurement. Significant inputs used in determining the discounted future net cash flows include future prices, which are determined with reference to recent historical prices and published forward prices, projected production volumes using risk adjusted oil and gas reserves and discount rates. The projected production volumes are based on geological
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and engineering evaluations of estimated in-place hydrocarbon volumes using financial and non-financial inputs including projected capital expenditures. Significant judgment is required by the Corporations’ internal petroleum engineering staff in evaluating the geological and engineering data used to estimate reserves. Estimating projected production volumes 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.
Auditing the Corporation’s impairment calculation involved a high degree of subjectivity as the determination of fair value was based on assumptions as described above about future market and economic conditions. In addition, the cash flows include projected production volumes based on risk adjusted reserve estimates developed by the Corporation’s internal engineering staff.
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How We Addressed the Matter in Our Audit
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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 impairment expense calculation. This included controls over the completeness and accuracy of the significant inputs used to estimate fair value including pricing assumptions and projected production volumes among others.
Our testing of the Corporation’s impairment calculation included, among other procedures, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data. We involved our valuation specialists to assist in evaluating the appropriateness of the methodology used in the cash flow model, as well as certain of the inputs, including reserve risk adjustment factors and projected pricing among other market inputs. We additionally evaluated 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. We performed testing procedures including testing the completeness and accuracy of the financial data used in the estimation of 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. We also performed sensitivity analyses and a retrospective comparison of forecasted cash flows to actual historical data. Finally, we tested the mathematical accuracy of the impairment calculations.
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/s/ Ernst & Young LLP
We have served as the Corporation’s auditor since 1971
New York, New York
March 1, 2021
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
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December 31,
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2020
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2019
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(In millions,
except share amounts)
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Assets
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Current Assets:
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Cash and cash equivalents
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$
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1,739
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$
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1,545
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Accounts receivable:
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From contracts with customers
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710
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940
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Joint venture and other
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150
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230
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Inventories
|
378
|
|
|
261
|
|
Other current assets
|
104
|
|
|
180
|
|
Total current assets
|
3,081
|
|
|
3,156
|
|
Property, plant and equipment:
|
|
|
|
Total — at cost
|
30,519
|
|
|
35,820
|
|
Less: Reserves for depreciation, depletion, amortization and lease impairment
|
16,404
|
|
|
19,006
|
|
Property, plant and equipment — net
|
14,115
|
|
|
16,814
|
|
Operating lease right-of-use assets — net
|
426
|
|
|
447
|
|
Finance lease right-of-use assets — net
|
168
|
|
|
299
|
|
Goodwill
|
360
|
|
|
360
|
|
Deferred income taxes
|
59
|
|
|
80
|
|
Other assets
|
612
|
|
|
626
|
|
Total Assets
|
$
|
18,821
|
|
|
$
|
21,782
|
|
Liabilities
|
|
|
|
Current Liabilities:
|
|
|
|
Accounts payable
|
$
|
200
|
|
|
$
|
411
|
|
Accrued liabilities
|
1,251
|
|
|
1,803
|
|
Taxes payable
|
81
|
|
|
97
|
|
Current maturities of long-term debt
|
10
|
|
|
—
|
|
Current portion of operating and finance lease obligations
|
81
|
|
|
199
|
|
Total current liabilities
|
1,623
|
|
|
2,510
|
|
Long-term debt
|
8,286
|
|
|
7,142
|
|
Long-term operating lease obligations
|
478
|
|
|
353
|
|
Long-term finance lease obligations
|
220
|
|
|
238
|
|
Deferred income taxes
|
342
|
|
|
415
|
|
Asset retirement obligations
|
894
|
|
|
897
|
|
Other liabilities and deferred credits
|
643
|
|
|
521
|
|
Total Liabilities
|
12,486
|
|
|
12,076
|
|
Equity
|
|
|
|
Hess Corporation stockholders’ equity:
|
|
|
|
Common stock, par value $1.00; Authorized — 600,000,000 shares:
|
|
|
|
Issued — 306,980,092 shares (2019: 304,955,472)
|
307
|
|
|
305
|
|
Capital in excess of par value
|
5,684
|
|
|
5,591
|
|
Retained earnings
|
130
|
|
|
3,535
|
|
Accumulated other comprehensive income (loss)
|
(755)
|
|
|
(699)
|
|
Total Hess Corporation stockholders’ equity
|
5,366
|
|
|
8,732
|
|
Noncontrolling interests
|
969
|
|
|
974
|
|
Total equity
|
6,335
|
|
|
9,706
|
|
Total Liabilities and Equity
|
$
|
18,821
|
|
|
$
|
21,782
|
|
The consolidated financial statements reflect the successful efforts method of accounting for oil and gas exploration and production activities.
See accompanying Notes to Consolidated Financial Statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions, except per share amounts)
|
Revenues and Non-Operating Income
|
|
|
|
|
|
Sales and other operating revenues
|
$
|
4,667
|
|
|
$
|
6,495
|
|
|
$
|
6,323
|
|
Gains on asset sales, net
|
87
|
|
|
22
|
|
|
32
|
|
Other, net
|
50
|
|
|
(7)
|
|
|
111
|
|
Total revenues and non-operating income
|
4,804
|
|
|
6,510
|
|
|
6,466
|
|
|
|
|
|
|
|
Costs and Expenses
|
|
|
|
|
|
Marketing, including purchased oil and gas
|
936
|
|
|
1,736
|
|
|
1,771
|
|
Operating costs and expenses
|
1,218
|
|
|
1,237
|
|
|
1,134
|
|
Production and severance taxes
|
124
|
|
|
184
|
|
|
171
|
|
Exploration expenses, including dry holes and lease impairment
|
351
|
|
|
233
|
|
|
362
|
|
General and administrative expenses
|
357
|
|
|
397
|
|
|
473
|
|
Interest expense
|
468
|
|
|
380
|
|
|
399
|
|
Loss on debt extinguishment
|
—
|
|
|
—
|
|
|
53
|
|
Depreciation, depletion and amortization
|
2,074
|
|
|
2,122
|
|
|
1,883
|
|
Impairment
|
2,126
|
|
|
—
|
|
|
—
|
|
Total costs and expenses
|
7,654
|
|
|
6,289
|
|
|
6,246
|
|
Income (Loss) Before Income Taxes
|
(2,850)
|
|
|
221
|
|
|
220
|
|
Provision (benefit) for income taxes
|
(11)
|
|
|
461
|
|
|
335
|
|
Net Income (Loss)
|
(2,839)
|
|
|
(240)
|
|
|
(115)
|
|
Less: Net income (loss) attributable to noncontrolling interests
|
254
|
|
|
168
|
|
|
167
|
|
Net Income (Loss) Attributable to Hess Corporation
|
(3,093)
|
|
|
(408)
|
|
|
(282)
|
|
Less: Preferred stock dividends
|
—
|
|
|
4
|
|
|
46
|
|
Net Income (Loss) Attributable to Hess Corporation Common Stockholders
|
$
|
(3,093)
|
|
|
$
|
(412)
|
|
|
$
|
(328)
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to Hess Corporation Per Common Share
|
|
|
|
|
|
Basic
|
$
|
(10.15)
|
|
|
$
|
(1.37)
|
|
|
$
|
(1.10)
|
|
Diluted
|
$
|
(10.15)
|
|
|
$
|
(1.37)
|
|
|
$
|
(1.10)
|
|
Weighted Average Number of Common Shares Outstanding (Diluted)
|
304.8
|
|
|
301.2
|
|
|
298.2
|
|
Common Stock Dividends Per Share
|
$
|
1.00
|
|
|
$
|
1.00
|
|
|
$
|
1.00
|
|
See accompanying Notes to Consolidated Financial Statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
Net Income (Loss)
|
$
|
(2,839)
|
|
|
$
|
(240)
|
|
|
$
|
(115)
|
|
Other Comprehensive Income (Loss):
|
|
|
|
|
|
Derivatives designated as cash flow hedges
|
|
|
|
|
|
Effect of hedge (gains) losses reclassified to income
|
(547)
|
|
|
(1)
|
|
|
173
|
|
Income taxes on effect of hedge (gains) losses reclassified to income
|
—
|
|
|
—
|
|
|
—
|
|
Net effect of hedge (gains) losses reclassified to income
|
(547)
|
|
|
(1)
|
|
|
173
|
|
Change in fair value of cash flow hedges
|
649
|
|
|
(462)
|
|
|
330
|
|
Income taxes on change in fair value of cash flow hedges
|
—
|
|
|
86
|
|
|
(86)
|
|
Net change in fair value of cash flow hedges
|
649
|
|
|
(376)
|
|
|
244
|
|
Change in derivatives designated as cash flow hedges, after taxes
|
102
|
|
|
(377)
|
|
|
417
|
|
Pension and other postretirement plans
|
|
|
|
|
|
(Increase) reduction in unrecognized actuarial losses
|
(205)
|
|
|
(160)
|
|
|
29
|
|
Income taxes on actuarial changes in plan liabilities
|
—
|
|
|
—
|
|
|
(6)
|
|
(Increase) reduction in unrecognized actuarial losses, net
|
(205)
|
|
|
(160)
|
|
|
23
|
|
Amortization of net actuarial losses
|
47
|
|
|
144
|
|
|
41
|
|
Income taxes on amortization of net actuarial losses
|
—
|
|
|
—
|
|
|
—
|
|
Net effect of amortization of net actuarial losses
|
47
|
|
|
144
|
|
|
41
|
|
Change in pension and other postretirement plans, after taxes
|
(158)
|
|
|
(16)
|
|
|
64
|
|
Other Comprehensive Income (Loss)
|
(56)
|
|
|
(393)
|
|
|
481
|
|
Comprehensive Income (Loss)
|
(2,895)
|
|
|
(633)
|
|
|
366
|
|
Less: Comprehensive income (loss) attributable to noncontrolling interests
|
254
|
|
|
168
|
|
|
167
|
|
Comprehensive Income (Loss) Attributable to Hess Corporation
|
$
|
(3,149)
|
|
|
$
|
(801)
|
|
|
$
|
199
|
|
See accompanying Notes to Consolidated Financial Statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
Cash Flows From Operating Activities
|
|
|
|
|
|
Net income (loss)
|
$
|
(2,839)
|
|
|
$
|
(240)
|
|
|
$
|
(115)
|
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
|
|
|
|
|
|
(Gains) on asset sales, net
|
(87)
|
|
|
(22)
|
|
|
(32)
|
|
Depreciation, depletion and amortization
|
2,074
|
|
|
2,122
|
|
|
1,883
|
|
Impairment
|
2,126
|
|
|
—
|
|
|
—
|
|
Exploratory dry hole costs
|
192
|
|
|
49
|
|
|
165
|
|
Exploration lease and other impairment
|
51
|
|
|
17
|
|
|
37
|
|
Pension settlement loss
|
—
|
|
|
93
|
|
|
4
|
|
Stock compensation expense
|
79
|
|
|
85
|
|
|
72
|
|
Noncash (gains) losses on commodity derivatives, net
|
260
|
|
|
116
|
|
|
182
|
|
Provision (benefit) for deferred income taxes and other tax accruals
|
(53)
|
|
|
17
|
|
|
(120)
|
|
Loss on debt extinguishment
|
—
|
|
|
—
|
|
|
53
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
(Increase) decrease in accounts receivable
|
267
|
|
|
(383)
|
|
|
(138)
|
|
(Increase) decrease in inventories
|
(117)
|
|
|
(16)
|
|
|
(12)
|
|
Increase (decrease) in accounts payable and accrued liabilities
|
(533)
|
|
|
4
|
|
|
88
|
|
Increase (decrease) in taxes payable
|
(16)
|
|
|
16
|
|
|
(2)
|
|
Changes in other operating assets and liabilities
|
(71)
|
|
|
(216)
|
|
|
(126)
|
|
Net cash provided by (used in) operating activities
|
1,333
|
|
|
1,642
|
|
|
1,939
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities
|
|
|
|
|
|
Additions to property, plant and equipment - E&P
|
(1,896)
|
|
|
(2,433)
|
|
|
(1,854)
|
|
Additions to property, plant and equipment - Midstream
|
(301)
|
|
|
(396)
|
|
|
(243)
|
|
Payments for Midstream equity investments
|
—
|
|
|
(33)
|
|
|
(67)
|
|
Proceeds from asset sales, net of cash sold
|
493
|
|
|
22
|
|
|
607
|
|
Other, net
|
(3)
|
|
|
(3)
|
|
|
(9)
|
|
Net cash provided by (used in) investing activities
|
(1,707)
|
|
|
(2,843)
|
|
|
(1,566)
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities
|
|
|
|
|
|
Net borrowings (repayments) of debt with maturities of 90 days or less
|
152
|
|
|
32
|
|
|
—
|
|
Debt with maturities of greater than 90 days:
|
|
|
|
|
|
Borrowings
|
1,000
|
|
|
760
|
|
|
—
|
|
Repayments
|
—
|
|
|
(8)
|
|
|
(633)
|
|
Payments on finance lease obligations
|
(7)
|
|
|
(49)
|
|
|
—
|
|
Common stock acquired and retired
|
—
|
|
|
(25)
|
|
|
(1,365)
|
|
Cash dividends paid
|
(309)
|
|
|
(316)
|
|
|
(345)
|
|
Noncontrolling interests, net
|
(261)
|
|
|
(353)
|
|
|
(211)
|
|
Other, net
|
(7)
|
|
|
11
|
|
|
28
|
|
Net cash provided by (used in) financing activities
|
568
|
|
|
52
|
|
|
(2,526)
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents
|
194
|
|
|
(1,149)
|
|
|
(2,153)
|
|
Cash and Cash Equivalents at Beginning of Year
|
1,545
|
|
|
2,694
|
|
|
4,847
|
|
Cash and Cash Equivalents at End of Year
|
$
|
1,739
|
|
|
$
|
1,545
|
|
|
$
|
2,694
|
|
See accompanying Notes to Consolidated Financial Statements.
HESS CORPORATION AND CONSOLIDATED SUBSIDIARIES
STATEMENT OF CONSOLIDATED EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
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)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
(282)
|
|
|
—
|
|
|
(282)
|
|
|
167
|
|
|
(115)
|
|
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
481
|
|
|
481
|
|
|
—
|
|
|
481
|
|
Share-based compensation
|
—
|
|
|
1
|
|
|
103
|
|
|
—
|
|
|
—
|
|
|
104
|
|
|
—
|
|
|
104
|
|
Dividends on preferred stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(46)
|
|
|
—
|
|
|
(46)
|
|
|
—
|
|
|
(46)
|
|
Dividends on common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(299)
|
|
|
—
|
|
|
(299)
|
|
|
—
|
|
|
(299)
|
|
Common stock acquired and retired
|
—
|
|
|
(25)
|
|
|
(541)
|
|
|
(814)
|
|
|
—
|
|
|
(1,380)
|
|
|
—
|
|
|
(1,380)
|
|
Noncontrolling interests, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(211)
|
|
|
(211)
|
|
Balance at December 31, 2018
|
$
|
1
|
|
|
$
|
291
|
|
|
$
|
5,386
|
|
|
$
|
4,257
|
|
|
$
|
(306)
|
|
|
$
|
9,629
|
|
|
$
|
1,259
|
|
|
$
|
10,888
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
(408)
|
|
|
—
|
|
|
(408)
|
|
|
168
|
|
|
(240)
|
|
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(393)
|
|
|
(393)
|
|
|
—
|
|
|
(393)
|
|
Preferred stock conversion
|
(1)
|
|
|
12
|
|
|
(11)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Share-based compensation
|
—
|
|
|
2
|
|
|
123
|
|
|
—
|
|
|
—
|
|
|
125
|
|
|
—
|
|
|
125
|
|
Dividends on preferred stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(4)
|
|
|
—
|
|
|
(4)
|
|
|
—
|
|
|
(4)
|
|
Dividends on common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(310)
|
|
|
—
|
|
|
(310)
|
|
|
—
|
|
|
(310)
|
|
Conversion of Midstream structure
|
—
|
|
|
—
|
|
|
15
|
|
|
—
|
|
|
—
|
|
|
15
|
|
|
(22)
|
|
|
(7)
|
|
Sale of water business to Hess Infrastructure Partners
|
—
|
|
|
—
|
|
|
78
|
|
|
—
|
|
|
—
|
|
|
78
|
|
|
(78)
|
|
|
—
|
|
Noncontrolling interests, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(353)
|
|
|
(353)
|
|
Balance at December 31, 2019
|
$
|
—
|
|
|
$
|
305
|
|
|
$
|
5,591
|
|
|
$
|
3,535
|
|
|
$
|
(699)
|
|
|
$
|
8,732
|
|
|
$
|
974
|
|
|
$
|
9,706
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,093)
|
|
|
—
|
|
|
(3,093)
|
|
|
254
|
|
|
(2,839)
|
|
Other comprehensive income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(56)
|
|
|
(56)
|
|
|
—
|
|
|
(56)
|
|
Share-based compensation
|
—
|
|
|
2
|
|
|
93
|
|
|
(5)
|
|
|
—
|
|
|
90
|
|
|
—
|
|
|
90
|
|
Dividends on common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(307)
|
|
|
—
|
|
|
(307)
|
|
|
—
|
|
|
(307)
|
|
Noncontrolling interests, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(259)
|
|
|
(259)
|
|
Balance at December 31, 2020
|
$
|
—
|
|
|
$
|
307
|
|
|
$
|
5,684
|
|
|
$
|
130
|
|
|
$
|
(755)
|
|
|
$
|
5,366
|
|
|
$
|
969
|
|
|
$
|
6,335
|
|
See accompanying Notes to Consolidated Financial Statements.
1. Nature of Operations, Basis of Presentation and Summary of Accounting Policies
Unless the context indicates otherwise, references to “Hess”, “the Corporation”, “Registrant”, “we”, “us” and “our” refer to the consolidated business operations of Hess Corporation and its affiliates.
Nature of Business: Hess Corporation, incorporated in the State of Delaware in 1920, is a global E&P company engaged in exploration, development, production, transportation, purchase and sale of crude oil, natural gas liquids, and natural gas with production operations located primarily in the United States (U.S.), Guyana, the Malaysia/Thailand Joint Development Area (JDA), Malaysia, and Denmark. We conduct exploration activities primarily offshore Guyana, the U.S. Gulf of Mexico, and offshore Suriname and Canada.
Our Midstream operating segment, which is comprised of Hess Corporation’s 47% consolidated ownership interest in Hess Midstream LP at December 31, 2020 (see Note 4, Hess Midstream LP) provides fee-based services, including gathering, compressing and processing natural gas and fractionating NGL; gathering, terminaling, loading and transporting crude oil and NGL; storing and terminaling propane, and water handling services primarily in the Bakken shale play in the Williston Basin area of North Dakota.
Basis of Presentation and Principles of Consolidation: The consolidated financial statements include the accounts of Hess Corporation and entities in which we own more than a 50% voting interest. Commencing December 16, 2019, we consolidate Hess Midstream LP, a variable interest entity that acquired Hess Infrastructure Partners LP (HIP), based on our conclusion that we have the power through Hess Corporation’s 47% consolidated ownership interest in Hess Midstream LP to direct those activities that most significantly impact the economic performance of Hess Midstream LP, and are obligated to absorb losses or have the right to receive benefits that could potentially be significant to Hess Midstream LP. Prior to December 16, 2019, we consolidated HIP, also a variable interest entity based on the conclusion that we had the power to direct the activities that most significantly impacted the economic performance of HIP, and were obligated to absorb losses or had the right to receive benefits that could potentially be significant to HIP. Our undivided interests in unincorporated oil and gas E&P ventures are proportionately consolidated. Investments in affiliated companies, 20% to 50% owned and where we have the ability to influence the operating or financial decisions of the affiliate, are accounted for using the equity method.
Estimates and Assumptions: In preparing financial statements in conformity with GAAP, management makes estimates and assumptions that affect the reported amounts of assets and liabilities in the Consolidated Balance Sheet and revenues and expenses in the Statement of Consolidated Income. Actual results could differ from those estimates. Estimates made by management include oil and gas reserves, asset and other valuations, depreciable lives, pension liabilities, legal and environmental obligations, asset retirement obligations and income taxes.
Revenue Recognition:
Exploration and Production
The E&P segment recognizes revenue from the sale of crude oil, NGL, and natural gas as performance obligations under contracts with customers are satisfied. Our responsibilities to deliver each unit of quantity of crude oil, NGL, and natural gas under these contracts represent separate, distinct performance obligations. These performance obligations are satisfied at the point in time control of each unit of quantity transfers to the customer. Generally, the control of each unit of quantity transfers to the customer upon the transfer of legal title at the point of physical delivery. Pricing is variable and is determined with reference to a particular market or pricing index, plus or minus adjustments reflecting quality or location differentials.
For long-term international natural gas contracts with ship-or-pay provisions, our obligation to stand-ready to provide a minimum volume over each commitment period represents separate, distinct performance obligations. Penalties owed against future deliveries of natural gas due to delivery of volumes below minimum delivery commitments are recognized as reductions to revenue in the commitment period when the shortfall occurs. Long-term international natural gas contracts may also contain take-or-pay provisions whereby the customer is required to pay for volumes not taken that are below minimum volume commitments but the customer has certain make-up rights to receive shortfall volumes in subsequent periods. Shortfall payments received from customers when volumes purchased are below the minimum volume commitment are deferred upon receipt as a contract liability. Revenue is recognized at the earlier of when we deliver the make-up volumes in subsequent periods or when it becomes remote that the customer will exercise their make-up rights.
Certain crude oil, NGL, and natural gas volumes are purchased by Hess from third parties, including working interest partners and royalty owners in certain Hess-operated properties, before they are sold to customers. Where control over the crude oil, NGL, or natural gas transfers to Hess before the volumes are transferred to the customer, revenue and the associated cost of purchased volumes are presented on a gross basis in the Statement of Consolidated Income within Sales and other operating revenues and Marketing, including purchased oil and gas, respectively. Where control of crude oil, NGL, or natural gas is not transferred to Hess, revenue is
presented net of the associated cost of purchased volumes within Sales and other operating revenues in the Statement of Consolidated Income.
Contract Duration and Pricing:
Contracts with customers for the sale of U.S. crude oil, NGL, and natural gas primarily include those contracts that involve the short-term sale of volumes during a specified period, and those contracts that automatically renew on a periodic basis until either party cancels. We have certain long-term contracts with customers for the sale of U.S. natural gas and NGL that have remaining durations ranging from one to twelve 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. At December 31, 2020 and 2019, there were no contract assets or contract liabilities.
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 the exemption from disclosure of revenue recognizable in future periods as these performance obligations are satisfied.
Sales-based Taxes:
We exclude sales-based taxes that are collected from customers from the transaction price in our contracts with customers. Accordingly, revenue from contracts with customers is net of sales-based taxes that are collected from customers and remitted to taxing authorities.
Midstream
Our Midstream segment provides gathering, compression, processing, fractionation, storage, terminaling, loading and transportation, and water handling services.
The Midstream segment has multiple long-term, fee-based commercial agreements with certain subsidiaries of Hess, each generally with an initial ten-year term that can be extended for an additional ten-year term at the unilateral right of Hess Midstream. These contracts have minimum volumes the customer is obligated to provide each calendar quarter. The minimum volume commitments are subject to fluctuation based on nominations covering substantially all of our E&P segment’s production and projected third-party volumes that will be purchased in the Bakken. As the minimum volume commitments are subject to fluctuation, and as these contracts contain fee inflation escalators and fee recalculation mechanisms, substantially all of the transaction price at contract inception is variable. The midstream segment also has long-term, fee based commercial agreements for water handling services with a subsidiary of Hess with an initial 14 year term that can be extended for an additional ten-year term at the unilateral right of Hess Midstream. Water handling services are provided for an agreed-upon fee per barrel or the reimbursement of third-party fees.
The Midstream segment’s responsibilities to provide each of the above services for each year under each of the commercial agreements are considered separate, distinct performance obligations. Revenue is recognized for each performance obligation under these commercial agreements over-time as services are rendered using the output method, measured using the amount of volumes serviced during the period. The Midstream segment has elected the practical expedient under the provisions of ASC 606, Revenue from Contracts with Customers to recognize revenue in the amount it is entitled to invoice. If the commercial agreements have ship-or-pay provisions, the Midstream segment’s responsibility to stand-ready to service a minimum volume over each quarterly commitment period represent separate, distinct performance obligations. Shortfall payments received under ship-or-pay provisions are recognized as revenue in the calendar quarter the shortfall occurs as the customer does not have make-up rights beyond the calendar
quarter end of the quarterly commitment period. All revenues, receivables, and contract balances arising from the commercial agreements between the Midstream segment and the Hess subsidiaries that are the counterparty to the commercial agreements are eliminated upon consolidation.
On December 30, 2020, Hess Midstream exercised its renewal options to extend the terms of certain gas gathering, crude oil gathering, gas processing and fractionation, storage, and terminal and export commercial agreements for the secondary term through December 31, 2033. There were no changes to any provisions of the existing commercial agreements as a result of the exercise of the renewal options.
Exploration and Development Costs: E&P activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Annual lease rentals, exploration expenses and exploratory dry hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized.
The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of a project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors, firm plans for additional drilling and other factors.
Depreciation, Depletion and Amortization: We record depletion expense for acquisition costs of proved properties using the units of production method over proved oil and gas reserves. Depreciation and depletion expense for oil and gas production facilities and wells is calculated using the units of production method over proved developed oil and gas reserves. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations and other factors. Depreciation of all other plant and equipment is determined on the straight-line method based on estimated useful lives.
Capitalized Interest: Interest from external borrowings is capitalized on material projects using the weighted average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at first production from the field. Capitalized interest is depreciated in the same manner as the depreciation of the underlying assets.
Impairment of Long‑lived Assets: We review long‑lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts of the long-lived assets are not expected to be recovered by estimated undiscounted future net cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is measured based on the estimated fair value of the assets generally determined by discounting anticipated future net cash flows, an income valuation approach, or by a market‑based valuation approach, which are Level 3 fair value measurements.
In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes and discounted at a risk-adjusted rate. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a projected amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairment will generally differ from those used in the standardized measure of discounted future net cash flows reported in Supplementary Oil and Gas Data, since the standardized measure requires the use of historical twelve-month average prices. As a result of the significant decline in crude oil prices in the first quarter of 2020, we tested our oil and gas properties for impairment at March 31, 2020. See Note 12, Impairment.
Impairment of Goodwill: Goodwill is tested for impairment annually on October 1st or when events or circumstances indicate that the carrying amount of the goodwill may not be recoverable. To determine whether goodwill is impaired, the fair value of a reporting unit is compared with its carrying 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. At December 31, 2020, goodwill of $360 million relates to the Midstream operating segment.
Cash and Cash Equivalents: Cash and cash equivalents primarily comprises cash on hand and on deposit, as well as highly liquid investments that are readily convertible into cash and have maturities of three months or less when acquired.
Inventories: Produced and unsold crude oil and NGL are valued at the lower of cost or net realizable value. Cost is determined using the average cost of production plus any transport cost incurred in bringing the volumes to their present location. Materials and
supplies are valued at cost. Obsolete or surplus materials identified during periodic reviews are valued at the lower of cost or estimated net realizable value.
Leases: We determine if an arrangement is a lease at inception by evaluating whether the contract conveys the right to control an identified asset during the period of use. Right-of-use (ROU) assets represent our right to use an identified asset for the lease term and lease obligations represent our obligation to make payments as set forth in the lease arrangement. ROU assets and lease liabilities are recognized in the Consolidated Balance Sheet as operating leases or finance leases at the commencement date based on the present value of the minimum lease payments over the lease term. Where the implicit discount rate in a lease is not readily determinable, we use our incremental borrowing rate based on information available at the commencement date for determining the present value of the minimum lease payments. The lease term used in measurement of our lease obligations includes options to extend or terminate the lease when, in our judgment, it is reasonably certain that we will exercise that option. Variable lease payments that depend on an index or a rate are included in the measurement of lease obligations using the index or rate at the commencement date. Variable lease payments that vary because of changes in facts or circumstances after the commencement date of the lease are not included in the minimum lease payments used to measure lease obligations. We have agreements that include financial obligations for lease and nonlease components. For purposes of measuring lease obligations, we have elected not to separate nonlease components from lease components for the following classes of assets: drilling rigs, office space, offshore vessels, and aircraft. We apply a portfolio approach to account for operating lease ROU assets and liabilities for certain vehicles, railcars, field equipment and office equipment leases.
Finance lease cost is recognized as amortization of the ROU asset and interest expense on the lease liability. Operating lease cost is generally recognized on a straight-line basis. Operating lease costs for drilling rigs used to drill development wells and successful exploration wells are capitalized. Operating lease cost for other ROU assets used in oil and gas producing activities are either capitalized or expensed on a straight-line basis based on the nature of operation for which the ROU asset is utilized.
Leases with an initial term of 12 months or less are not recorded on the balance sheet as permitted under ASC 842. We recognize lease cost for short-term leases on a straight-line basis over the term of the lease. Some of our leases include one or more options to renew. The renewal option is at our sole discretion and is not included in the lease term for measurement of the lease obligation unless we are reasonably certain at the commencement date of the lease, to renew the lease.
Income Taxes: Deferred income taxes are determined using the liability method. We have net operating loss carryforwards or credit carryforwards in multiple jurisdictions and have recorded deferred tax assets for those losses and credits. Additionally, we have deferred tax assets due to temporary differences between the book basis and tax basis of certain assets and liabilities. Regular assessments are made as to the likelihood of those deferred tax assets being realized. If, when tested under the relevant accounting standards, it is more likely than not that some or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to the amount that is expected to be realized. The accounting standards require the evaluation of all available positive and negative evidence giving weight based on the evidence’s relative objectivity. In evaluating potential sources of positive evidence, we consider the reversal of taxable temporary differences, taxable income in carryback and carryforward periods, the availability of tax planning strategies, the existence of appreciated assets, estimates of future taxable income, and other factors. In evaluating potential sources of negative evidence, we consider a cumulative loss in recent years, any history of operating losses or tax credit carryforwards expiring unused, losses expected in early future years, unsettled circumstances that, if unfavorably resolved, would adversely affect future operations and profit levels on a continuing basis in future years, and any carryback or carryforward period so brief that a significant deductible temporary difference expected to reverse in a single year would limit realization of tax benefits. We assign cumulative historical losses significant weight in the evaluation of realizability relative to more subjective evidence such as forecasts of future income. In addition, we recognize the financial statement effect of a tax position only when management believes that it is more likely than not, that based on the technical merits, the position will be sustained upon examination. We are no longer indefinitely reinvested with respect to the book in excess of tax basis in the investment in our foreign subsidiaries. Because of U.S. tax reform we expect that the future reversal of such temporary differences will occur free of material taxation. We classify interest and penalties associated with uncertain tax positions as income tax expense. We account for the U.S. tax effect of global intangible low-taxed income earned by foreign subsidiaries in the period that such income is earned. We utilize the aggregate approach for releasing disproportionate income tax effects from Accumulated other comprehensive income (loss).
Asset Retirement Obligations: We have material legal obligations to remove and dismantle long‑lived assets and to restore land or the seabed at certain E&P locations. We initially recognize a liability for the fair value of legally required asset retirement obligations in the period in which the retirement obligations are incurred and capitalize the associated asset retirement costs as part of the carrying amount of the long‑lived assets. In subsequent periods, the liability is accreted, and the asset is depreciated over the useful life of the related asset. Fair value is determined by applying a credit adjusted risk-free rate to the undiscounted expected future abandonment expenditures. Changes in estimates prior to settlement result in adjustments to both the liability and related asset values, unless the field has ceased production, in which case changes are recognized in the Statement of Consolidated Income.
Retirement Plans: We recognize the funded status of defined benefit postretirement plans in the Consolidated Balance Sheet. The funded status is measured as the difference between the fair value of plan assets and the projected benefit obligation. We recognize the net changes in the funded status of these plans in the year in which such changes occur. Actuarial gains and losses in
excess of 10% of the greater of the benefit obligation or the market value of assets are amortized over the average remaining service period of active employees or the remaining average expected life if a plan’s participants are predominantly inactive.
Derivatives: We utilize derivative instruments for financial risk management activities. In these activities, we may use futures, forwards, options and swaps, individually or in combination, to mitigate our exposure to fluctuations in prices of crude oil and natural gas, as well as changes in interest and foreign currency exchange rates.
All derivative instruments are recorded at fair value in the Consolidated Balance Sheet. Our policy for recognizing the changes in fair value of derivatives varies based on the designation of the derivative. The changes in fair value of derivatives that are not designated as hedges are recognized currently in earnings. Derivatives may be designated as hedges of expected future cash flows or forecasted transactions (cash flow hedges), or hedges of changes in fair value of recognized assets and liabilities or of unrecognized firm commitments (fair value hedges). Changes in fair value of derivatives that are designated as cash flow hedges are recorded as a component of other comprehensive income (loss). Amounts included in Accumulated other comprehensive income (loss) for cash flow hedges are reclassified into earnings in the same period that the hedged item is recognized in earnings. Changes in fair value of derivatives designated as fair value hedges are recognized currently in earnings. The change in fair value of the related hedged item is recorded as an adjustment to its carrying amount and recognized currently in earnings.
Fair Value Measurements: We use various valuation approaches in determining fair value for financial instruments, including the market and income approaches. Our fair value measurements also include non-performance risk and time value of money considerations. Counterparty credit is considered for receivable balances, and our credit is considered for accrued liabilities. We also record certain nonfinancial assets and liabilities at fair value when required by GAAP. These fair value measurements are recorded in connection with business combinations, qualifying nonmonetary exchanges, the initial recognition of asset retirement obligations and any impairment of long‑lived assets, equity method investments or goodwill. We determine fair value in accordance with the fair value measurements accounting standard which established a hierarchy for the inputs used to measure fair value based on the source of the inputs, which generally range from quoted prices for identical instruments in a principal trading market (Level 1) to estimates determined using related market data (Level 3), including discounted cash flows and other unobservable data. Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. When Level 1 inputs are available within a particular market, those inputs are selected for determination of fair value over Level 2 or 3 inputs in the same market. Multiple inputs may be used to measure fair value; however, the level assigned to a fair value measurement is based on the lowest significant input level within this fair value hierarchy.
Details on the methods and assumptions used to determine the fair values are as follows:
Fair value measurements based on Level 1 inputs: Measurements that are most observable are based on quoted prices of identical instruments obtained from the principal markets in which they are traded. Closing prices are both readily available and representative of fair value. Market transactions occur with sufficient frequency and volume to assure liquidity.
Fair value measurements based on Level 2 inputs: Measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid are considered Level 2. Measurements based on Level 2 inputs include over-the-counter derivative instruments that are priced on an exchange-traded curve but have contractual terms that are not identical to exchange-traded contracts.
Fair value measurements based on Level 3 inputs: Measurements that are least observable are estimated from related market data, determined from sources with little or no market activity for comparable contracts or are positions with longer durations. Fair values determined using discounted cash flows and other unobservable data are also classified as Level 3.
Netting of Financial Instruments: We generally enter into master netting arrangements to mitigate legal and counterparty credit risk. Master netting arrangements are generally accepted overarching master contracts that govern all individual transactions with the same counterparty entity as a single legally enforceable agreement. The U.S. Bankruptcy Code provides for the enforcement of certain termination and netting rights under certain types of contracts upon the bankruptcy filing of a counterparty, commonly known as the “safe harbor” provisions. If a master netting arrangement provides for termination and netting upon the counterparty’s bankruptcy, these rights are generally enforceable with respect to “safe harbor” transactions. If these arrangements provide the right of offset and our intent and practice is to offset amounts in the case of such a termination, our policy is to record the fair value of derivative assets and liabilities on a net basis. In the normal course of business, we rely on legal and credit risk mitigation clauses providing for adequate credit assurance as well as close‑out netting, including two‑party netting and single counterparty multilateral netting. As applied to us, “two‑party netting” is the right to net amounts owing under safe harbor transactions between a single defaulting counterparty entity and a single Hess entity, and “single counterparty multilateral netting” is the right to net amounts owing under safe harbor transactions among a single defaulting counterparty entity and multiple Hess entities. We are reasonably assured that these netting rights would be upheld in a bankruptcy proceeding in the U.S. in which the defaulting counterparty is a debtor under the U.S. Bankruptcy Code.
Share-based Compensation: We account for share-based compensation based on the fair value of the award on the date of grant. The fair value of all share‑based compensation is recognized over the requisite service period for the entire award, whether the award was granted with ratable or cliff vesting terms, net of actual forfeitures. We estimate fair value at the date of grant using a
Black‑Scholes valuation model for employee stock options and a Monte Carlo simulation model for performance share units (PSUs). Fair value of restricted stock is based on the market value of the underlying shares at the date of grant.
Foreign Currency Translation: The U.S. Dollar is the functional currency (primary currency in which business is conducted) for our foreign operations. Adjustments resulting from remeasuring monetary assets and liabilities that are denominated in a currency other than the functional currency are recorded in Other, net in the Statement of Consolidated Income.
Maintenance and Repairs: Maintenance and repairs are expensed as incurred. Capital improvements are recorded as additions in Property, plant and equipment.
Environmental Expenditures: We accrue and expense the undiscounted environmental costs necessary to remediate existing conditions related to past operations when the future costs are probable and reasonably estimable. At year‑end 2020, our reserve for estimated remediation liabilities was approximately $65 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 the first quarter of 2020, we adopted Accounting Standards Update (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 with the prior "incurred loss" model. We calculate expected credit losses for our receivables using the probability of default and the expected loss given default. Historical data, current market conditions, and forecasts of future economic conditions are used to determine the probability of default and the expected loss given default. The adoption of this ASU did not have a material impact to our financial statements.
2. Inventories
Inventories at December 31 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
|
|
|
|
(In millions)
|
Crude oil and natural gas liquids
|
$
|
226
|
|
|
$
|
92
|
|
Materials and supplies
|
152
|
|
|
169
|
|
Total Inventories
|
$
|
378
|
|
|
$
|
261
|
|
In the first quarter of 2020, we recognized charges of $53 million ($52 million after income taxes) recorded in Marketing, including purchased oil and gas to reflect crude oil inventories at net realizable value at March 31, 2020.
In 2020, we chartered three VLCCs to load and transport a total of 6.3 million barrels of Bakken crude oil for sale in Asian markets. The first VLCC cargo of 2.1 million barrels was sold in September 2020. We have entered into agreements for the sale of the remaining 4.2 million barrels of crude oil loaded on the second and third VLCCs in the first quarter of 2021. At December 31, 2020, crude oil inventories included $164 million associated with the cost of these volumes.
3. Property, Plant and Equipment
Property, plant and equipment at December 31 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
|
|
|
|
(In millions)
|
Exploration and Production
|
|
|
|
Unproved properties
|
$
|
164
|
|
|
$
|
168
|
|
Proved properties
|
2,930
|
|
|
3,304
|
|
Wells, equipment and related facilities
|
23,224
|
|
|
28,404
|
|
|
26,318
|
|
|
31,876
|
|
Midstream
|
4,163
|
|
|
3,904
|
|
Corporate and Other
|
38
|
|
|
40
|
|
Total — at cost
|
30,519
|
|
|
35,820
|
|
Less: Reserves for depreciation, depletion, amortization and lease impairment
|
16,404
|
|
|
19,006
|
|
Property, Plant and Equipment — Net
|
$
|
14,115
|
|
|
$
|
16,814
|
|
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
Balance at January 1
|
$
|
584
|
|
|
$
|
418
|
|
|
$
|
304
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
111
|
|
|
224
|
|
|
128
|
|
Reclassifications to wells, facilities and equipment based on the determination of proved reserves
|
(111)
|
|
|
(58)
|
|
|
—
|
|
Capitalized exploratory well costs charged to expense
|
(125)
|
|
|
—
|
|
|
(14)
|
|
|
|
|
|
|
|
Balance at December 31
|
$
|
459
|
|
|
$
|
584
|
|
|
$
|
418
|
|
Number of Wells at December 31
|
22
|
|
|
31
|
|
|
24
|
|
During the three years ended December 31, 2020, additions to capitalized exploratory well costs primarily related to drilling at the Stabroek Block, offshore Guyana. Other drilling activity included the Esox prospect in the Gulf of Mexico during 2019 and the Bunga prospect in the North Malay Basin, offshore Peninsular Malaysia during 2018.
Reclassifications to wells, facilities and equipment based on the determination of proved reserves in 2020 resulted from sanctions of the Payara Field development on the Stabroek Block, offshore Guyana, and an additional phase of development at the North Malay Basin, offshore Peninsular Malaysia. In 2019, reclassifications to wells, facilities and equipment resulted from sanction of the Liza Phase 2 development on the Stabroek Block and the Esox tieback well to the Tubular Bells Field in the Gulf of Mexico.
Capitalized exploratory well costs charged to expense in 2020 included $125 million, primarily related to the northern portion of the Shenzi Field (Hess 28%) in the Gulf of Mexico due to reprioritization of our forward capital program in response to the significant decline in crude oil prices. In 2018, in Canada, offshore Nova Scotia (Hess 50% participating interest), the operator, BP Canada, completed drilling of the Aspy exploration well, which did not encounter commercial quantities of hydrocarbons. As a result, we expensed well costs totaling $120 million in 2018, of which $14 million was incurred in 2017. The preceding table excludes well costs incurred and expensed during 2020 of $67 million (2019: $49 million; 2018: $151 million).
Exploratory well costs capitalized for greater than one year following completion of drilling were $342 million at December 31, 2020, separated by year of completion as follows (in millions):
|
|
|
|
|
|
2019
|
$
|
173
|
|
2018
|
105
|
|
2017
|
27
|
|
2016
|
—
|
|
2015
|
37
|
|
|
$
|
342
|
|
Guyana: Approximately 85% of the capitalized well costs in excess of one year relate to successful exploration wells where hydrocarbons were encountered on the Stabroek Block (Hess 30%), offshore Guyana. The operator plans further appraisal drilling and is conducting pre-development planning for additional phases of development beyond the three previously sanctioned development projects on the Block.
JDA: Approximately 10% of the capitalized well costs in excess of one year relates to the JDA (Hess 50%) in the Gulf of Thailand, where hydrocarbons were encountered in three successful exploration wells drilled in the western part of Block A-18. The operator has submitted a development plan concept to the regulator to facilitate ongoing commercial negotiations for an extension of the existing gas sales contract to include development of the western part of the Block.
Malaysia: Approximately 5% of the capitalized well costs in excess of one year relates to North Malay Basin (Hess 50%), offshore Peninsular Malaysia, where hydrocarbons were encountered in one successful exploration well. Subsurface evaluation and pre-development studies for future phases of development are ongoing.
4. Hess Midstream LP
Prior to December 16, 2019, the Midstream segment was primarily comprised of HIP, a 50/50 joint venture between Hess Corporation and Global Infrastructure Partners (GIP), formed to own, operate, develop and acquire a diverse set of midstream assets to provide fee-based services to Hess and third-party customers. HIP was initially formed on May 21, 2015, with Hess selling 50% of HIP to GIP for approximately $2.6 billion on July 1, 2015.
On April 10, 2017, HIP completed an initial public offering (IPO) of 16,997,000 common units, representing 30.5% limited partnership interests in its subsidiary Hess Midstream Partners LP (Hess Midstream Partners), for net proceeds of approximately
$365.5 million. In connection with the IPO, HIP contributed a 20% controlling economic interest in each of Hess North Dakota Pipeline Operations LP, Hess TGP Operations LP, and Hess North Dakota Export Logistics Operations LP, and a 100% economic interest in Hess Mentor Storage Holdings LLC (collectively the “Contributed Businesses”). In exchange for the contributed businesses, Hess and GIP each received common and subordinated units representing a direct 33.75% limited partner interest in Hess Midstream Partners and a 50% indirect ownership interest through HIP in Hess Midstream Partners’ general partner, which had a 2% economic interest in Hess Midstream Partners plus incentive distribution rights.
On March 1, 2019, HIP acquired Hess’s existing Bakken water services business for $225 million in cash. As a result of this transaction, we recorded an after-tax gain of $78 million in additional paid-in capital with an offsetting reduction to noncontrolling interest to reflect the adjustment to GIP’s noncontrolling interest in HIP. On March 22, 2019, HIP and Hess Midstream Partners acquired crude oil and gas gathering assets, and HIP acquired water gathering assets of Summit Midstream Partners LP’s Tioga Gathering System for aggregate cash consideration of approximately $90 million, with the potential for an additional $10 million of contingent payments in future periods subject to certain future performance metrics. On January 25, 2018, Hess Midstream Partners entered into a 50/50 joint venture with Targa Resources Corp. to construct a new 200 million standard cubic feet per day gas processing plant called Little Missouri 4 (LM4). The plant, which is operated by Targa, was placed into service in the third quarter of 2019.
On December 16, 2019, Hess Midstream Partners acquired HIP, including HIP’s 80% interest in Hess Midstream Partners’ oil and gas midstream assets, HIP’s water services business and the outstanding economic general partner interest and incentive distribution rights in Hess Midstream Partners LP. In addition, Hess Midstream Partners’ organizational structure converted from a master limited partnership into an “Up-C” structure in which Hess Midstream Partners’ public unitholders received newly issued Class A shares in a new public entity named Hess Midstream LP (Hess Midstream), which is taxed as a corporation for U.S. federal and state income tax purposes. Hess Midstream Partners changed its name to “Hess Midstream Operations LP” (HESM Opco) and became a consolidated subsidiary of Hess Midstream, the new publicly listed entity. As consideration for the acquisition, Hess received a cash payment of $301 million and approximately 115 million newly issued HESM Opco Class B units. After giving effect to the acquisition and related transactions, public shareholders of Class A shares in Hess Midstream own 6% of the consolidated entity on an as-exchanged basis and Hess and GIP each own 47% of the consolidated entity on an as-exchanged basis, primarily through the sponsors’ ownership of Class B units in HESM Opco that are exchangeable into Class A shares of Hess Midstream on a one-for-one basis, or referred to as “Hess Corporation’s 47% consolidated ownership in Hess Midstream LP”.
At December 31, 2020, Hess Midstream liabilities totaling $2,026 million (2019: $1,941 million) are on a nonrecourse basis to Hess Corporation, while Hess Midstream assets available to settle the obligations of Hess Midstream included Cash and cash equivalents totaling $3 million (2019: $3 million), Property, plant and equipment, net totaling $3,111 million (2019: $3,010 million) and an equity-method investment of $108 million (2019: $108 million) in LM4.
5. Accrued Liabilities
The following table provides detail of our accrued liabilities at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
|
|
|
|
(In millions)
|
Accrued capital expenditures
|
$
|
345
|
|
|
$
|
616
|
|
Accrued operating and marketing expenditures
|
325
|
|
|
479
|
|
Accrued payments to royalty and working interest owners
|
170
|
|
|
260
|
|
Accrued interest on debt
|
126
|
|
|
126
|
|
Accrued compensation and benefits
|
117
|
|
|
166
|
|
Current portion of asset retirement obligations
|
105
|
|
|
127
|
|
Other accruals
|
63
|
|
|
29
|
|
Total Accrued Liabilities
|
$
|
1,251
|
|
|
$
|
1,803
|
|
6. Leases
Operating and finance lease obligations at December 31 included in the Consolidated Balance Sheet were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Leases
|
|
Finance Leases
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Right-of-use assets — net (a)
|
$
|
426
|
|
|
$
|
447
|
|
|
$
|
168
|
|
|
$
|
299
|
|
Lease obligations:
|
|
|
|
|
|
|
|
Current
|
$
|
63
|
|
|
$
|
182
|
|
|
$
|
18
|
|
|
$
|
17
|
|
Long-term
|
478
|
|
|
353
|
|
|
220
|
|
|
238
|
|
Total lease obligations
|
$
|
541
|
|
|
$
|
535
|
|
|
$
|
238
|
|
|
$
|
255
|
|
(a)At December 31, 2020, finance lease ROU assets had a cost of $212 million (2019: $381 million) and accumulated amortization of $44 million (2019: $82 million).
Lease obligations represent 100% of the present value of future minimum lease payments in the lease arrangement. Where we have contracted directly with a lessor in our role as operator of an unincorporated oil and gas venture, we bill our partners their proportionate share for reimbursements as payments under lease agreements become due pursuant to the terms of our joint operating and other agreements.
The nature of our leasing arrangements at December 31, 2020 was as follows:
Operating leases: In the normal course of business, we primarily lease drilling rigs, equipment, logistical assets (offshore vessels, aircraft, and shorebases), and office space.
Finance leases: In 2018, we entered into a sale and lease-back arrangement for a floating storage and offloading vessel (FSO) to handle produced condensate at North Malay Basin, offshore Peninsular Malaysia. At December 31, 2020, the remaining lease term for the FSO was 12.8 years.
Maturities of lease obligations at December 31, 2020 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Leases
|
|
Finance
Leases
|
|
|
|
|
|
(In millions)
|
2021
|
$
|
83
|
|
|
$
|
36
|
|
2022
|
83
|
|
|
36
|
|
2023
|
72
|
|
|
36
|
|
2024
|
71
|
|
|
36
|
|
2025
|
67
|
|
|
36
|
|
Remaining years
|
287
|
|
|
176
|
|
Total lease payments
|
663
|
|
|
356
|
|
Less: Imputed interest
|
(122)
|
|
|
(118)
|
|
Total lease obligations
|
$
|
541
|
|
|
$
|
238
|
|
The following information relates to the Operating and Finance leases at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Leases
|
|
Finance Leases
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
Weighted average remaining lease term
|
10.3 years
|
|
5.4 years
|
|
12.8 years
|
|
13.8 years
|
Range of remaining lease terms
|
0.1 - 15.5 years
|
|
0.1 - 16.1 years
|
|
12.8 years
|
|
13.8 years
|
Weighted average discount rate
|
4.0%
|
|
4.3%
|
|
7.9%
|
|
7.9%
|
The components of lease costs for the years ended December 31, 2020 and 2019 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
|
|
|
|
(In millions)
|
Operating lease cost
|
$
|
200
|
|
|
$
|
414
|
|
Finance lease cost:
|
|
|
|
Amortization of leased assets
|
31
|
|
|
43
|
|
Interest on lease obligations
|
20
|
|
|
21
|
|
Short-term lease cost (a)
|
199
|
|
|
164
|
|
Variable lease cost (b)
|
38
|
|
|
89
|
|
Sublease income (c)
|
(15)
|
|
|
(12)
|
|
Total lease cost (d)
|
$
|
473
|
|
|
$
|
719
|
|
(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.
(d)Prior to the adoption of ASC 842, we incurred total rental expense of $154 million and income from subleases of $8 million in 2018.
The above lease costs represent 100% of the lease payments due for the period, including where we as operator have contracted directly with suppliers. As the payments under lease agreements where we are operator become due, we bill our partners their proportionate share for reimbursement pursuant to the terms of our joint operating agreements. Reimbursements are not reflected in the table above. Certain lease costs above associated with exploration and development activities are included in capital expenditures.
Supplemental cash flow information related to leases for the years ended December 31, 2020 and 2019 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Leases
|
|
Finance Leases
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Cash paid for amounts included in the measurement of lease obligations:
|
|
|
|
|
|
|
|
Operating cash flows (a)
|
$
|
218
|
|
|
$
|
419
|
|
|
$
|
20
|
|
|
$
|
21
|
|
Financing cash flows (a)
|
—
|
|
|
—
|
|
|
17
|
|
|
55
|
|
Noncash transactions:
|
|
|
|
|
|
|
|
Leased assets recognized for new lease obligations incurred
|
51
|
|
|
14
|
|
|
—
|
|
|
—
|
|
Changes in leased assets and lease obligations due to lease modifications (b)
|
123
|
|
|
14
|
|
|
—
|
|
|
—
|
|
(a)Amounts represent gross lease payments before any recovery from partners.
(b)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:
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
|
|
|
|
(In millions)
|
Debt - Hess Corporation:
|
|
|
|
Fixed-rate public notes:
|
|
|
|
3.5% due 2024
|
$
|
299
|
|
|
$
|
298
|
|
4.3% due 2027
|
994
|
|
|
992
|
|
7.9% due 2029
|
464
|
|
|
463
|
|
7.3% due 2031
|
628
|
|
|
628
|
|
7.1% due 2033
|
537
|
|
|
537
|
|
6.0% due 2040
|
741
|
|
|
741
|
|
5.6% due 2041
|
1,236
|
|
|
1,235
|
|
5.8% due 2047
|
494
|
|
|
494
|
|
Total fixed-rate public notes
|
5,393
|
|
|
5,388
|
|
Term loan due March 2023
|
988
|
|
|
—
|
|
Fair value adjustments - interest rate hedging
|
5
|
|
|
1
|
|
Total Debt - Hess Corporation
|
$
|
6,386
|
|
|
$
|
5,389
|
|
|
|
|
|
Debt - Midstream:
|
|
|
|
Fixed-rate notes: 5.625% due 2026 - Hess Midstream Operations LP
|
$
|
789
|
|
|
$
|
787
|
|
Fixed-rate notes: 5.125% due 2028 - Hess Midstream Operations LP
|
542
|
|
|
540
|
|
Term loan A facility - Hess Midstream Operations LP
|
395
|
|
|
394
|
|
Revolving credit facility - Hess Midstream Operations LP
|
184
|
|
|
32
|
|
Total Debt - Midstream
|
$
|
1,910
|
|
|
$
|
1,753
|
|
|
|
|
|
Total Debt:
|
|
|
|
Current maturities of long-term debt
|
$
|
10
|
|
|
$
|
—
|
|
Long-term debt
|
8,286
|
|
|
7,142
|
|
Total Debt
|
$
|
8,296
|
|
|
$
|
7,142
|
|
At December 31, 2020, the maturity profile of total debt was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
Hess
Corporation
|
|
Midstream
|
|
|
|
|
|
|
|
(In millions)
|
2021
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
10
|
|
2022
|
20
|
|
|
—
|
|
|
20
|
|
2023
|
1,030
|
|
|
1,000
|
|
|
30
|
|
2024
|
824
|
|
|
300
|
|
|
524
|
|
2025
|
—
|
|
|
—
|
|
|
—
|
|
Thereafter
|
6,488
|
|
|
5,138
|
|
|
1,350
|
|
Total Borrowings
|
8,372
|
|
|
6,438
|
|
|
1,934
|
|
Less: Deferred financing costs and discounts
|
(76)
|
|
|
(52)
|
|
|
(24)
|
|
Total Debt (excluding interest)
|
$
|
8,296
|
|
|
$
|
6,386
|
|
|
$
|
1,910
|
|
No interest was capitalized in 2020 (2019: $38 million; 2018: $20 million).
Debt – Hess Corporation:
Senior unsecured fixed-rate public notes:
At December 31, 2020, Hess Corporation’s fixed-rate public notes had a gross principal amount of $5,438 million (2019: $5,438 million) and a weighted average interest rate of 5.9% (2019: 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, 2020, Hess Corporation was in compliance with this financial covenant.
Term loan and 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 applicable margin of 2.25% until the term loan's first anniversary. The
applicable margin varies based on the credit rating of the Corporation’s senior unsecured long-term debt and will increase by 0.25% on each anniversary of the term loan.
In 2019, we entered into a new $3.5 billion revolving credit facility with a maturity date of May 15, 2023, which replaced the Corporation’s previous revolving credit facility. The new facility can be used for borrowings and letters of credit. Borrowings will generally bear interest at 1.30% above LIBOR, though the interest rate is subject to adjustment if the Corporation’s credit rating changes. At December 31, 2020, Hess Corporation had no outstanding borrowings or letters of credit under this facility.
Both the term loan and revolving credit facility 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, 2020, Hess Corporation was in compliance with these financial covenants.
The most restrictive of the financial covenants related to our fixed-rate public notes and our term loan and revolving credit facility would allow us to borrow up to an additional $1,730 million of secured debt at December 31, 2020.
Other outstanding letters of credit at December 31 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
|
|
|
|
(In millions)
|
Committed lines (a)
|
$
|
54
|
|
|
$
|
54
|
|
Uncommitted lines (a)
|
215
|
|
|
218
|
|
Total
|
$
|
269
|
|
|
$
|
272
|
|
(a)At December 31, 2020, committed and uncommitted lines have expiration dates through 2021.
Debt - Midstream:
Senior unsecured fixed-rate public notes:
In November 2017, HIP issued $800 million of 5.625% senior unsecured notes due in 2026. In December 2019, in connection with the acquisition of HIP and corporate restructuring described in Note 4, Hess Midstream LP, HESM Opco assumed $800 million of outstanding HIP senior notes in a par-for-par exchange. The senior notes are guaranteed by certain subsidiaries of HESM Opco. In addition, in December 2019, HESM Opco issued $550 million of 5.125% senior unsecured notes due in 2028. The notes are guaranteed by HESM Opco’s direct and indirect wholly owned material domestic subsidiaries. Proceeds of the new notes were used to finance the acquisition of HIP and repay outstanding borrowings under HIP’s credit facilities.
Credit facilities:
Prior to the closing of the December 2019 transaction, HIP had a $600 million 5-year senior secured revolving credit facility and a $200 million senior secured Term Loan A facility, while Hess Midstream Partners LP had a $300 million 4-year senior secured syndicated revolving credit facility. In connection with the acquisition of HIP, both HIP and Hess Midstream Partners LP retired their existing senior secured revolving credit facilities and HESM Opco entered into a new 5-year senior secured syndicated revolving credit facility in the amount of $1.0 billion. HIP also retired its senior secured Term Loan A facility, which had borrowings of $190 million excluding deferred issuance costs, and HESM Opco entered into a fully drawn $400 million 5-year Term Loan A facility, receiving cash of $210 million at closing. The new revolving credit facility can be used for borrowings and letters of credit to fund HESM Opco’s operating activities, capital expenditures, distributions and for other general corporate purposes. Borrowings under the 5-year Term Loan A facility will generally bear interest at LIBOR plus an applicable margin ranging from 1.55% to 2.50%, while the applicable margin for the 5-year syndicated revolving credit facility ranges from 1.275% to 2.000%. Pricing levels for the facility fee and interest-rate margins are based on HESM Opco’s ratio of total debt to EBITDA as defined in the credit facilities. If HESM Opco obtains an investment grade credit rating, the pricing levels will be based on HESM Opco’s credit ratings in effect from time to time. The credit facilities contain covenants that require HESM Opco to maintain a ratio of total debt to EBITDA 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 the presently owned and after-acquired assets of HESM Opco and its direct and indirect wholly owned material domestic subsidiaries, including equity interests directly owned by such entities, subject to certain customary exclusions. At December 31, 2020, borrowings of $184 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 to Hess Corporation.
8. Asset Retirement Obligations
The following table describes changes to our asset retirement obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
|
|
|
|
(In millions)
|
Balance at January 1
|
$
|
1,024
|
|
|
$
|
857
|
|
Liabilities incurred
|
36
|
|
|
72
|
|
Liabilities settled or disposed of
|
(161)
|
|
|
(75)
|
|
Accretion expense
|
46
|
|
|
40
|
|
Revisions of estimated liabilities
|
52
|
|
|
129
|
|
Foreign currency remeasurement
|
2
|
|
|
1
|
|
Balance at December 31
|
$
|
999
|
|
|
$
|
1,024
|
|
|
|
|
|
Total Asset Retirement Obligations at December 31:
|
|
|
|
Current portion of asset retirement obligations
|
$
|
105
|
|
|
$
|
127
|
|
Long-term asset retirement obligations
|
894
|
|
|
897
|
|
Total at December 31
|
$
|
999
|
|
|
$
|
1,024
|
|
The liabilities incurred in 2020 and 2019 primarily relate to operations in Guyana, the U.S. and Malaysia. The liabilities settled or disposed of in 2020 primarily reflect 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, while 2019 primarily relates to abandonment activity in the Gulf of Mexico and the Bakken. Revisions of estimated liabilities in 2020 and 2019 reflect an acceleration of planned abandonment activity in the Gulf of Mexico and changes in service and equipment rates.
Sinking fund deposits that are legally restricted for purposes of settling asset retirement obligations, which are reported in non-current Other assets in the Consolidated Balance Sheet, were $207 million at December 31, 2020 (2019: $178 million).
9. Retirement Plans
We have funded noncontributory defined benefit pension plans for a significant portion of our employees. In addition, we have an unfunded supplemental pension plan covering certain employees, which provides incremental payments that would have been payable from our principal pension plans, were it not for limitations imposed by income tax regulations. The plans provide defined benefits based on years of service and final average salary to U.S. employees hired prior to January 1, 2017 and to U.K. employees. U.S. employees hired on or after January 1, 2017 participate under a cash accumulation formula and receive credits to a notional account based on a percentage of pensionable wages. Interest accrues on the balance in the notional account at a rate determined in accordance with plan provisions. Additionally, we maintain an unfunded postretirement medical plan that provides health benefits to certain U.S. qualified retirees from ages 55 through 65. The measurement date for all retirement plans is December 31.
The following table summarizes the benefit obligations, the fair value of plan assets, and the funded status of our pension and postretirement medical plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded
Pension Plans
|
|
Unfunded
Pension Plan
|
|
Postretirement
Medical Plan
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Change in Benefit Obligation
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1,
|
$
|
2,667
|
|
|
$
|
2,492
|
|
|
$
|
242
|
|
|
$
|
216
|
|
|
$
|
75
|
|
|
$
|
59
|
|
Service cost
|
37
|
|
|
33
|
|
|
13
|
|
|
11
|
|
|
3
|
|
|
2
|
|
Interest cost
|
68
|
|
|
82
|
|
|
5
|
|
|
7
|
|
|
1
|
|
|
2
|
|
Actuarial (gains) loss (a)
|
385
|
|
|
401
|
|
|
26
|
|
|
22
|
|
|
(8)
|
|
|
19
|
|
Single premium annuity contract payment
|
—
|
|
|
(249)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Benefit payments (b)
|
(93)
|
|
|
(113)
|
|
|
(17)
|
|
|
(14)
|
|
|
(6)
|
|
|
(7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency exchange rate changes
|
21
|
|
|
21
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Balance at December 31, (c)
|
3,085
|
|
|
2,667
|
|
|
269
|
|
|
242
|
|
|
65
|
|
|
75
|
|
Change in Fair Value of Plan Assets
|
|
|
|
|
|
|
|
|
|
|
|
Balance at January 1,
|
$
|
2,732
|
|
|
$
|
2,568
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
378
|
|
|
462
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Employer contributions
|
4
|
|
|
40
|
|
|
17
|
|
|
14
|
|
|
6
|
|
|
7
|
|
Single premium annuity contract payment
|
—
|
|
|
(249)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Benefit payments (b)
|
(93)
|
|
|
(113)
|
|
|
(17)
|
|
|
(14)
|
|
|
(6)
|
|
|
(7)
|
|
Foreign currency exchange rate changes
|
22
|
|
|
24
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Balance at December 31,
|
3,043
|
|
|
2,732
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded Status (Plan assets greater (less) than benefit obligations) at December 31,
|
$
|
(42)
|
|
|
$
|
65
|
|
|
$
|
(269)
|
|
|
$
|
(242)
|
|
|
$
|
(65)
|
|
|
$
|
(75)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized Net Actuarial (Gains) Losses
|
$
|
900
|
|
|
$
|
756
|
|
|
$
|
86
|
|
|
$
|
65
|
|
|
$
|
(19)
|
|
|
$
|
(12)
|
|
(a)Changes in discount rates resulted in actuarial losses of $387 million in 2020 (2019: $465 million). Changes in mortality assumptions resulted in actuarial gains of $18 million in 2020 (2019: $13 million).
(b)Benefit payments include lump-sum settlement payments of $23 million in 2020 (2019: $27 million).
(c)At December 31, 2020, the accumulated benefit obligation for the funded and unfunded defined benefit pension plans was $2,993 million and $228 million, respectively (2019: $2,580 million and $194 million, respectively).
Amounts recognized in the Consolidated Balance Sheet at December 31 consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded
Pension Plans
|
|
Unfunded
Pension Plan
|
|
Postretirement
Medical Plan
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Noncurrent assets
|
$
|
45
|
|
|
$
|
71
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Current liabilities
|
—
|
|
|
—
|
|
|
(49)
|
|
|
(32)
|
|
|
(7)
|
|
|
(8)
|
|
Noncurrent liabilities
|
(87)
|
|
|
(6)
|
|
|
(220)
|
|
|
(210)
|
|
|
(58)
|
|
|
(67)
|
|
Pension assets / (accrued benefit liability)
|
$
|
(42)
|
|
|
$
|
65
|
|
|
$
|
(269)
|
|
|
$
|
(242)
|
|
|
$
|
(65)
|
|
|
$
|
(75)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive loss, pre-tax (a)
|
$
|
900
|
|
|
$
|
756
|
|
|
$
|
86
|
|
|
$
|
65
|
|
|
$
|
(19)
|
|
|
$
|
(12)
|
|
(a)The after‑tax deficit reflected in Accumulated other comprehensive income (loss) was $759 million at December 31, 2020 (2019: $601 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
|
|
2020
|
|
2019
|
|
2018
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Service cost
|
$
|
50
|
|
|
$
|
44
|
|
|
$
|
42
|
|
|
$
|
3
|
|
|
$
|
2
|
|
|
$
|
2
|
|
Interest cost
|
73
|
|
|
89
|
|
|
91
|
|
|
1
|
|
|
2
|
|
|
3
|
|
Expected return on plan assets
|
(180)
|
|
|
(180)
|
|
|
(194)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of unrecognized net actuarial losses (gains)
|
48
|
|
|
52
|
|
|
39
|
|
|
(1)
|
|
|
(1)
|
|
|
(2)
|
|
Settlement loss
|
—
|
|
|
93
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Curtailment gain
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Periodic Benefit Cost / (Income) (a)
|
$
|
(9)
|
|
|
$
|
98
|
|
|
$
|
(18)
|
|
|
$
|
3
|
|
|
$
|
3
|
|
|
$
|
1
|
|
(a)Net non-service cost, which are included in Other, net in the Statement of Consolidated Income, were income of $59 million in 2020 (2019: $55 million of expense; 2018: $61 million of income).
In 2019, the trust for the Hess Corporation Employees’ Pension Plan (the “Plan”) purchased a single premium annuity contract at a cost of $249 million using assets of the Plan to settle and transfer certain of its obligations to a third party. The settlement transaction resulted in a noncash charge of $88 million to recognize unamortized pension actuarial losses that is included in Other, net in the Statement of Consolidated Income.
In 2021, we forecast service cost for our pension and postretirement medical plans to be approximately $55 million and net non-service cost of approximately $85 million of income, which is comprised of interest cost of approximately $55 million, amortization of unrecognized net actuarial losses of approximately $55 million, and estimated expected return on plan assets of approximately $195 million.
Assumptions: The weighted average actuarial assumptions used to determine benefit obligations at December 31 and net periodic benefit cost for the three years ended December 31 for our funded and unfunded pension plans were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
Benefit Obligations:
|
|
|
|
|
|
|
Discount rate
|
|
2.2%
|
|
2.9%
|
|
3.9%
|
Rate of compensation increase
|
|
3.8%
|
|
3.8%
|
|
3.8%
|
|
|
|
|
|
|
|
Net Periodic Benefit Cost:
|
|
|
|
|
|
|
Discount rate
|
|
|
|
|
|
|
Service cost
|
|
3.2%
|
|
3.9%
|
|
3.9%
|
Interest cost
|
|
2.6%
|
|
3.4%
|
|
3.3%
|
Expected return on plan assets
|
|
6.7%
|
|
7.1%
|
|
7.2%
|
Rate of compensation increase
|
|
3.8%
|
|
3.8%
|
|
4.5%
|
The actuarial assumptions used to determine benefit obligations at December 31 for the postretirement medical plan were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
Discount rate
|
|
1.9%
|
|
2.8%
|
|
3.9%
|
Initial health care trend rate
|
|
6.0%
|
|
6.5%
|
|
6.9%
|
Ultimate trend rate
|
|
4.5%
|
|
4.5%
|
|
4.5%
|
Year in which ultimate trend rate is reached
|
|
2038
|
|
2038
|
|
2038
|
The assumptions used to determine net periodic benefit cost for each year were established at the end of each previous year while the assumptions used to determine benefit obligations were established at each year‑end. The net periodic benefit cost and the actuarial present value of benefit obligations are based on actuarial assumptions that are reviewed on an annual basis. The discount rate is developed based on a portfolio of high‑quality, fixed income debt instruments with maturities that approximate the expected payment of plan obligations.
The overall expected return on plan assets is developed from the expected future returns for each asset category, weighted by the target allocation of pension assets to that asset category. The future expected return assumptions for individual asset categories are largely based on inputs from various investment experts regarding their future return expectations for particular asset categories.
Our investment strategy is to maximize long‑term returns at an acceptable level of risk through broad diversification of plan assets in a variety of asset classes. Asset classes and target allocations are determined by our investment committee and include domestic and foreign equities, fixed income, and other investments, including hedge funds, real estate and private equity. Investment managers are prohibited from investing in securities issued by us unless indirectly held as part of an index strategy. The majority of plan assets
are highly liquid, providing ample liquidity for benefit payment requirements. The current target allocations for plan assets are 45% equity securities, 35% fixed income securities (including cash and short‑term investment funds) and 20% to all other types of investments. Asset allocations are rebalanced on a periodic basis throughout the year to bring assets to within an acceptable range of target levels.
Fair value: The following tables provide the fair value of the financial assets of the funded pension plans at December 31, 2020 and 2019 in accordance with the fair value measurement hierarchy described in Note 1, Nature of Operations, Basis of Presentation and Summary of Accounting Policies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Net Asset
Value (c)
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
December 31, 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
|
|
December 31, 2019
|
|
|
|
|
|
|
|
|
|
Cash and Short-Term Investment Funds
|
$
|
57
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
57
|
|
Equities:
|
|
|
|
|
|
|
|
|
|
U.S. equities (domestic)
|
638
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
638
|
|
International equities (non-U.S.)
|
80
|
|
|
37
|
|
|
—
|
|
|
302
|
|
|
419
|
|
Global equities (domestic and non-U.S.)
|
—
|
|
|
8
|
|
|
—
|
|
|
196
|
|
|
204
|
|
Fixed Income:
|
|
|
|
|
|
|
|
|
|
Treasury and government related (a)
|
—
|
|
|
372
|
|
|
—
|
|
|
56
|
|
|
428
|
|
Mortgage-backed securities (b)
|
—
|
|
|
141
|
|
|
—
|
|
|
30
|
|
|
171
|
|
Corporate
|
—
|
|
|
293
|
|
|
—
|
|
|
82
|
|
|
375
|
|
Other:
|
|
|
|
|
|
|
|
|
|
Hedge funds
|
—
|
|
|
—
|
|
|
—
|
|
|
65
|
|
|
65
|
|
Private equity funds
|
—
|
|
|
—
|
|
|
—
|
|
|
191
|
|
|
191
|
|
Real estate funds
|
27
|
|
|
—
|
|
|
—
|
|
|
157
|
|
|
184
|
|
Total investments
|
$
|
802
|
|
|
$
|
851
|
|
|
$
|
—
|
|
|
$
|
1,079
|
|
|
$
|
2,732
|
|
(a)Includes securities issued and guaranteed by U.S. and non‑U.S. governments, and securities issued by governmental agencies and municipalities.
(b)Comprised of U.S. residential and commercial mortgage-backed securities.
(c)Includes certain investments that have been valued using the net asset value (NAV) practical expedient, and therefore have not been categorized in the fair value hierarchy. The inclusion of such amounts in the above table is intended to aid reconciliation of investments categorized in the fair value hierarchy to total pension plan assets.
The following describes the financial assets of the funded pension plans:
Cash and short‑term investment funds - Consists of cash on hand and short-term investment funds that provide for daily investments and redemptions which are classified as Level 1.
Equities - Consists of individually held U.S. and international equity securities. This investment category also includes funds that consist primarily of U.S. and international equity securities. Equity securities, which are individually held and are traded actively on exchanges, are classified as Level 1. Certain funds, consisting primarily of equity securities, are classified as Level 2 if the NAV is determined and published daily, and is the basis for current transactions. Commingled funds, consisting primarily of equity securities, are valued using the NAV per fund share.
Fixed income investments - Consists of individually held securities issued by the U.S. government, non-U.S. governments, governmental agencies, municipalities and corporations, and agency and non-agency mortgage backed securities. This investment category also includes funds that consist of fixed income securities. Individual fixed income securities are generally priced based on
evaluated prices from independent pricing services, which are monitored and provided by the third-party custodial firm responsible for safekeeping assets of the particular plan and are classified as Level 2. Certain funds, consisting primarily of fixed income securities, are classified as Level 2 if the NAV is determined and published daily, and is the basis for current transactions. Commingled funds, consisting primarily of fixed income securities, are valued using the NAV per fund share.
Other investments - Consists of exchange‑traded real estate investment trust securities, which are classified as Level 1. Commingled funds and limited partnership investments in hedge funds, private equity and real estate funds are valued at the NAV per fund share.
Contributions and estimated future benefit payments: To preserve cash in 2021, we are minimizing non-required cash contributions to funded pension plans. In 2021, we expect to contribute approximately $4 million to our funded pension plans.
Estimated future benefit payments by the funded and unfunded pension plans, and the postretirement medical plan, which reflect expected future service, are as follows (in millions):
|
|
|
|
|
|
|
|
|
2021
|
|
$
|
151
|
|
2022
|
|
134
|
|
2023
|
|
133
|
|
2024
|
|
137
|
|
2025
|
|
130
|
|
Years 2026 to 2030
|
|
687
|
|
We also have defined contribution plans for certain eligible employees. Employees may contribute a portion of their compensation to these plans and we match a portion of the employee contributions. We recorded expense of $22 million in 2020 for contributions to these plans (2019: $20 million; 2018: $19 million).
10. Revenue
Revenue from contracts with customers on a disaggregated basis was as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and Production
|
|
Midstream
|
|
Eliminations
|
|
Total
|
|
United States
|
|
Guyana
|
|
Malaysia and JDA
|
|
Other (a)
|
|
E&P Total
|
|
|
|
|
|
|
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
|
|
2018
|
|
Sales of our net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil revenue
|
$
|
2,832
|
|
|
$
|
—
|
|
|
$
|
104
|
|
|
$
|
587
|
|
|
$
|
3,523
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,523
|
|
Natural gas liquids revenue
|
308
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
308
|
|
|
—
|
|
|
—
|
|
|
308
|
|
Natural gas revenue
|
176
|
|
|
—
|
|
|
651
|
|
|
32
|
|
|
859
|
|
|
—
|
|
|
—
|
|
|
859
|
|
Sales of purchased oil and gas
|
1,661
|
|
|
—
|
|
|
14
|
|
|
93
|
|
|
1,768
|
|
|
—
|
|
|
—
|
|
|
1,768
|
|
Intercompany revenue
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
713
|
|
|
(713)
|
|
|
—
|
|
Total revenues from contracts with customers
|
4,977
|
|
|
—
|
|
|
769
|
|
|
712
|
|
|
6,458
|
|
|
713
|
|
|
(713)
|
|
|
6,458
|
|
Other operating revenues (b)
|
(135)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(135)
|
|
|
—
|
|
|
—
|
|
|
(135)
|
|
Total sales and other operating revenues
|
$
|
4,842
|
|
|
$
|
—
|
|
|
$
|
769
|
|
|
$
|
712
|
|
|
$
|
6,323
|
|
|
$
|
713
|
|
|
$
|
(713)
|
|
|
$
|
6,323
|
|
(a)Other includes our interests in Denmark and Libya.
(b)Includes gains (losses) on commodity derivatives of $547 million in 2020, $1 million in 2019, and $(183) million in 2018.
11. Dispositions
2020: We completed the sale of our 28% working interest in the Shenzi Field in the deepwater Gulf of Mexico for proceeds of $482 million, after normal closing adjustments, and recognized a pre-tax gain of $79 million ($79 million after income taxes).
2019: We completed the sale of our remaining acreage in the Utica shale play in eastern Ohio for proceeds of $22 million, after normal closing adjustments, and recognized a pre-tax gain of $22 million ($22 million after income taxes).
2018: We completed the sale of our joint venture interests in the Utica shale play in eastern Ohio 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).
12. Impairment
Oil and Gas Properties:
As a result of the significant decline in crude oil prices due to the global economic slowdown from the COVID-19 pandemic, 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. Exit and Disposal Costs
We incurred employee termination costs of $27 million in 2020 and $38 million in 2018 related to cost reduction initiatives and asset sales in 2018. 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 $20 million in 2020 (2019: $4 million; 2018: $40 million).
14. Share-based Compensation
We have established and maintain long term incentive plans (LTIP) for the granting of restricted common shares, performance share units (PSUs) and stock options to our employees. At December 31, 2020, the total number of authorized common stock under the LTIP was 51.5 million shares, of which we have 13.0 million shares available for issuance. Share‑based compensation expense consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
Restricted stock
|
$
|
51
|
|
|
$
|
53
|
|
|
$
|
40
|
|
Performance share units
|
18
|
|
|
22
|
|
|
22
|
|
Stock options
|
10
|
|
|
10
|
|
|
10
|
|
Share-based compensation expense before income taxes
|
$
|
79
|
|
|
$
|
85
|
|
|
$
|
72
|
|
Income tax benefit on share-based compensation expense
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Based on share‑based compensation awards outstanding at December 31, 2020, unearned compensation expense, before income taxes, will be recognized in future years as follows (in millions): 2021: $49, 2022: $26 and 2023: $4.
Our share-based compensation plans can be summarized as follows:
Restricted stock:
Restricted stock generally vests equally on an annual basis over a three-year term and is valued based on the prevailing market price of our common stock on the date of grant. The following is a summary of restricted stock award activity in 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares of Restricted Common Stock
|
|
Weighted - Average Price on Date of Grant
|
|
|
|
|
|
(In thousands, except per share amounts)
|
Outstanding at January 1, 2020
|
2,014
|
|
|
$
|
53.61
|
|
Granted
|
1,122
|
|
|
49.71
|
|
Vested (a)
|
(1,028)
|
|
|
52.67
|
|
Forfeited
|
(191)
|
|
|
52.54
|
|
Outstanding at December 31, 2020
|
1,917
|
|
|
$
|
51.94
|
|
(a)In 2020, restricted stock with fair values of $51 million were vested (2019: $102 million; 2018: $54 million).
Performance share units:
PSUs generally vest three years from the date of grant and are valued using a Monte Carlo simulation on the date of grant. The number of shares of common stock to be issued under a PSU agreement is based on a comparison of the Corporation’s total shareholder return (TSR) to the TSR of a predetermined group of peer companies over a three-year performance period ending December 31 of the year prior to settlement of the grant. Beginning with the PSUs granted in 2020, the Corporation's TSR is compared to the TSR of a predetermined group of peer companies and the S&P 500 index over the three-year performance period. Payouts of the performance share awards will range from 0% to 200% of the target awards based on the Corporation’s TSR ranking within the peer group. Dividend equivalents for the performance period will accrue on performance shares but will only be paid out on earned shares after the performance period. The following is a summary of PSU activity in 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Share Units
|
|
Weighted - Average Fair Value on Date of Grant
|
|
|
|
|
|
(In thousands, except per share amounts)
|
Outstanding at January 1, 2020
|
929
|
|
|
$
|
59.57
|
|
Granted
|
308
|
|
|
58.14
|
|
Vested (a)
|
(416)
|
|
|
52.86
|
|
Forfeited
|
(15)
|
|
|
66.63
|
|
Outstanding at December 31, 2020
|
806
|
|
|
$
|
62.36
|
|
(a)In 2020, PSU’s with fair value of $48 million were vested (2019: $16 million; 2018: $9 million).
The following weighted average assumptions were utilized to estimate the fair value of PSU awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
Risk free interest rate
|
0.52
|
%
|
|
2.48
|
%
|
|
2.39
|
%
|
Stock price volatility
|
0.374
|
|
0.369
|
|
0.400
|
Contractual term in years
|
3.0
|
|
3.0
|
|
3.0
|
Grant date price of Hess common stock
|
$
|
49.72
|
|
|
$
|
56.74
|
|
|
$
|
48.48
|
|
Stock options:
Stock options vest over three years from the date of grant, have a 10‑year term, and the exercise price equals the market price of our common stock on the date of grant. The following is a summary of stock options activity in 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of options
(In thousands)
|
|
Weighted Average Exercise Price per Share
|
|
Weighted Average Remaining Contractual Term
|
Outstanding at January 1, 2020
|
4,301
|
|
|
$
|
63.24
|
|
|
4.8 years
|
Granted
|
686
|
|
|
49.72
|
|
|
|
Exercised
|
(261)
|
|
|
59.88
|
|
|
|
Cancelled
|
(301)
|
|
|
61.13
|
|
|
|
Forfeited
|
(43)
|
|
|
52.70
|
|
|
|
Outstanding at December 31, 2020
|
4,382
|
|
|
$
|
61.57
|
|
|
5.1 years
|
At December 31, 2020, there were 4.4 million outstanding stock options (3.2 million exercisable) with a weighted average remaining contractual life of 5.1 years (3.8 years for exercisable options) and an aggregated intrinsic value of $9.3 million ($6.3 million for exercisable options).
The following weighted average assumptions were utilized to estimate the fair value of stock options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
Risk free interest rate
|
0.64
|
%
|
|
2.55
|
%
|
|
2.74
|
%
|
Stock price volatility
|
0.372
|
|
0.359
|
|
0.322
|
Dividend yield
|
2.01
|
%
|
|
1.76
|
%
|
|
2.06
|
%
|
Expected life in years
|
6.0
|
|
6.0
|
|
6.0
|
Weighted average fair value per option granted
|
$
|
14.30
|
|
|
$
|
18.08
|
|
|
$
|
13.69
|
|
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.
15. Income Taxes
The provision (benefit) for income taxes consisted of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
United States
|
|
|
|
|
|
Federal
|
|
|
|
|
|
Current
|
$
|
(4)
|
|
|
$
|
(1)
|
|
|
$
|
1
|
|
Deferred taxes and other accruals
|
6
|
|
|
72
|
|
|
(74)
|
|
State
|
(1)
|
|
|
16
|
|
|
(45)
|
|
|
1
|
|
|
87
|
|
|
(118)
|
|
Foreign
|
|
|
|
|
|
Current (a)
|
48
|
|
|
447
|
|
|
455
|
|
Deferred taxes and other accruals
|
(60)
|
|
|
(73)
|
|
|
(2)
|
|
|
(12)
|
|
|
374
|
|
|
453
|
|
Provision (Benefit) For Income Taxes
|
$
|
(11)
|
|
|
$
|
461
|
|
|
$
|
335
|
|
(a)Primarily comprised of Libya in 2019 and 2018.
Income (loss) before income taxes consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
United States (a)
|
$
|
(1,509)
|
|
|
$
|
(338)
|
|
|
$
|
(219)
|
|
Foreign
|
(1,341)
|
|
|
559
|
|
|
439
|
|
Income (Loss) Before Income Taxes
|
$
|
(2,850)
|
|
|
$
|
221
|
|
|
$
|
220
|
|
(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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
U.S. statutory rate
|
21.0
|
%
|
|
21.0
|
%
|
|
21.0
|
%
|
Effect of foreign operations (a)
|
12.1
|
|
|
142.9
|
|
|
141.2
|
|
State income taxes, net of federal income tax
|
0.1
|
|
|
5.8
|
|
|
(18.9)
|
|
Valuation allowance on current year operations
|
(36.5)
|
|
|
41.8
|
|
|
55.2
|
|
Release valuation allowance against previously unbenefited deferred tax assets
|
—
|
|
|
(24.5)
|
|
|
—
|
|
Noncontrolling interests in Midstream
|
1.7
|
|
|
(16.0)
|
|
|
(15.9)
|
|
Intraperiod allocation
|
—
|
|
|
33.7
|
|
|
(37.3)
|
|
Credits
|
2.0
|
|
|
—
|
|
|
—
|
|
Equity and executive compensation
|
(0.1)
|
|
|
2.2
|
|
|
7.4
|
|
Other
|
0.1
|
|
|
1.2
|
|
|
(0.3)
|
|
Total
|
0.4
|
%
|
|
208.1
|
%
|
|
152.4
|
%
|
(a)The variance in effective income tax rates attributable to the effect of foreign operations primarily resulted from the mix of income among high, primarily Libya, and low tax rate jurisdictions.
The components of deferred tax liabilities and deferred tax assets at December 31, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
|
|
|
|
(In millions)
|
Deferred Tax Liabilities
|
|
|
|
Property, plant and equipment and investments
|
$
|
(847)
|
|
|
$
|
(1,318)
|
|
Other
|
(45)
|
|
|
(45)
|
|
Total Deferred Tax Liabilities
|
(892)
|
|
|
(1,363)
|
|
Deferred Tax Assets
|
|
|
|
Net operating loss carryforwards
|
5,037
|
|
|
4,733
|
|
Tax credit carryforwards
|
135
|
|
|
66
|
|
Property, plant and equipment and investments
|
55
|
|
|
206
|
|
Accrued compensation, deferred credits and other liabilities
|
196
|
|
|
179
|
|
Asset retirement obligations
|
252
|
|
|
261
|
|
Other
|
325
|
|
|
317
|
|
Total Deferred Tax Assets
|
6,000
|
|
|
5,762
|
|
Valuation allowances (a)
|
(5,391)
|
|
|
(4,734)
|
|
Total deferred tax assets, net of valuation allowances
|
609
|
|
|
1,028
|
|
Net Deferred Tax Assets (Liabilities)
|
$
|
(283)
|
|
|
$
|
(335)
|
|
(a)In 2020, the valuation allowance increased by $657 million (2019: decrease of $143 million; 2018: decrease of $322 million).
In the Consolidated Balance Sheet, deferred tax assets and liabilities are netted by taxing jurisdiction and are recorded at December 31, as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
|
|
|
|
(In millions)
|
Deferred income taxes (long-term asset)
|
$
|
59
|
|
|
$
|
80
|
|
Deferred income taxes (long-term liability)
|
(342)
|
|
|
(415)
|
|
Net Deferred Tax Assets (Liabilities)
|
$
|
(283)
|
|
|
$
|
(335)
|
|
At December 31, 2020, we have recognized a gross deferred tax asset related to net operating loss carryforwards of $5,037 million before application of valuation allowances. The deferred tax asset is comprised of $1,121 million attributable to foreign net operating losses which begin to expire in 2025, $3,277 million attributable to U.S. federal operating losses which begin to expire in 2034, and $639 million attributable to losses in various U.S. states which begin to expire in 2021. The deferred tax asset attributable to foreign net operating losses, net of valuation allowances, is $155 million. A full valuation allowance is established against the deferred tax asset attributable to U.S. federal and state net operating losses, except for $3 million U.S. federal and $1 million U.S. state deferred tax asset attributable to Midstream activities. At December 31, 2020, we have U.S. federal, state and foreign alternative minimum tax credit carryforwards of $49 million, which can be carried forward indefinitely, and approximately $83 million of other business credit carryforwards. The deferred tax asset attributable to these credits, net of valuation allowances was not significant. A full valuation allowance is established against our foreign tax credit carryforwards of $3 million, which begin to expire in 2021.
At December 31, 2020, the Consolidated Balance Sheet reflects a $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, and Malaysia. 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, 2020 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. At December 31, 2019 the valuation allowance established against the net deferred tax asset in Guyana for the Stabroek Block was released as a result of the positive evidence from first production in December 2019, and the significant forecasted pre-tax income from operations. The cumulative pre-tax losses in Guyana were driven by pre-production activities.
Below is a reconciliation of the gross beginning and ending amounts of unrecognized tax benefits:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
Balance at January 1
|
$
|
168
|
|
|
$
|
168
|
|
|
$
|
205
|
|
Additions based on tax positions taken in the current year
|
2
|
|
|
2
|
|
|
19
|
|
Additions based on tax positions of prior years
|
1
|
|
|
1
|
|
|
36
|
|
Reductions based on tax positions of prior years
|
(2)
|
|
|
(1)
|
|
|
(78)
|
|
Reductions due to settlements with taxing authorities
|
(1)
|
|
|
—
|
|
|
(10)
|
|
Reductions due to lapses in statutes of limitation
|
(2)
|
|
|
(2)
|
|
|
(4)
|
|
Balance at December 31
|
$
|
166
|
|
|
$
|
168
|
|
|
$
|
168
|
|
The December 31, 2020 balance of unrecognized tax benefits includes $16 million that, if recognized, would impact our effective income tax rate. Over the next 12 months, it is reasonably possible that the total amount of unrecognized tax benefits could decrease between zero and $41 million due to settlements with taxing authorities or other resolutions, as well as lapses in statutes of limitation. At December 31, 2020, our accrued interest and penalties related to unrecognized tax benefits is $6 million (2019: $7 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 2010.
16. Outstanding and Weighted Average Common Shares
The Net income (loss) and weighted average number of common shares used in basic and diluted earnings per share computation were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions except per share amounts)
|
Net Income (Loss) Attributable to Hess Corporation Common Stockholders:
|
|
|
|
|
|
Net income (loss)
|
$
|
(2,839)
|
|
|
$
|
(240)
|
|
|
$
|
(115)
|
|
Less: Net income (loss) attributable to noncontrolling interests
|
254
|
|
|
168
|
|
|
167
|
|
Less: Preferred stock dividends
|
—
|
|
|
4
|
|
|
46
|
|
Net income (loss) attributable to Hess Corporation Common Stockholders
|
$
|
(3,093)
|
|
|
$
|
(412)
|
|
|
$
|
(328)
|
|
|
|
|
|
|
|
Weighted Average Number of Common Shares Outstanding:
|
|
Basic
|
304.8
|
|
|
301.2
|
|
|
298.2
|
|
Effect of dilutive securities
|
|
|
|
|
|
Restricted common stock
|
—
|
|
|
—
|
|
|
—
|
|
Stock options
|
—
|
|
|
—
|
|
|
—
|
|
Performance share units
|
—
|
|
|
—
|
|
|
—
|
|
Mandatory convertible preferred stock
|
—
|
|
|
—
|
|
|
—
|
|
Diluted
|
304.8
|
|
|
301.2
|
|
|
298.2
|
|
|
|
|
|
|
|
Net Income (Loss) Attributable to Hess Corporation per Common Share:
|
|
|
|
|
|
Basic
|
$
|
(10.15)
|
|
|
$
|
(1.37)
|
|
|
$
|
(1.10)
|
|
Diluted
|
$
|
(10.15)
|
|
|
$
|
(1.37)
|
|
|
$
|
(1.10)
|
|
|
|
|
|
|
|
Antidilutive shares excluded from the computation of diluted shares:
|
|
Restricted common stock
|
2.1
|
|
|
2.2
|
|
|
2.9
|
|
Stock options
|
4.3
|
|
|
4.7
|
|
|
5.5
|
|
Performance share units
|
1.1
|
|
|
1.7
|
|
|
1.1
|
|
Common shares from conversion of preferred stock
|
—
|
|
|
—
|
|
|
12.7
|
|
The following table provides the changes in our outstanding common shares:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
Balance at January 1
|
304.9
|
|
|
291.4
|
|
|
315.1
|
|
Conversion of preferred stock
|
—
|
|
|
11.6
|
|
|
—
|
|
Activity related to restricted stock awards, net
|
1.0
|
|
|
0.9
|
|
|
0.8
|
|
Stock options exercised
|
0.3
|
|
|
0.7
|
|
|
0.6
|
|
PSUs vested
|
0.8
|
|
|
0.3
|
|
|
0.1
|
|
Shares repurchased
|
—
|
|
|
—
|
|
|
(25.2)
|
|
Balance at December 31
|
307.0
|
|
|
304.9
|
|
|
291.4
|
|
Preferred Stock Issuance:
In February 2016, we issued depository shares representing 575,000 shares of 8% Series A Mandatory Convertible Preferred Stock (Preferred Stock), par value $1 per share, with a liquidation preference of $1,000 per share. On January 31, 2019, the Preferred Stock automatically converted into shares of common stock and the net number of common shares issued by the Corporation was approximately 11.6 million shares.
Common Stock Repurchase Plan:
In 2018, we repurchased 25.2 million shares of our common stock for $1,380 million at an average cost per share of $54.85. At December 31, 2020, we are authorized, but not required, to purchase additional common stock up to a value of $650 million.
Common Stock Dividends:
In 2020, 2019 and 2018, cash dividends declared on common stock totaled $1.00 per share ($0.25 per quarter).
17. Supplementary Cash Flow Information
The following information supplements the Statement of Consolidated Cash Flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
(In millions)
|
Cash Flows From Operating Activities
|
|
|
|
|
|
Interest paid
|
$
|
(460)
|
|
|
$
|
(380)
|
|
|
$
|
(394)
|
|
Net income taxes (paid) refunded
|
(64)
|
|
|
(417)
|
|
|
(463)
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities
|
|
|
|
|
|
Additions to property, plant and equipment - E&P:
|
|
|
|
|
|
Capital expenditures incurred - E&P
|
$
|
(1,678)
|
|
|
$
|
(2,576)
|
|
|
$
|
(1,909)
|
|
Increase (decrease) in related liabilities
|
(218)
|
|
|
143
|
|
|
55
|
|
Additions to property, plant and equipment - E&P
|
$
|
(1,896)
|
|
|
$
|
(2,433)
|
|
|
$
|
(1,854)
|
|
|
|
|
|
|
|
Additions to property, plant and equipment - Midstream:
|
|
|
|
|
|
Capital expenditures incurred - Midstream
|
$
|
(253)
|
|
|
$
|
(416)
|
|
|
$
|
(271)
|
|
Increase (decrease) in related liabilities
|
(48)
|
|
|
20
|
|
|
28
|
|
Additions to property, plant and equipment - Midstream
|
$
|
(301)
|
|
|
$
|
(396)
|
|
|
$
|
(243)
|
|
In December 2019, as part of HESM Opco’s acquisition of HIP (see Note 4, Hess Midstream LP), HESM Opco assumed $800 million of outstanding HIP notes (see Note 7, Debt).
18. Guarantees, Contingencies and Commitments
Guarantees and Contingencies
We are subject to loss contingencies with respect to various claims, lawsuits and other proceedings. A liability is recognized in our consolidated financial statements when it is probable that a loss has been incurred and the amount can be reasonably estimated. If the risk of loss is probable, but the amount cannot be reasonably estimated or the risk of loss is only reasonably possible, a liability is not accrued; however, we disclose the nature of those contingencies. We cannot predict with certainty if, how or when existing claims, lawsuits and proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages.
We, along with many companies that have been or continue to be engaged in refining and marketing of gasoline, have been a party to lawsuits and claims related to the use of MTBE in gasoline. A series of similar lawsuits, many involving water utilities or governmental entities, were filed in jurisdictions across the U.S. against producers of MTBE and petroleum refiners who produced gasoline containing MTBE, including us. The principal allegation in all cases was that gasoline containing MTBE was a defective product and that these producers and refiners are strictly liable in proportion to their share of the gasoline market for damage to groundwater resources and are required to take remedial action to ameliorate the alleged effects on the environment of releases of MTBE. The majority of the cases asserted against us have been settled. There are three 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 federal court by the defendants.
In September 2003, we received a directive from the New Jersey Department of Environmental Protection (NJDEP) to remediate contamination in the sediments of the Lower Passaic River. The NJDEP is also seeking natural resource damages. The directive, insofar as it affects us, relates to alleged releases from a petroleum bulk storage terminal in Newark, New Jersey we previously owned. We and over 70 companies entered into an Administrative Order on Consent with the EPA to study the same contamination; this work remains ongoing. We and other parties settled a cost recovery claim by the State of New Jersey and agreed with the EPA to fund remediation of a portion of the site. On March 4, 2016, the EPA issued a Record of Decision (ROD) in respect of the lower eight miles of the Lower Passaic River, selecting a remedy that includes bank-to-bank dredging at an estimated cost of $1.38 billion. The ROD does not address the upper nine miles of the Lower Passaic River or the Newark Bay, which may require additional remedial action. In addition, the federal trustees for natural resources have begun a separate assessment of damages to natural resources in the Passaic River. Given that the EPA has not selected a remedy for the entirety of the Lower Passaic River or the Newark Bay, total
remedial costs cannot be reliably estimated at this time. Based on currently known facts and circumstances, we do not believe that this matter will result in a significant liability to us because our former terminal did not store or use contaminants which are of concern in the river sediments and could not have contributed contamination along the river’s length. Further, there are numerous other parties who we expect will bear the cost of remediation and damages.
In March 2014, we received an Administrative Order from the EPA requiring us and 26 other parties to undertake the Remedial Design for the remedy selected by the EPA for the Gowanus Canal Superfund Site in Brooklyn, New York. Our alleged liability derives from our former ownership and operation of a fuel oil terminal and connected shipbuilding and repair facility adjacent to the Canal. The remedy selected by the EPA includes dredging of surface sediments and the placement of a cap over the deeper sediments throughout the Canal and in-situ stabilization of certain contaminated sediments that will remain in place below the cap. The EPA’s original estimate was that this remedy would cost $506 million; however, the ultimate costs that will be incurred in connection with the design and implementation of the remedy remain uncertain. We have complied with the EPA’s March 2014 Administrative Order and contributed funding for the Remedial Design based on an allocation of costs among the parties determined by a third-party expert. In January 2020, we received an additional Administrative Order from the EPA requiring us and several other parties to begin Remedial Action along the uppermost portion of the Canal. We intend to comply with this Administrative Order. The remediation work began in the fourth quarter of 2020. Based on currently known facts and circumstances, we do not believe that this matter will result in a significant liability to us, and the costs will continue to be allocated amongst the parties, as they were for the Remedial Design.
From time to time, we are involved in other judicial and administrative proceedings relating to environmental matters. We periodically receive notices from the EPA that we are a “potential responsible party” under the Superfund legislation with respect to various waste disposal sites. Under this legislation, all potentially responsible parties may be jointly and severally liable. For any site for which we have received such a notice, the EPA’s claims or assertions of liability against us relating to these sites have not been fully developed, or the EPA’s claims have been settled or a settlement is under consideration, in all cases for amounts that are not material. Beginning in 2017, certain states, municipalities and private associations in California, Delaware, Maryland, Rhode Island and South Carolina separately filed lawsuits against oil, gas and coal producers, including us, for alleged damages purportedly caused by climate change. These proceedings include claims for monetary damages and injunctive relief. Beginning in 2013, various parishes in Louisiana filed suit against approximately 100 oil and gas companies, including us, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. The ultimate impact of the aforementioned 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 cannot predict with certainty if, how or when such proceedings will be resolved or what the eventual relief, if any, may be, particularly for proceedings that are in their early stages of development or where plaintiffs seek indeterminate damages. Numerous issues may need to be resolved, including through potentially lengthy discovery and determination of important factual matters before a loss or range of loss can be reasonably estimated for any proceeding.
Subject to the foregoing, in management’s opinion, based upon currently known facts and circumstances, the outcome of lawsuits, claims and proceedings, including the matters disclosed above, is not expected to have a material adverse effect on our financial condition, results of operations or cash flows. However, we could incur judgments, enter into settlements, or revise our opinion regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations in the period in which the amounts are accrued and our cash flows in the period in which the amounts are paid.
Unconditional Purchase Obligations and Commitments
The following table shows aggregate information for certain unconditional purchase obligations and commitments at December 31, 2020, which are not included elsewhere within these Consolidated Financial Statements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
Total
|
|
2021
|
|
2022 and
2023
|
|
2024 and
2025
|
|
Thereafter
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Capital expenditures
|
$
|
2,837
|
|
|
$
|
868
|
|
|
$
|
1,469
|
|
|
$
|
500
|
|
|
$
|
—
|
|
Operating expenses
|
236
|
|
|
167
|
|
|
63
|
|
|
5
|
|
|
1
|
|
Transportation and related contracts
|
2,867
|
|
|
310
|
|
|
756
|
|
|
493
|
|
|
1,308
|
|
19. Segment Information
We currently have two operating segments, E&P and Midstream. The E&P operating segment explores for, develops, produces, purchases and sells crude oil, NGL and natural gas. Production operations over the three years ended December 31, 2020 were in the United States (U.S.), Malaysia and the JDA, Denmark, Libya, and Guyana commencing December 2019. The Midstream operating segment provides fee-based services including crude oil and natural gas gathering, processing of natural gas and the fractionation of NGL, transportation of crude oil by rail car, terminaling and loading crude oil and NGL, storing and terminaling propane, and water handling services primarily in the Bakken shale play of North Dakota. All unallocated costs are reflected under Corporate, Interest and Other.
The following table presents operating segment financial data (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and Production
|
|
Midstream
|
|
Corporate, Interest and Other
|
|
Eliminations
|
|
Total
|
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
|
2,126
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,126
|
|
Provision (Benefit) for Income Taxes (a)
|
(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 (a)
|
375
|
|
|
—
|
|
|
86
|
|
|
—
|
|
|
461
|
|
Investment in Affiliates
|
114
|
|
|
108
|
|
|
—
|
|
|
—
|
|
|
222
|
|
Identifiable Assets
|
16,790
|
|
|
3,499
|
|
|
1,493
|
|
|
—
|
|
|
21,782
|
|
Capital Expenditures
|
2,576
|
|
|
416
|
|
|
—
|
|
|
—
|
|
|
2,992
|
|
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
|
|
Capital Expenditures
|
1,909
|
|
|
271
|
|
|
—
|
|
|
—
|
|
|
2,180
|
|
(a)Commencing January 1, 2019, management changed its measurement of segment earnings to reflect income taxes on a post U.S. tax consolidation and valuation allowance assessment basis. In 2018, the provision for income taxes in the Midstream segment was presented before consolidating its operations with other U.S. activities of the Corporation and prior to evaluating realizability of net U.S. deferred taxes. An offsetting impact was presented in the E&P segment. If 2018 segment results were prepared on a basis consistent with 2020 and 2019, Midstream segment net income attributable to Hess Corporation would have been $158 million and E&P net income attributable to Hess Corporation would have been $13 million.
The following table presents financial information by major geographic area:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
Guyana
|
|
Malaysia and JDA
|
|
Other
|
|
Corporate, Interest and other
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
2020
|
|
|
|
|
|
|
|
|
|
|
|
Sales and Other Operating Revenues
|
$
|
3,604
|
|
|
$
|
350
|
|
|
$
|
511
|
|
|
$
|
202
|
|
|
$
|
—
|
|
|
$
|
4,667
|
|
Property, Plant and Equipment (Net) (a)
|
10,384
|
|
|
2,114
|
|
|
1,067
|
|
|
539
|
|
|
11
|
|
|
14,115
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
|
Sales and Other Operating Revenues
|
$
|
5,043
|
|
|
$
|
—
|
|
|
$
|
762
|
|
|
$
|
690
|
|
|
$
|
—
|
|
|
$
|
6,495
|
|
Property, Plant and Equipment (Net) (a)
|
12,182
|
|
|
1,507
|
|
|
1,890
|
|
|
1,223
|
|
|
12
|
|
|
16,814
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
Sales and Other Operating Revenues
|
$
|
4,842
|
|
|
$
|
—
|
|
|
$
|
769
|
|
|
$
|
712
|
|
|
$
|
—
|
|
|
$
|
6,323
|
|
(a)Property, plant and equipment in the United States, in 2020, includes $7,273 million (2019: $9,172 million) attributable to the E&P segment and $3,111 million (2019: $3,010 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 of a portion of our crude oil or natural gas production. Swaps may also be used to fix the difference between current selling prices and forward selling prices in periods of contango for crude oil production that will be stored and sold in the future. 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, 2020, these forward contracts relate to the British Pound, Danish Krone, Canadian Dollar and Malaysian Ringgit. Interest rate swaps may be used to convert interest payments on certain long-term debt from fixed to floating rates.
The notional amounts of outstanding financial risk management derivative contracts were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
December 31, 2019
|
|
|
|
|
|
(In millions)
|
Commodity - crude oil put options (millions of barrels)
|
27.4
|
|
|
54.9
|
|
Foreign exchange forwards
|
$
|
163
|
|
|
$
|
90
|
|
Interest rate swaps
|
$
|
100
|
|
|
$
|
100
|
|
At December 31, 2020, we had WTI put options with an average monthly floor price of approximately $45 per barrel for 75,000 bopd for 2021. In the first quarter of 2021, we increased the average monthly floor price of 75,000 bopd of WTI put option contracts from approximately $45 per barrel to $50 per barrel for the remainder of 2021. We also purchased additional WTI put options with an average monthly floor price of $50 per barrel for 45,000 bopd and Brent put options with an average monthly floor price of $55 per barrel for 30,000 bopd. As a result, we now have total purchased WTI put options of 120,000 bopd with an average monthly floor price of $50 per barrel and total purchased Brent put options of 30,000 bopd with an average monthly floor price of $55 per barrel for the remainder of 2021.
The table below reflects the gross and net fair values of risk management derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets
|
|
Liabilities
|
|
|
|
|
|
(In millions)
|
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)
|
|
|
|
|
|
December 31, 2019
|
|
|
|
Derivative Contracts Designated as Hedging Instruments:
|
|
|
|
Crude oil put options
|
$
|
125
|
|
|
$
|
—
|
|
Interest rate swaps
|
1
|
|
|
—
|
|
Total derivative contracts designated as hedging instruments
|
126
|
|
|
—
|
|
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
|
126
|
|
|
(1)
|
|
Gross amount offset in the Consolidated Balance Sheet
|
—
|
|
|
—
|
|
Net Amounts Presented in the Consolidated Balance Sheet
|
$
|
126
|
|
|
$
|
(1)
|
|
In 2020, we chartered three VLCCs to load and transport a total of 6.3 million barrels of Bakken crude oil for sale in Asian markets. The first VLCC cargo of 2.1 million barrels was sold in September 2020. We have entered into agreements for the sale of the remaining 4.2 million barrels of crude oil in the first quarter of 2021. In connection with this activity, we entered into Brent swap transactions intended to fix the difference between Brent prices in the month of production and the forward Brent price for the expected month of sale. At December 31, 2020, net realized and unrealized losses from the Brent swaps of $16 million were deferred in Accumulated other comprehensive income, and the liability for unrealized losses from the Brent swaps was $54 million. In addition, total net realized gains from WTI put options associated with the VLCCs of $40 million were deferred in Accumulated other comprehensive income at December 31, 2020.
The fair value of our crude oil put options and crude oil swaps is presented within Other current assets and Accrued liabilities, respectively, in our Consolidated Balance Sheet. The fair value of our interest rate swaps is presented within Other assets in our Consolidated Balance Sheet. The fair value of our foreign exchange forwards is presented within Accrued liabilities in our Consolidated Balance Sheet. All fair values in the table above are based on Level 2 inputs.
Derivative contracts designated as hedging instruments:
Crude oil derivatives: In 2020, crude oil price hedging contracts increased Sales and other operating revenues by $547 million (2019: increase of $1 million; 2018: decrease of $161 million). At December 31, 2020, pre-tax deferred gains in Accumulated other comprehensive income (loss) related to outstanding crude oil price hedging contracts were $4 million, of which all will be reclassified into earnings during the next 12 months as the hedged crude oil sales are recognized in earnings.
Interest rate swaps designated as fair value hedges: At December 31, 2020, we had interest rate swaps with gross notional amounts of $100 million (2019: $100 million), which were designated as fair value hedges and relate to long-term debt where we have converted interest payments from fixed to floating rates. Changes in the fair value of interest rate swaps and the hedged fixed‑rate debt are recorded in Interest expense in the Statement of Consolidated Income. In 2020, the change in fair value of interest rate swaps was an increase in the asset of $4 million (2019: $3 million decrease in liability; 2018: $1 million increase in liability) with a corresponding adjustment in the carrying value of the hedged fixed‑rate debt.
Derivative contracts not designated as hedging instruments:
Foreign exchange: Total foreign exchange gains and losses were losses of $6 million in 2020 (2019: gain of $3 million; 2018: loss of $5 million) and are reported in Other, net in Revenues and non-operating income in the Statement of Consolidated Income. A
component of foreign exchange gains or losses is the result of foreign exchange derivative contracts that are not designated as hedges, which amounted to a gain of $2 million in 2020 (2019: loss of $2 million; 2018: loss of $2 million).
Crude oil collars: In 2018, noncash adjustments to de-designated crude oil price hedging contracts decreased Sales and other operating revenues by $22 million.
Credit Risk: We are exposed to credit risks that may at times be concentrated with certain counterparties, groups of counterparties or customers. Accounts receivable are generated from a diverse domestic and international customer base. At December 31, 2020, our Accounts receivable were concentrated with the following counterparty industry segments: Integrated companies — 39%, Independent E&P companies — 39%, Refining and marketing companies — 8%, National oil companies — 5%, Storage and transportation companies — 5%, and Others — 4%. We reduce risk related to certain counterparties, where applicable, by using master netting arrangements and requiring collateral, generally cash or letters of credit.
At December 31, 2020, we had outstanding letters of credit totaling $269 million (2019: $272 million).
Fair Value Measurement: At December 31, 2020, our total long-term debt, which was substantially comprised of fixed rate debt instruments, had a carrying value of $8,296 million and a fair value of $9,647 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, 2020 and December 31, 2019.
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, 2020, we produced crude oil, NGL and natural gas in the United States (U.S.), Malaysia and the JDA, Denmark, Libya, and Guyana commencing December 2019. Exploration and/or development activities were also conducted in certain of these producing areas as well as offshore Suriname and Canada.
Costs Incurred in Oil and Gas Producing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31
|
|
Total
|
|
United
States
|
|
Guyana
|
|
Malaysia and JDA
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
2020
|
|
|
|
|
|
|
|
|
|
|
Property acquisitions
|
|
|
|
|
|
|
|
|
|
|
Unproved
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Proved
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Exploration
|
|
307
|
|
|
169
|
|
|
130
|
|
|
2
|
|
|
6
|
|
Production and development capital expenditures (a)
|
|
1,567
|
|
|
804
|
|
|
630
|
|
|
106
|
|
|
27
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
Property acquisitions
|
|
|
|
|
|
|
|
|
|
|
Unproved
|
|
$
|
26
|
|
|
$
|
26
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Proved
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Exploration
|
|
455
|
|
|
174
|
|
|
239
|
|
|
4
|
|
|
38
|
|
Production and development capital expenditures (a)
|
|
2,463
|
|
|
1,735
|
|
|
585
|
|
|
114
|
|
|
29
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
Property acquisitions
|
|
|
|
|
|
|
|
|
|
|
Unproved
|
|
$
|
51
|
|
|
$
|
43
|
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Proved
|
|
43
|
|
|
43
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Exploration
|
|
442
|
|
|
111
|
|
|
131
|
|
|
32
|
|
|
168
|
|
Production and development capital expenditures (a)
|
|
1,577
|
|
|
1,239
|
|
|
244
|
|
|
92
|
|
|
2
|
|
(a)Includes an increase of $88 million for asset retirement obligations related to net accruals and revisions in 2020 (2019: $201 million increase; 2018: $44 million increase).
Capitalized Costs Relating to Oil and Gas Producing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31,
|
|
2020
|
|
2019
|
|
|
|
|
|
(In millions)
|
Unproved properties
|
$
|
164
|
|
|
$
|
168
|
|
Proved properties
|
2,930
|
|
|
3,304
|
|
Wells, equipment and related facilities
|
23,224
|
|
|
28,404
|
|
Total costs
|
26,318
|
|
|
31,876
|
|
Less: Reserve for depreciation, depletion, amortization and lease impairment
|
15,325
|
|
|
18,084
|
|
Net Capitalized Costs
|
$
|
10,993
|
|
|
$
|
13,792
|
|
Results of Operations for Oil and Gas Producing Activities
The results of operations shown below exclude non‑oil and gas producing activities, primarily gains (losses) on sales of oil and gas properties, sales of purchased crude oil, NGL and natural gas from third parties, interest expense and non-operating income. 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 19, Segment Information in the Notes to Consolidated Financial Statements. Other includes results for Denmark, Libya, Canada and Suriname.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31
|
|
Total
|
|
United
States
|
|
Guyana (a)
|
|
Malaysia and JDA
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
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
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
Sales and Other Operating Revenues
|
|
$
|
4,515
|
|
|
$
|
3,141
|
|
|
$
|
—
|
|
|
$
|
755
|
|
|
$
|
619
|
|
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses
|
|
941
|
|
|
697
|
|
|
24
|
|
|
129
|
|
|
91
|
|
Production and severance taxes
|
|
171
|
|
|
165
|
|
|
—
|
|
|
6
|
|
|
—
|
|
Midstream tariffs
|
|
648
|
|
|
648
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Exploration expenses, including dry holes and lease impairment
|
|
362
|
|
|
119
|
|
|
40
|
|
|
6
|
|
|
197
|
|
General and administrative expenses
|
|
258
|
|
|
230
|
|
|
4
|
|
|
10
|
|
|
14
|
|
Depreciation, depletion and amortization
|
|
1,748
|
|
|
1,297
|
|
|
—
|
|
|
395
|
|
|
56
|
|
Total Costs and Expenses
|
|
4,128
|
|
|
3,156
|
|
|
68
|
|
|
546
|
|
|
358
|
|
Results of Operations Before Income Taxes
|
|
387
|
|
|
(15)
|
|
|
(68)
|
|
|
209
|
|
|
261
|
|
Provision (benefit) for income taxes
|
|
337
|
|
|
(63)
|
|
|
—
|
|
|
11
|
|
|
389
|
|
Results of Operations
|
|
$
|
50
|
|
|
$
|
48
|
|
|
$
|
(68)
|
|
|
$
|
198
|
|
|
$
|
(128)
|
|
(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.
Proved Oil and Gas Reserves
Our proved oil and gas reserves are calculated in accordance with the Securities and Exchange Commission (SEC) regulations and the requirements of the Financial Accounting Standards Board. Proved oil and gas reserves are quantities, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. Our estimation of net recoverable quantities of liquid hydrocarbons and natural gas is a highly technical process performed by our internal teams of geoscience and reservoir engineering professionals. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of June 25, 2019).” The method or combination of methods used in the analysis of each reservoir is based on the maturity of the reservoir, the completeness of the subsurface data available at the time of the estimate, the stage of reservoir development and the production history. Subsurface data used included well logs, reservoir core and fluid samples, production and pressure testing, static and dynamic pressure information, and reservoir surveillance. Where applicable, reliable technologies may be used in reserve estimation, as defined in the SEC regulations. These technologies, including computational methods, must have been field tested and demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In some cases, where appropriate, use of empirical and analytical methods, combined with analog data were used. Analytic tools, including reservoir simulation, geologic modeling and seismic processing, have been used in the interpretation of the subsurface data. These technologies were used to increase the quality and confidence in the reserves estimates.
In order for reserves to be classified as proved, any required government approvals must be obtained and depending on the cost of the project, either senior management or the Board of Directors must commit to fund the development. Our proved reserves are subject to certain risks and uncertainties, which are discussed in Item 1A. Risk Factors of this Form 10‑K.
Internal Controls
The Corporation maintains internal controls over its oil and gas reserve estimation processes, which are administered by our Global Reserves group and our Chief Financial Officer. Estimates of reserves are prepared by technical staff who work directly with the oil and gas properties using industry standard reserve estimation principles, definitions and methodologies. Each year, reserve estimates of the Corporation’s assets are subject to internal technical audits and reviews. In addition, an independent third-party reserve engineer reviews and audits a significant portion of the Corporation’s reported reserves (see pages 93 through 97). Reserve estimates are reviewed by senior management and the Board of Directors.
Qualifications
The person primarily responsible for overseeing the preparation of the Corporation’s oil and gas reserves during 2020 was the Senior Manager, Global Reserves. He is a member of the Society of Petroleum Engineers and has 18 years of experience in the oil and gas industry with a MSc degree in Petroleum Engineering. His experience has been primarily focused on oil and gas subsurface understanding and reserves estimation in both domestic and international areas. He is also responsible for the Corporation’s Global Reserves group, which is the internal organization that establishes the policies and processes used within the operating units to estimate reserves and perform internal technical reserve audits and reviews.
Reserves Audit
We engaged the consulting firm of DeGolyer and MacNaughton (D&M) to perform an audit of the internally prepared reserve estimates on certain fields aggregating 92% of 2020 year‑end reported reserve quantities on a barrel of oil equivalent basis (2019: 80%). The purpose of this audit was to provide additional assurance on the reasonableness of internally prepared reserve estimates and compliance with SEC regulations. The D&M report, dated February 3, 2021, 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, 2020 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 audited by D&M, in the aggregate, differed by less than 1% (2019: less than 1%) 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, 2020 were $39.77 per barrel for WTI (2019: $55.73; 2018: $65.55) and $43.43 per barrel for Brent (2019:
$62.54; 2018: $72.08). New York Mercantile Exchange (NYMEX) natural gas prices used were $2.16 per mcf in 2020 (2019: $2.54; 2018: $3.01).
At December 31, 2020, spot prices for WTI oil closed at $48.52 per barrel. If crude oil prices in 2021 are at levels below that used in determining 2020 proved reserves, we may recognize negative revisions to our December 31, 2021 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 2021 above those used in determining 2020 proved reserves could result in positive revisions to proved developed and proved undeveloped reserves at December 31, 2021. It is difficult to estimate the magnitude of any potential net negative or positive change in proved reserves at December 31, 2021, due to numerous currently unknown factors, including 2021 crude oil prices, the amount of any additions to proved reserves, positive or negative revisions in proved reserves related to 2021 reservoir performance, the levels to which industry costs will change in response to 2021 crude oil prices, and management’s plans as of December 31, 2021 for developing proved undeveloped reserves.
Following are the Corporation’s proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil & Condensate
|
|
Natural Gas Liquids
|
|
United
States
|
|
Guyana
|
|
Malaysia and
JDA
|
|
Other (a)
|
|
Total
|
|
United
States
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Millions of bbls)
|
|
(Millions of bbls)
|
Net Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At January 1, 2018
|
433
|
|
43
|
|
6
|
|
177
|
|
659
|
|
171
|
|
171
|
Revisions of previous estimates
|
(3)
|
|
(3)
|
|
1
|
|
(12)
|
|
(17)
|
|
(14)
|
|
(14)
|
Extensions, discoveries and other additions
|
114
|
|
—
|
|
2
|
|
9
|
|
125
|
|
39
|
|
39
|
Purchase of minerals in place
|
3
|
|
—
|
|
—
|
|
—
|
|
3
|
|
1
|
|
1
|
Sales of minerals in place
|
(3)
|
|
—
|
|
—
|
|
—
|
|
(3)
|
|
(8)
|
|
(8)
|
Production
|
(43)
|
|
—
|
|
(1)
|
|
(9)
|
|
(53)
|
|
(14)
|
|
(14)
|
At December 31, 2018
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At January 1, 2018
|
239
|
|
—
|
|
5
|
|
157
|
|
401
|
|
87
|
|
87
|
At December 31, 2018
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At January 1, 2018
|
194
|
|
43
|
|
1
|
|
20
|
|
258
|
|
84
|
|
84
|
At December 31, 2018
|
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
|
(a)Other includes our interests in Denmark and Libya.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
Total
|
|
United
States
|
|
Guyana
|
|
Malaysia and
JDA
|
|
Other (b)
|
|
Total
|
|
United
States
|
|
Guyana
|
|
Malaysia and
JDA
|
|
Other (b)
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Millions of mcf)
|
|
(Millions of boe)
|
Net Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At January 1, 2018
|
880
|
|
12
|
|
833
|
|
216
|
|
1,941
|
|
751
|
|
45
|
|
145
|
|
213
|
|
1,154
|
Revisions of previous estimates
|
(24)
|
|
—
|
|
(21)
|
|
(13)
|
|
(58)
|
|
(21)
|
|
(3)
|
|
(2)
|
|
(15)
|
|
(41)
|
Extensions, discoveries and other additions
|
177
|
|
—
|
|
104
|
|
11
|
|
292
|
|
183
|
|
—
|
|
19
|
|
11
|
|
213
|
Purchase of minerals in place
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
4
|
|
—
|
|
—
|
|
—
|
|
4
|
Sales of minerals in place
|
(145)
|
|
—
|
|
—
|
|
—
|
|
(145)
|
|
(35)
|
|
—
|
|
—
|
|
—
|
|
(35)
|
Production (a)
|
(75)
|
|
—
|
|
(132)
|
|
(8)
|
|
(215)
|
|
(70)
|
|
—
|
|
(23)
|
|
(10)
|
|
(103)
|
At December 31, 2018
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At January 1, 2018
|
526
|
|
—
|
|
696
|
|
197
|
|
1,419
|
|
414
|
|
—
|
|
121
|
|
190
|
|
725
|
At December 31, 2018
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At January 1, 2018
|
354
|
|
12
|
|
137
|
|
19
|
|
522
|
|
337
|
|
45
|
|
24
|
|
23
|
|
429
|
At December 31, 2018
|
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
|
(a)Natural gas production in 2020 includes 16 million mcf used for fuel (2019: 14 million mcf; 2018: 13 million mcf).
(b)Other includes our interests in Denmark and Libya.
Extensions, discoveries and other additions (‘Additions’)
2020: Total Additions were 142 million boe, of which 12 million boe (8 million barrels of crude oil, 2 million barrels of NGL and 14 million mcf of natural gas) related to proved developed reserves. Additions to proved developed reserves primarily resulted from drilling activity in the Bakken shale play in North Dakota. Additions to proved undeveloped reserves were 130 million boe (98 million barrels of crude oil, 16 million barrels of NGL and 93 million mcf of natural gas) and are discussed in further detail on page 96.
2019: Total Additions were 228 million boe, of which 25 million boe (13 million barrels of crude oil, 6 million barrels of NGL and 35 million mcf of natural gas) related to proved developed reserves. Additions to proved developed reserves primarily resulted from new wells drilled in the Bakken shale play in North Dakota. Additions in the U.S. also included two wells drilled in the Gulf of Mexico. Additions to proved undeveloped reserves were 203 million boe (144 million barrels of crude oil, 34 million barrels of NGL and 149 million mcf of natural gas) and are discussed in further detail on page 97.
2018: Total Additions were 213 million boe, of which 6 million boe (3 million barrels of crude oil and 18 million mcf of natural gas) related to proved developed reserves. Additions to proved developed reserves were primarily from drilling activity in the Bakken shale play in North Dakota. Additions to proved undeveloped reserves were 207 million boe (122 million barrels of crude oil, 39 million barrels of NGL and 274 million mcf of natural gas) and are discussed in further detail on page 97.
Revisions of previous estimates
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 237 million 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 97.
2019: Total revisions of previous estimates amounted to a net decrease of 107 million boe, of which revisions of proved developed reserves amounted to a net decrease of 19 million boe (7 million barrels of NGL and 72 million mcf of natural gas). Revisions to proved developed reserves from the Bakken were a net decrease of 25 million boe with approximately 80% relating to changes in expected recoveries of NGL and natural gas and approximately 20% relating to the impact of lower prices. Net revisions from international assets were an increase of 6 million boe. Revisions associated with proved undeveloped reserves are discussed in further detail on page 97.
2018: Total revisions of previous estimates amounted to a net decrease of 41 million boe, of which revisions of proved developed reserves amounted to a net increase of 3 million boe (4 million barrels of crude oil increase, 4 million barrels of NGL decrease and 20 million mcf of natural gas increase). Revisions to proved developed reserves primarily relate to the Bakken. Revisions associated with proved undeveloped reserves are discussed in further detail on page 97.
Sales of minerals in place (‘Asset sales’)
2020: Asset sales relate to the divestiture of our 28% working interest in the Shenzi Field in the deepwater Gulf of Mexico.
2018: Asset sales primarily include our former interests in the Utica Basin of Ohio.
Proved Undeveloped Reserves
Following are the Corporation’s proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United
States
|
|
Guyana
|
|
Malaysia and
JDA
|
|
Other (a)
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
(Millions of boe)
|
Net Proved Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
At January 1, 2018
|
337
|
|
45
|
|
24
|
|
23
|
|
429
|
Revisions of previous estimates
|
(22)
|
|
(3)
|
|
(6)
|
|
(13)
|
|
(44)
|
Extensions, discoveries and other additions
|
178
|
|
—
|
|
19
|
|
10
|
|
207
|
Transfers to proved developed reserves
|
(97)
|
|
—
|
|
—
|
|
(2)
|
|
(99)
|
Sales of minerals in place
|
(7)
|
|
—
|
|
—
|
|
—
|
|
(7)
|
At December 31, 2018
|
389
|
|
42
|
|
37
|
|
18
|
|
486
|
Revisions of previous estimates
|
(91)
|
|
9
|
|
—
|
|
(6)
|
|
(88)
|
Extensions, discoveries and other additions
|
154
|
|
34
|
|
—
|
|
15
|
|
203
|
Transfers to proved developed reserves
|
(108)
|
|
(29)
|
|
(4)
|
|
(2)
|
|
(143)
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2019
|
344
|
|
56
|
|
33
|
|
25
|
|
458
|
Revisions of previous estimates
|
(146)
|
|
42
|
|
(4)
|
|
(25)
|
|
(133)
|
Extensions, discoveries and other additions
|
78
|
|
50
|
|
2
|
|
—
|
|
130
|
Transfers to proved developed reserves
|
(85)
|
|
(8)
|
|
(7)
|
|
—
|
|
(100)
|
Sales of minerals in place
|
(3)
|
|
—
|
|
—
|
|
—
|
|
(3)
|
At December 31, 2020
|
188
|
|
140
|
|
24
|
|
—
|
|
352
|
(a)Other includes our interests in Denmark and Libya.
Extensions, discoveries and other additions (‘Additions’)
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 25% of the change results from additional planned wells to be drilled in the next five years, and approximately 75% results from new wells moved into the five-year plan associated with 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 in Libya due to additional planned wells to be drilled.
2018: In the United States, additions from the Bakken shale play in North Dakota were 168 million boe, of which approximately 40% of the change results from additional planned wells to be drilled in the next five years, approximately 35% results from performance associated with improved well completion designs, and approximately 25% results from other changes, primarily the impact of higher crude oil prices. Additions in the Gulf of Mexico were 10 million boe due to additional planned drilling at the Tubular Bells Field. Additions in Malaysia and JDA include 11 million boe at North Malay Basin and 8 million boe at the JDA relating to additional planned wells to be drilled within the next five years.
Revisions of previous estimates
2020: In the United States, negative reserve revisions of 146 million boe were from the Bakken, which included negative price revisions of 77 million boe, and a decrease of 121 million boe from wells 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 in 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 impact of lower 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 response to the decline in crude oil prices in 2020.
2019: Negative reserve revisions in the United States of 91 million boe were largely from the Bakken (94 million boe), of which approximately 75% resulted from wells moved outside our five-year plan associated with optimization of drilling locations. The remaining 25% of negative revisions in the Bakken were caused by lower commodity prices. The net positive reserve revisions in Guyana of 9 million boe relate to the Liza Phase 1 development due to the impact of lower crude oil prices on entitlement allocations in the production sharing agreement.
2018: Negative reserve revisions in the United States totaling 22 million boe, primarily resulted from optimizing drilling plans at the Bakken. Negative reserve revisions in international assets primarily resulted from updates in drilling plans in Denmark and North Malay Basin, and the impact of crude oil price changes on our production sharing agreement in Guyana.
Transfers to proved developed reserves (‘Transfers’)
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 100 million boe in the Bakken associated with drilling activity, 29 million boe at the Stabroek Block in Guyana where first production was achieved in 2019, and 8 million boe at the Tubular Bells Field in the Gulf of Mexico associated with drilling activity.
2018: Transfers from proved undeveloped reserves included 75 million boe in the Bakken associated with drilling activity, and 22 million boe at the Stampede Field in the Gulf of Mexico where first production was achieved in 2018.
In 2020, capital expenditures of $1,090 million were incurred to convert proved undeveloped reserves to proved developed reserves (2019: $1,750 million; 2018: $1,070 million).
At December 31, 2020, projects that have proved reserves that have been classified as undeveloped for a period in excess of five years totaled 4.7 million boe, or less than 1% of total proved reserves, primarily related to the multi-phase development at North Malay Basin, offshore Malaysia.
Production Sharing Contracts
The Corporation’s proved reserves include crude oil and natural gas reserves relating to long‑term agreements with governments or authorities in which the Corporation has the legal right to produce or has a revenue interest in the production. The Corporation's operations with these production sharing arrangements include those in Guyana, Malaysia, and the JDA. Proved reserves for each of the three years ended December 31, 2020, as well as volumes produced and received during 2020, 2019 and 2018 from these production sharing contracts are presented in the proved reserve tables on pages 94 and 95. Revisions resulting from the entitlement impact of price changes in production sharing contracts increased proved reserves by 22 million boe in 2020 (2019: 5 million boe increase; 2018: 7 million boe decrease).
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Future net cash flows are calculated by applying prescribed oil and gas selling prices used in determining year‑end reserve estimates (adjusted for price changes provided by contractual arrangements) to estimated future production of proved oil and gas reserves, less estimated future development 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 2020 were $39.77 per barrel for WTI (2019: $55.73; 2018: $65.55) and $43.43 per barrel for Brent (2019: $62.54; 2018: $72.08) and do not include the effects of commodity hedges. NYMEX natural gas prices used were $2.16 per mcf in 2020 (2019: $2.54; 2018: $3.01). Selling prices have in the past, and can in the future, fluctuate significantly. As a result, selling prices used in the disclosure of future net cash flows may not be representative of future selling prices. In addition, the discounted future net cash flow estimates do not include exploration expenses, interest expense or corporate general and administrative expenses. The amount of tax deductions, credits, and allowances relating to the Corporation’s proved oil and gas reserves can change year to year due to factors including changes in proved reserves, variances in actual pre-tax cash flows from forecasted pre-tax cash flows in historical periods, and the impact to year-end carryforward tax attributes associated with deducting in the Corporation’s income tax returns exploration expenses, interest expense, and corporate general and administrative expenses that are not contemplated in the standardized measure computations. The future net cash flow estimates could be materially different if other assumptions were used.
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At December 31
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Total
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United
States
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Guyana
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Malaysia and
JDA
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Other (a)
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(In millions)
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2020
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Future revenues
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$
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28,745
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$
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11,757
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$
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8,362
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$
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2,578
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$
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6,048
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Less:
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Future production costs
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12,360
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6,887
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2,784
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1,073
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1,616
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Future development costs
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6,322
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2,593
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2,617
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677
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435
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Future income tax expenses
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4,135
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45
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380
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110
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3,600
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22,817
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9,525
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5,781
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1,860
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5,651
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Future net cash flows
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5,928
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2,232
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2,581
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718
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397
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Less: Discount at 10% annual rate
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2,343
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1,205
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935
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123
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80
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Standardized Measure of Discounted Future Net Cash Flows
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$
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3,585
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$
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1,027
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$
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1,646
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$
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595
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$
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317
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2019
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Future revenues
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$
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44,778
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$
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25,223
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$
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5,326
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$
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3,473
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$
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10,756
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Less:
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Future production costs
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14,176
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10,189
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931
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1,238
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1,818
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Future development costs
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8,267
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5,104
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1,549
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823
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791
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Future income tax expenses
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8,560
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1,291
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505
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162
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6,602
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31,003
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16,584
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2,985
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2,223
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9,211
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Future net cash flows
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13,775
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8,639
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2,341
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1,250
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1,545
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Less: Discount at 10% annual rate
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5,390
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3,872
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|
539
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270
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|
709
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Standardized Measure of Discounted Future Net Cash Flows
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$
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8,385
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$
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4,767
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$
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1,802
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$
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980
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$
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836
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2018
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Future revenues
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$
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50,948
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$
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31,460
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$
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2,826
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$
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4,443
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$
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12,219
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Less:
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Future production costs
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13,636
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9,718
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605
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1,324
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1,989
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Future development costs
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8,427
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6,132
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596
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949
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750
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Future income tax expenses
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10,950
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2,641
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334
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233
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7,742
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33,013
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18,491
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1,535
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2,506
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10,481
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Future net cash flows
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17,935
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12,969
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1,291
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1,937
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1,738
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Less: Discount at 10% annual rate
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7,285
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5,437
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553
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492
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|
803
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Standardized Measure of Discounted Future Net Cash Flows
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$
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10,650
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$
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7,532
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$
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738
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$
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1,445
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$
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935
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(a)Other includes our interests in Denmark and Libya.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
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For the Years Ended December 31
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2020
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2019
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2018
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(In millions)
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Standardized Measure of Discounted Future Net Cash Flows at January 1
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$
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8,385
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$
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10,650
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$
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6,356
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Changes during the year:
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Sales and transfers of oil and gas produced during the year, net of production costs
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(1,829)
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(2,842)
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(2,755)
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Development costs incurred during the year
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1,479
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2,262
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1,533
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Net changes in prices and production costs
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(10,141)
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(5,761)
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7,076
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Net change in estimated future development costs
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1,860
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(186)
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(1,119)
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Extensions and discoveries (including improved recovery) of oil and gas reserves, less related costs
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543
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1,591
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2,129
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Revisions of previous oil and gas reserve estimates
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364
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(281)
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(630)
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Net purchases (sales) of minerals in place, before income taxes
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(500)
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—
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(83)
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Accretion of discount
|
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1,220
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|
|
1,635
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|
929
|
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Net change in income taxes
|
|
2,091
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|
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1,305
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(2,662)
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Revision in rate or timing of future production and other changes
|
|
113
|
|
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12
|
|
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(124)
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Total
|
|
(4,800)
|
|
|
(2,265)
|
|
|
4,294
|
|
Standardized Measure of Discounted Future Net Cash Flows at December 31
|
|
$
|
3,585
|
|
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$
|
8,385
|
|
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$
|
10,650
|
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