Item 7. Management’s Discussion and Analysis
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Exploration and Production (Contd.)
United States E&P operations reported earnings of $766.3 million in 2021 compared to a loss of $1,014.3 million in 2020. Results were favorable $1,780.6 million in 2021 compared to the 2020 period primarily due to no impairment charges in 2021 (2020 : $1,152.5 million), higher total revenues ($925.7 million), lower DD&A ($132.9 million), and lower LOE ($70.5 million), partially offset by higher income tax expense ($428.1 million) and higher other operating expense ($77.9 million). The impairment charge in the prior year was primarily the result of lower forecast future prices as of March 31, 2020, as a result of lower oil demand (COVID-19 impact) and abundant oil supply at the time of the assessment.
Higher revenues were primarily due to higher realized prices (oil and condensate, natural gas and NGLs) year over year, partially offset by lower sales volume (7,514 barrels of oil equivalent per day lower) as a result of lower capital expenditures in 2020. Lower DD&A is a result of the prior year impairment charge reducing the depreciable asset base. Lower lease operating expenses were primarily due to higher GOM workover costs in the prior year at Cascade ($51.3 million) and Dalmatian ($20.5 million). Higher income tax expense is a result of higher pre-tax income principally due to higher oil price and lower DD&A and LOE. Higher other operating expense is primarily due to an unfavorable mark-to-market revaluation on contingent consideration ($63.2 million; as a result of higher commodity prices) from prior GOM acquisitions.
Canadian E&P operations reported a loss of $16.1 million in 2021 compared to a loss of $35.0 million in 2020. Results were favorable $18.9 million compared to 2020 primarily due to higher revenue ($130.5 million) and lower DD&A ($49.4 million), partially offset by an impairment charge ($171.3 million), higher lease operating expense ($14.7 million), transportation, gathering and processing ($15.8 million) and income tax charges ($19.7 million). 2021 results include an impairment charge ($171.3 million) recorded in the first quarter following notice from the operator of asset abandonment at Terra Nova at the time of the assessment and a partially offsetting credit of $71.8 million as of September 30, 2021 reported in ‘other operating expense’ as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project and reversal of the asset abandonment decision.
Higher revenue is primarily attributable to higher natural gas prices and volumes at Tupper Montney and higher oil prices at Hibernia and Kaybob Duvernay. Lower DD&A is primarily due to lower production volumes at Kaybob Duvernay following reduced capital expenditures throughout 2020. Higher lease operating expenses and transportation, gathering and processing costs are due to higher gas processing and downstream transportation capacity, which are expected to be utilized by growth at Tupper Montney in the future.
Other international E&P operations reported a loss from continuing operations of $33.5 million in 2021 compared to a loss of $85.6 million in 2020. Results were favorable $52.1 million in 2021 compared to 2020 primarily due to lower impairment charges ($21.7 million), lower income tax charges ($11.6 million), lower exploration expenses ($5.9 million) primarily in Brazil and Mexico and lower LOE ($4.8 million).
2020 vs 2019
All amounts include amounts attributable to a noncontrolling interest in MP GOM (a subsidiary of Murphy Expro USA, operating and developing properties in the Gulf of Mexico) and exclude discontinued operations, unless otherwise noted.
E&P from continuing operations recorded a loss of $1,134.9 million in 2020 compared to earnings of $460.6 million in 2019. The results for 2020 were unfavorably impacted by impairment charges and lower oil and natural gas liquid prices and volumes, partially offset by lower depreciation and accretion expenses, G&A expenses, exploration expenses and taxes.
As a result of the COVID-19 pandemic and certain major global suppliers announcing crude oil supply increases in the first quarter of 2020, commodity prices were generally lower in 2020 vs 2019. Crude oil price realizations averaged $38.02 per barrel in 2020 compared to $60.27 per barrel in 2019, a price decrease of 37% year over year. U.S. natural gas realized price per MCF averaged $2.02 in 2020 compared to $2.45 per MCF in 2019, a price decrease of 18% year over year. Canada natural gas realized price per MCF averaged U.S. $1.79 in 2020 compared to U.S. $1.60 per MCF in 2019, a price increase of 12% year over year. Oil and natural gas production costs, including associated production taxes, on a per-unit basis, were $9.81 in 2020 excluding TGP (2019: $9.66). The increase in production costs in 2020 was primarily attributable to costs associated with well workovers at Cascade and Dalmatian in the U.S. Gulf of Mexico.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Exploration and Production (Contd.)
United States E&P operations reported a loss of $1,014.3 million in 2020 compared to earnings of $518.4 million in 2019. Results were $1,532.7 million unfavorable in 2020 compared to the 2019 period primarily due to higher impairment charges ($1,152.5 million), lower revenues ($955.2 million) and higher lease operating expenses ($15.4 million), partially offset by lower income tax expense ($359.8 million), depreciation, depletion and amortization (DD&A) ($129.3 million), G&A ($49.7 million), other operating expenses ($27.2 million) and transportation, gathering, and processing ($13.1 million). The impairment charge was primarily the result of lower future prices at the time of calculation, as a result of decreased oil demand.
Lower revenues were primarily due to lower commodity prices year over year and lower volumes in the U.S. Gulf of Mexico (as a result of shut-ins related to hurricanes and storms and lower capital expenditures). Higher lease operating expenses were due primarily to Gulf of Mexico well workovers at Cascade ($51.3 million) and Dalmatian ($20.5 million). Lower income tax expense was a result of pre-tax losses driven by the impairment charge and lower commodity prices. Lower other operating expense was primarily due to a favorable mark-to-market revaluation on contingent consideration (as a result of lower commodity prices) from prior Gulf of Mexico (GOM) acquisitions ($13.8 million). Lower G&A was due to cost reductions and lower headcount as a result of restructuring (primarily closing the El Dorado and Calgary offices).
Canadian E&P operations reported a loss of $35.0 million in 2020 compared to income of $4.3 million in 2019. Results were unfavorable $30.7 million compared to 2019 primarily due to lower revenue ($101.2 million) partially offset by lower DD&A ($29.8 million), lease operating expense ($20.8 million), income tax charges ($18.5 million) and G&A ($12.9 million). Lower revenues were due to lower oil and condensate prices versus the prior year and a shut-in at Terra Nova for Asset Integrity work (starting in December 2019 and expected to continue until 2022). Lower DD&A and lease operating expenses were a result of lower sales. Lower income tax expense was a result of pre-tax losses. Lower G&A was due to cost reductions and lower headcount as a result of restructuring.
Other international E&P operations reported a loss from continuing operations of $85.6 million in 2020 compared to a loss of $53.5 million in the prior year. The 2020 results included an impairment charge of $39.7 million and lower revenues of $9.8 million in Brunei.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Cost per equivalent barrel sold for these production-related expenses are shown by geographical area in the following table.
( Dollars per equivalent barrel )
2021 2020 2019
Continuing operations
United States – Eagle Ford Shale
Lease operating expense $ 8.96 9.08 8.70
Severance and ad valorem taxes 2.91 2.06 2.82
Depreciation, depletion and amortization (DD&A) expense 27.59 26.22 24.19
United States – Gulf of Mexico
Lease operating expense 10.63 11.95 10.89
Severance and ad valorem taxes 0.07 — —
DD&A expense 9.51 13.48 16.43
Canada – Onshore
Lease operating expense 6.20 4.63 5.49
Severance and ad valorem taxes 0.09 0.07 0.07
DD&A expense 7.64 9.93 10.94
Canada – Offshore
Lease operating expense 13.04 17.86 14.95
DD&A expense 12.80 12.01 13.07
Total oil and natural gas continuing operations
Lease operating expense 8.86 9.34 8.95
Severance and ad valorem taxes 0.68 0.44 0.71
DD&A expense 13.05 15.36 16.98
Total oil and natural gas continuing operations – excluding noncontrolling interest
Lease operating expense
8.65 9.10 8.81
Severance and ad valorem taxes 0.71 0.47 0.76
DD&A expense 13.23 15.49 17.05
Discontinued Operations
Malaysia
Lease operating expense — — 16.49
DD&A expense — — 4.60
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Corporate
2021 vs 2020
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains and losses on derivative instruments (forward swaps and collars to hedge the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $668.0 million in 2021 compared to a loss of $120.3 million in 2020. The $547.7 million unfavorable variance is principally due to higher net losses on derivative instruments in 2021 compared to the 2020 period (2021: $525.9 million loss; 2020: $202.7 million gain) and higher interest expense ($53.0 million), partially offset by a higher tax benefit ($148.3 million), lower restructuring charges ($48.8 million), lower G&A expenses ($12.9 million), and lower impairment charges ($7.1 million). Realized and unrealized losses on derivative instruments are due to an increase in market pricing in future periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price, with variability in between the floor and ceiling. Higher interest costs are principally due to debt redemption costs on the 2022 notes and $550.0 million issuance of new notes in March 2021 that bear interest at a rate of 6.375% and mature on July 15, 2028. Higher income tax benefit is a result of higher pre-tax loss driven by the higher realized and unrealized losses on derivative instruments. Lower restructuring charges and G&A are due to the 2020 cost reduction efforts which included closing the Company’s previous headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas.
2020 vs 2019
In 2020, the Company announced that it was closing its headquarters office in El Dorado, Arkansas, its office in Calgary, Alberta, and consolidating all worldwide staff activities to its existing office location in Houston, Texas. As a result, certain directly attributable costs and charges were recognized and reported as Restructuring charges as part of net loss in 2020. These costs included severance, relocation, IT costs, pension curtailment and a write-off of the right of use asset lease associated with the Canada office. Further, the office building in El Dorado was classified as held for sale.
Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains and losses on derivative instruments and corporate overhead not allocated to Exploration and Production, reported a loss of $120.3 million in 2020 compared to a loss of $271.8 million in 2019. The $151.5 million favorable variance was primarily due to higher realized gains on forward swap commodity contracts ($239.5 million), lower interest charges ($50.2 million), lower G&A ($14.5 million), and partially offset by higher tax charges ($55.3 million), restructuring charges ($48.8 million) related to the closure of the El Dorado and Calgary offices, and impairment charges ($14.1 million). Higher realized gains on forward swap commodity contracts were due to lower market pricing whereby the contract provides the Company with a fixed price. Interest charges were lower primarily due to 2019 temporary borrowings on the Company’s revolving credit facility (RCF) to fund the LLOG acquisition (the RCF borrowings were repaid in the third quarter 2019 following the divestment of the Malaysia business) and gains from the buy-back of debt in the second quarter 2020. As of December 31, 2020, the average forward NYMEX WTI prices for 2021 and 2022 were $48.34 and $46.76, respectively (versus fixed hedge prices of $42.77 and $44.88).
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Production Volumes and Prices
2021 vs 2020
Total hydrocarbon production from all E&P continuing operations averaged 167,356 barrels of oil equivalent per day in 2021, which represented a 4% decrease from the 174,636 barrels per day produced in 2020.
Average crude oil and condensate production from continuing operations was 95,705 barrels per day in 2021 compared to 103,966 barrels per day in 2020. The decrease of 8,261 barrels per day was principally due to lower volumes in the Gulf of Mexico (2,703 barrels per day primarily due to reservoir decline), lower volumes at Kaybob Duvernay (2,272 barrels per day due to well decline) and lower Eagle Ford Shale production (765 barrels per day). On a worldwide basis, the Company’s crude oil and condensate prices averaged $66.80 per barrel in 2021 compared to $38.02 per barrel in the 2020 period, an increase of 76% year over year.
Total production of natural gas liquids (NGL) from continuing operations was 10,385 barrels per day in 2021 compared to 11,541 barrels per day in the 2020 period. The average sales price for U.S. NGL was $27.97 per barrel in 2021 compared to $11.29 per barrel in 2020. The average sales price for NGL in Canada was $40.18 per barrel in 2021 compared to $18.54 per barrel in 2020. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob and Placid assets.
Natural gas sales volumes from continuing operations averaged 368 million cubic feet per day (MMCFD) in 2021 compared to 355 MMCFD in 2020. The increase of 13 MMCFD was primarily the result of higher volumes in Canada. Higher natural gas volumes in Canada are primarily due to bringing online 14 new wells at Tupper Montney in 2021. Higher volumes at Tupper Montney were partially offset by lower gas volumes in the Gulf of Mexico.
Natural gas prices for the total Company averaged $2.74 per thousand cubic feet (MCF) in 2021, versus $1.85 per MCF average in the same period of 2020. Average realized natural gas prices in the US and Canada in 2021 were $3.71 and $2.43 per MCF, respectively.
2020 vs 2019
Total hydrocarbon production from continuing operations averaged 174,636 barrels of oil equivalent per day in 2020, which represented a 6% decrease from the 185,649 barrels per day produced in 2019. Production in the Gulf of Mexico was significantly impacted by a record breaking hurricane year which resulted in shut-ins and loss of approximately 6.4 MBOED of production in 2020. Lower volumes in the Eagle Ford Shale volumes were due to lower capital expenditures.
Average crude oil and condensate production from continuing operations was 103,966 barrels per day in 2020 compared to 114,742 barrels per day in 2019. The decrease of 10,776 barrels per day was principally due to lower Eagle Ford Shale production (8,158 barrels per day) and lower volumes in the Gulf of Mexico (2,143 barrels per day) as stated above. On a worldwide basis, the Company’s crude oil and condensate prices averaged $38.02 per barrel in 2020 compared to $60.27 per barrel in 2019, a decrease of 37% year over year, resulting from the global downturn triggered by the COVID-19 pandemic.
Total production of natural gas liquids (NGL) from continuing operations was 11,541 barrels per day in 2020 compared to 11,888 per day in 2019. The average sales price for U.S. NGL was $11.29 per barrel in 2020 compared to $14.85 per barrel in 2019. The average sales price of NGL in Canada was $18.54 per barrel in 2020 compared to $26.04 per barrel in 2019. NGL prices are higher in Canada due to the higher value of product produced at the Kaybob Duvernay and Placid Montney assets.
Natural gas sales volumes from continuing operations averaged 355 million cubic feet per day (MMCFD) in 2020 compared to 354 MMCFD in 2019. The increase of 1 MMCFD was a primarily the result of higher volumes in the Gulf of Mexico (14 MMCFD) due to a full year contribution from the assets associated with the LLOG transaction.
Natural gas prices for the total Company averaged $1.85 per thousand cubic feet (MCF) in 2020, versus $1.8 per MCF average in 2019. Average prices in the U.S. and Canada in 2020 were $2.02 and $1.79 respectively.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
The following table contains hydrocarbons produced during the three years ended December 31, 2021.
Barrels per day unless otherwise noted 2021 2020 2019
Continuing operations
Net crude oil and condensate
United States Onshore 25,655 26,420 34,578
Gulf of Mexico 1
60,717 64,680 66,823
Canada Onshore 5,312 7,888 6,329
Offshore 3,765 4,893 6,543
Other 256 85 469
Total net crude oil and condensate - continuing operations 95,705 103,966 114,742
Net natural gas liquids
United States Onshore 5,092 5,248 5,731
Gulf of Mexico 1
4,176 4,978 4,894
Canada Onshore 1,117 1,315 1,263
Total net natural gas liquids - continuing operations 10,385 11,541 11,888
Net natural gas – thousands of cubic feet per day
United States Onshore 28,565 27,985 30,692
Gulf of Mexico 1
61,240 66,105 52,068
Canada Onshore 277,790 260,683 271,355
Total net natural gas - continuing operations 367,595 354,773 354,115
Total net hydrocarbons - continuing operations including NCI 2,3
167,356 174,636 185,649
Noncontrolling interest
Net crude oil and condensate – barrels per day (8,623) (9,962) (11,226)
Net natural gas liquids – barrels per day (303) (416) (507)
Net natural gas – thousands of cubic feet per day 2
(3,236) (3,843) (3,965)
Total noncontrolling interest (9,465) (11,019) (12,394)
Total net hydrocarbons - continuing operations excluding NCI 2,3
157,891 163,617 173,255
Discontinued operations
Net crude oil and condensate – barrels per day — — 12,215
Net natural gas liquids – barrels per day — — 325
Net natural gas – thousands of cubic feet per day 2
— — 50,758
Total discontinued operations — — 21,000
Total net hydrocarbons produced excluding NCI 2,3
157,891 163,617 194,255
Estimated net hydrocarbon reserves - million equivalent barrels 3,4
716.9 714.9 825.0
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1.
3 NCI – noncontrolling interest in MP GOM.
4 December 31, 2021, 2020 and 2019, include 18.4 MMBOE, 17.4 MMBOE and 24.6 MMBOE, respectively, relating to noncontrolling interest.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
The following table contains hydrocarbons sold during the three years ended December 31, 2021.
Barrels per day unless otherwise noted 2021 2020 2019
Continuing operations
Net crude oil and condensate
United States Onshore 25,655 26,420 34,578
Gulf of Mexico 1
60,544 65,621 66,272
Canada Onshore 5,312 7,888 6,329
Offshore 3,559 4,958 6,722
Other 195 78 427
Total net crude oil and condensate - continuing operations 95,265 104,965 114,328
Net natural gas liquids
United States Onshore 5,092 5,248 5,731
Gulf of Mexico 1
4,176 4,978 4,894
Canada Onshore 1,117 1,315 1,263
Total net natural gas liquids - continuing operations 10,385 11,541 11,888
Net natural gas – thousands of cubic feet per day
United States Onshore 28,565 27,985 30,692
Gulf of Mexico 1
61,240 66,105 52,068
Canada Onshore 277,790 260,683 271,355
Total net natural gas - continuing operations 367,595 354,773 354,115
Total net hydrocarbons - continuing operations including NCI 2,3
166,916 175,635 185,235
Noncontrolling interest
Net crude oil and condensate – barrels per day (8,605) (10,127) (11,115)
Net natural gas liquids – barrels per day (303) (416) (507)
Net natural gas – thousands of cubic feet per day 2
(3,236) (3,843) (3,965)
Total noncontrolling interest (9,447) (11,184) (12,283)
Total net hydrocarbons - continuing operations excluding NCI 2,3
157,469 164,451 172,952
Discontinued operations
Net crude oil and condensate – barrels per day — — 12,100
Net natural gas liquids – barrels per day — — 296
Net natural gas – thousands of cubic feet per day 2
— — 50,758
Total discontinued operations — — 20,856
Total net hydrocarbons sold excluding NCI 2,3
157,469 164,451 193,808
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1.
3 NCI – noncontrolling interest in MP GOM.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
The following table contains the weighted average sales prices excluding transportation cost deduction for the three years ended December 31, 2021. Comparative periods are conformed to current presentation.
2021 2020 2019
Weighted average Exploration and Production sales prices
Continuing operations
Crude oil and condensate – dollars per barrel
United States Onshore $ 66.90 36.54 59.45
Gulf of Mexico 1
66.93 39.15 61.09
Canada 2
Onshore 61.79 32.42 50.29
Offshore 71.39 39.40 64.91
Other 69.21 63.51 74.70
Natural gas liquids – dollars per barrel
United States Onshore 26.97 11.67 14.60
Gulf of Mexico 1
29.14 10.84 15.10
Canada 2
Onshore 40.18 18.54 26.04
Natural gas – dollars per thousand cubic feet
United States Onshore 3.83 1.95 2.47
Gulf of Mexico 1
3.67 2.04 2.43
Canada 2
Onshore 2.43 1.79 1.60
Discontinued operations
Crude oil and condensate – dollars per barrel
Malaysia 3
Sarawak — — 70.39
Block K — — 65.75
Natural gas liquids – dollars per barrel
Malaysia 3
Sarawak — — 48.23
Natural gas – dollars per thousand cubic feet
Malaysia 3
Sarawak — — 3.60
Block K — — 0.24
1 Prices include the effect of noncontrolling interest share for MP GOM.
2 U.S. dollar equivalent.
3 Prices are net of payments under the terms of the respective production sharing contracts.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Financial Condition
Cash Provided by Operating Activities
Net cash provided by continuing operating activities was $1,422.2 million in 2021 compared to $802.7 million in 2020. The increased cash provided by continuing operating activities of $619.5 million is primarily attributable to higher revenue from sales to customers ($1,049.5 million), positive effect of movements on payable and receivable working capital balances ($118.5 million), lower lease operating expenses ($60.5 million), lower general and administrative and cash restructuring expenses ($50.7 million), partially offset by higher cash payments made on forward swap commodity contracts (2021: realized loss of $413.7 million; 2020: realized gain of $272.0 million). Higher revenues were primarily due to higher commodity prices driven by OPEC+ supply constraints and the increase in demand.
Cash flow provided by continuing operations was $686.4 million lower in 2020 than in 2019 primarily due to lower revenues, partially offset by higher cash payments received on forward swap commodity contracts. Lower revenues were primarily due to lower commodity prices resulting from lower demand triggered by the COVID-19 pandemic and lower volumes (due to reduced capital expenditures).
The total reductions of operating cash flows for interest paid (which excludes debt redemption costs reported in Financing activities) during the three years ended December 31, 2021, 2020, and 2019 were $165.7 million, $191.6 million, and $179.7 million, respectively. Lower cash interest paid in 2021 was due to the repayment of the $200 million outstanding on the revolving credit facility, the early redemption of the 2022 notes and the early redemption of $300 million of the 2024 notes, partially offset by interest paid on the issuance of 2028 notes in the first quarter of 2021. Higher cash interest paid in 2020 was due to the new 2027 notes paying interest at 5.875% and revolver borrowing during the year.
Cash Used for Investing Activities
Cash used for property additions and dry holes, which includes amounts expensed, were $688.2 million and $872.8 million in 2021 and 2020, respectively. These amounts include $17.7 million and $113.0 million used to fund the development of the King’s Quay FPS in 2021 and 2020. In March 2021, the King’s Quay FPS was sold to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million, which reimbursed the Company for previously incurred capital expenditures. 2021 also includes proved property acquisitions for an additional interest in the Lucius property of $19.9 million. Lower property additions in 2021 are principally due to lower capital spending at Eagle Ford Shale and lower spend on King’s Quay.
In 2019, property additions included $1,261.1 million for the LLOG acquisition.
The accrual (value of work done) basis of capital expenditures were as follows:
Year Ended December 31,
(Millions of dollars) 2021 2020 2019
Capital Expenditures
Exploration and production $ 690.1 813.3 2,683.2
Corporate 21.1 13.3 15.0
Total capital expenditures $ 711.2 826.6 2,698.2
Total capital expenditures excluding proved property acquisitions $ 711.2 826.6 1,437.1
Total capital expenditures excluding proved property acquisitions and NCI $ 688.2 804.9 1,402.3
A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Condition (Contd.)
Year Ended December 31,
(Millions of dollars) 2021 2020 2019
Property additions and dry hole costs per cash flow statements $ 670.5 759.8 1,244.1
Property additions King's Quay per cash flow statements 17.7 113.0 100.2
Geophysical and other exploration expenses 26.9 32.3 48.5
Capital expenditure accrual changes and other (3.9) (78.5) 93.1
Acquisition of oil properties per the cash flow statements — — 1,212.3
Total capital expenditures $ 711.2 826.6 2,698.2
Capital expenditures in the exploration and production business in 2021 compared to 2020 have decreased as a result of capital expenditure reductions to support generating free cash flow.
Cash Used by and Provided by Financing Activities
Net cash required by financing activities was $794.5 million in 2021 compared to net cash provided by financing activities of $39.7 million during 2020. In 2021, the cash required by financing activities was principally due to the repayment of the balance outstanding on the revolving credit facility ($200.0 million), the early redemption of the remainder of the 2022 notes ($576.4 million), the early redemption of a portion of the 2024 notes ($300.0 million), costs associated with early redemption ($39.3 million), dividends paid ($77.2 million) and distributions to noncontrolling interest ($137.5 million), partially offset by issuance of 2028 notes ($541.9 million).
The primary sources of the Company’s liquidity are internally generated funds, access to outside financing and working capital. The Company generally uses its internally generated funds to finance its capital and operating expenditures, but it also maintains lines of credit with banks and will borrow as necessary to meet spending requirements. As of December 31, 2021, the Company has a $1.6 billion senior unsecured guaranteed credit facility (RCF) with a major banking consortium, which expires in November 2023. As of December 31, 2021 and in the event it is required to fund investing activities from borrowings, the Company has approximately $1.6 billion available on its committed revolving credit facility.
In 2020, net cash provided by financing activities of $39.7 million was principally from borrowings on the Company’s RCF ($200.0 million), partially offset by dividends paid ($96.0 million) and distributions to noncontrolling interest ($43.7 million).
In 2019, net cash required by financing activities of $1,130.0 million consisted of $548.0 million to redeem a portion of the 2022 notes, $499.9 million to buy back issued ordinary shares, $325.0 million to repay the RCF, $163.7 million to pay dividends, and $128.2 million to cover distributions to noncontrolling interest, net of proceeds of $542.4 million from the issuance of the 2027 notes.
Working Capital
At the end of 2021, working capital (total current assets less total current liabilities, excluding assets and liabilities held for sale) amounted to a net working capital liability of $298.9 million (2020: net working capital liability of $29.4 million). The total working capital liability increase of $269.5 million in 2021 is primarily attributable to higher accounts payable ($216.0 million) and higher other accrued liabilities ($210.3 million), partially offset by higher cash and cash equivalents ($210.6 million). The higher accounts payable is due to the increase in unrealized losses on derivative instruments (commodity swap and collar) maturing in the next 12 months. The higher other accrued liabilities are principally due to higher liabilities associated with current asset retirement obligations, and contingent consideration liabilities related to prior GOM acquisitions.
Cash and cash equivalents as of December 31, 2021 totaled $521.2 million (2020: $310.6 million). There were no borrowings from the RCF outstanding at the end of the year (2020: $200.0 million). Cash in the year benefited from a positive working capital inflow of $118.5 million principally due to increasing liabilities associated with a major U.S. Offshore capital project expected to begin production mid-2022.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Financial Condition (Contd.)
Cash and invested cash are maintained in several operating locations outside the U.S. As of December 31, 2021, Cash and cash equivalents held outside the U.S. included U.S dollar equivalents of approximately $242.9 million (2020: $119.3 million), the majority of which was held in Canada ($175.0 million). In addition, approximately $26.2 million and $14.0 million of cash was held in Brazil and the U.K., respectively. In certain cases, the Company could incur cash taxes or other costs should these cash balances be repatriated to the U.S. in future periods. Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S. See Note I – Income Taxes for further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the United States.
Capital Employed
As of December 31, 2021, long-term debt of $2,465.4 million had decreased by $522.7 million compared to December 31, 2020, as a result the net repayment of the $200.0 million outstanding on the revolving credit facility December 31, 2020, the early redemption of the 2022 notes and the early redemption of $300.0 million of the 2024 notes, partially offset by issuance of 2028 notes. The fixed-rate notes had a weighted average maturity of 7.5 years and a weighted average coupon of 6.2%.
A summary of capital employed as of December 31, 2021 and 2020 follows.
December 31, 2021 December 31, 2020
(Millions of dollars) Amount % Amount %
Capital employed
Long-term debt $ 2,465.4 37.2 % $ 2,988.1 41.5 %
Murphy shareholders' equity 4,157.3 62.8 % 4,214.3 58.5 %
Total capital employed $ 6,622.7 100.0 % $ 7,202.4 100.0 %
Murphy shareholders’ equity was $4.16 billion at the end of 2021 (2020: $4.21 billion). Shareholders’ equity decreased in 2021 primarily due to dividends paid ($77.2 million) and a 2021 net loss ($73.7 million), partially offset by a favorable revaluation of pension assets and liabilities ($59.8 million). A summary of transactions in stockholders’ equity accounts is presented in the Consolidated Statements of Stockholders’ Equity on page 72 of this Form 10-K report.
Other Balance Sheet Activity - Long-Term Assets and Liabilities
Other significant changes in Murphy’s balance sheet at the end of 2021, compared to 2020 are discussed below.
Property, plant and equipment, net of depreciation decreased $141.2 million principally due to an annual charge of depreciation, depletion and amortization ($795.1 million) of these balances and impairment charges ($196.3 million), offset by capital expenditures in the year. Capital expenditures are discussed above in the ‘Cash Used for Investing Activities’ section. An impairment charge of $171.3 million was triggered when the operator at Terra Nova provided notice of abandonment in the first quarter of 2021, before a commercial resolution in the third quarter of 2021 led Murphy to acquire an additional 7.525% in a commercial settlement with the other partners. The commercial resolution would have meant the Terra Nova impairment charge was not required. In the fourth quarter of 2021, a further impairment charge of $25.0 million was recorded on non-core assets.
Murphy had commitments for capital expenditures of approximately $520.1 million at December 31, 2021 (2020: $747.0 million). This amount includes $175.9 million for approved expenditure for capital projects relating to non-operated interests in deepwater U.S. Gulf of Mexico, principally at St. Malo ($173.0 million), non-operated Canada interests, mainly offshore ($84.7 million), non-operated Eagle Ford Shale ($18.1 million), Brazil ($16.3 million), Vietnam ($6.1 million), and Brunei ($2.6 million).
Assets held for sale of $15.5 million decreased $312.3 million due to the March 2021 sale of King’s Quay FPS to ArcLight Capital Partners, LLC (ArcLight) for proceeds of $267.7 million.
Operating lease assets ($881.4 million) and liabilities ($900.6 million) decreased $46.3 million principally due to an annual charge of depreciation, depletion and amortization and 2021 annual payments reducing the operating lease liabilities.
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Financial Condition (Contd.)
Long-term asset retirement obligations increased $23.5 million to $839.8 million, principally due to inflationary pressures from higher oil prices and associated demand for services.
Deferred credits and other liabilities decreased $110.0 million primarily as a result of the pension fair value remeasurement and cash pension contributions to the plan in 2021.
At December 31, 2021, the Company had no outstanding borrowings under the RCF and $31.4 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF. Borrowings under the RCF bear interest at rates, based, at the Company’s option, on the “Alternate Base Rate” of interest in effect plus the “ABR Spread” or the “Adjusted LIBOR Rate,” which is a periodic fixed rate based on LIBOR with a term equivalent to the interest period for such borrowing, plus the “Eurodollar Spread.” The “Alternate Base Rate” of interest is the highest of (i) the Wall Street Journal prime rate, (ii) the New York Federal Reserve Bank Rate plus 0.50%, and (iii) one-month LIBOR plus 1.00%. Note that in July 2017, the Financial Conduct Authority in the U.K. announced a desire to phase out LIBOR as a benchmark by the end of 2021. Some USD LIBOR tenors (overnight, 1-month, 3-month, 6-month and 12-month) will continue to be published until June 30, 2023. See “Risk Factors – Financial Risk Factors – Capital Financing” for further discussion. The “Eurodollar Spread” ranges from 1.075% to 2.10% per annum based upon the Corporation’s senior unsecured long-term debt securities credit ratings (the “Credit Ratings”). A facility fee accrues and is payable quarterly in arrears at a rate ranging from 0.175% to 0.40% per annum (based upon the Company’s Credit Ratings) on the aggregate commitments under the 2018 facility. At December 31, 2021, the interest rate in effect on borrowings under the facility was 1.78%. At December 31, 2021, the Company was in compliance with all covenants related to the RCF.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Environmental, Health and Safety Matters
Murphy faces various environmental, health and safety risks that are inherent in exploring for, developing and producing hydrocarbons. To help manage these risks, the Company has established a robust health, safety and environmental governance program comprised of a worldwide policy, guiding principles, annual goals and a management system incorporating oversight at each business unit, senior leadership and board levels. The Company strives to minimize these risks by continually improving its processes through design, operation and implementation of a comprehensive asset integrity plan, and through emergency and oil spill response planning to address any credible risks. These plans are presented to, reviewed and approved by a Health, Safety, Environmental and Corporate Responsibility Committee consisting of certain members of Murphy’s Board of Directors.
The oil and natural gas industry is subject to numerous international, foreign, national, state, provincial and local environmental, health and safety laws and regulations. Murphy allocates a portion of both its capital expenditures and its general and administrative budget toward compliance with existing and anticipated environmental, health and safety laws and regulations. These requirements affect virtually all operations of the Company and increase Murphy’s overall cost of business, including its capital costs to construct, maintain and upgrade equipment and facilities as well as operating costs for ongoing compliance.
The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including GHG emissions; wildlife, habitat and water protection; the placement, operation and decommissioning of production equipment; and the health and safety of our employees, contractors and communities where our operations are located. These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning facilities once production has ceased. Violations can give rise to sanctions including significant civil and criminal penalties, injunctions, construction bans and delays.
Further information on environmental, health and safety laws and regulations applicable to Murphy are contained in the Business section beginning page 11.
Climate Change and Emissions
The world’s population and standard of living is growing steadily along with the demand for energy. Murphy recognizes that this may generate increasing amounts of greenhouse gases, which raise important climate change concerns. Murphy works to assess the Company’s governance, strategy, risk identification, and management and measurement of climate risks and opportunities in order to remain in alignment with the Task Force on Climate-related Financial Disclosures (TCFD) core elements. The TCFD was created by the Financial Stability Board to focus on climate-related financial disclosures to improve and increase reporting of climate-related financial information. Murphy’s disclosures related to its alignment with the TCFD are included in the Company’s 2021 Sustainability Report issued on August 5, 2021, which is not incorporated by reference hereto.
During 2021 the Company made significant strides in our sustainability efforts, including:
• Setting a goal to achieve zero routine flaring by 2030;
• Obtaining third-party assurance of our 2020 Scope 1 and 2 gross-operated GHG emissions;
• Decreasing our 2020 Scope 1 and 2 GHG emissions intensity by 10% from our 2019 baseline;
• Publishing our estimated Scope 3, Category 11 - Use of Sold Products GHG emissions;
• Updating our 2008 established climate change position;
• Adding an annual GHG emissions intensity goal as a performance metric, to the already established safety and spills metrics, in our Company’s renumeration policy; and
• Including processes to stress-test our GHG emissions under various portfolio scenarios.
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Environmental, Health and Safety Matters (Contd.)
During 2020, the Company:
• Established a goal of reducing our GHG emissions intensity 15% to 20% by 2030 from our 2019 levels, excluding divested assets from the 2019 baseline, for an aggregate of 35% to 40% reduction from our reported 2019 levels;
• Expanded our GHG, air quality, climate risk management and biodiversity management public disclosures;
• Expanded the purview of our Health, Safety, Environmental and Corporate Responsibility Committee to include sustainability issues; and
• Created a Director of Sustainability role
Other Matters
Impact of inflation – In 2021, data indicates a sharp rise in inflation globally in most countries where the Company operates (this follows a sustained period of relatively low inflation prior to 2021). In the U.S. (and other parts of the globe), inflation has been triggered by constrained supplies and increasing demand of certain goods and services as recovery from the COVID-19 pandemic begins. The Company’s revenues, capital and operating costs are influenced to a larger extent by specific price changes in the oil and natural gas industry and allied industries rather than by changes in general inflation. Crude oil prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC+ production levels and/or attitudes of traders concerning supply and demand in the future. Prices for oil field goods and services are usually affected by the worldwide prices for crude oil.
As a result of increasing commodity prices for oil and natural gas, in 2021 and at the start of 2022, higher costs for goods and services in the oil and gas natural gas industry are being observed. Murphy has a dedicated procurement department focused on managing supply chain and input costs. Murphy also has certain transportation, processing and production handling services costs fixed through long-term contracts and commitments and therefore is partly protected from increasing price of services. However, from time to time, Murphy will seek to enter new commitments, exercise options to extend contracts and retender contracts for rigs and other industry services which could expose Murphy to the impact of higher prices. Murphy continues to strive toward safely executing our work in an ever increasing efficient manner to mitigate possible inflationary pressures in our business.
In 2020, some downward service cost relief was observed during a year of depressed commodity prices.
Natural gas prices are also affected by supply and demand, which are often affected by the weather and by the fact that delivery of natural gas can be restricted to specific geographic areas. Natural gas demand is also impacted by demand driven by lower carbon emission and a view that natural gas is one option to transition from higher carbon emitting fuels.
As a result of the overall volatility of oil and natural gas prices, it is not possible to predict the Company’s future cost of oil field goods and services.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Critical Accounting Estimates – In preparing the Company’s consolidated financial statements in accordance with U.S. GAAP, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Application of certain of the Company’s accounting policies requires significant estimates. The most significant of these accounting policies and estimates are described below.
Oil and natural gas proved reserves – Oil and natural gas proved reserves are defined by the SEC as those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations before the time at which contracts providing the right to operate expire (unless evidence indicates that renewal is reasonably certain). Proved developed reserves of oil and natural gas can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Although the Company’s engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. SEC rules require the Company to use an unweighted average of the oil and natural gas prices in effect at the beginning of each month of the year for determining quantities of proved reserves. These historical prices often do not approximate the average price that the Company expects to receive for its oil and natural gas production in the future. The Company often uses significantly different oil and natural gas price and reserve assumptions when making its own internal economic property evaluations. Changes in oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserves quantities.
Estimated reserves are subject to future revision, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Reserves revisions inherently lead to adjustments of the Company’s depreciation rates and the timing of settlement of asset retirement obligations. Downward reserves revisions can also lead to significant impairment expense. The Company cannot predict the type of oil and natural gas reserves revisions that will be required in future periods.
The Company’s proved reserves of crude oil, natural gas liquids and natural gas are presented on pages 110 to 119 of this Form 10-K report. Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data, and commercially available technologies, to establish ‘reasonable certainty’ of economic producibility. As defined by the SEC, reasonable certainty of proved reserves describes a high degree of confidence that the quantities will be recovered. In estimating proved reserves, Murphy uses familiar industry-accepted methods for subsurface evaluations, including performance, volumetric, and analog-based studies.
Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves. Reliable geologic and engineering technology is a method or combination of methods that are field-tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates. It was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas, and in certain reservoirs developed with the application of improved recovery techniques. Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data, and commercially available seismic processing and numerical reservoir simulation programs. Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.
See further discussion of proved reserves and changes in proved reserves during the three years ended December 31, 2021 beginning on pages 4 and 110 of this Form 10-K report.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Critical Accounting Estimates (Contd.)
Property, Plant & Equipment - impairment of long-lived assets – The Company continually monitors its long-lived assets recorded in Property, plant and equipment (PPE) in the Consolidated Balance Sheet to make sure that they are fairly presented. The Company must evaluate its PPE for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable from future cash flows.
A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the amount of oil and natural gas that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, future capital, operating and abandonment costs, and future inflation levels.
The need to test a long-lived asset for impairment can be based on several factors, including, but not limited to, a significant reduction in sales prices for oil and/or natural gas, unfavorable revisions of oil or natural gas reserves, or other changes to contracts, environmental, health and safety laws and regulations, tax laws or other regulatory changes. All of these factors must be considered when evaluating a property’s carrying value for possible impairment.
Due to the volatility of world oil and natural gas markets, the actual sales prices for oil and natural gas have often been different from the Company’s projections.
Estimates of future oil and natural gas production and sales volumes are based on a combination of proved and risked probable and possible reserves. Although the estimation of reserves and future production is uncertain, the Company believes that its estimates are reasonable; however, there have been cases where actual production volumes were higher or lower than projected and the timing was different than the original projection. The Company adjusts reserves and production estimates as new information becomes available.
The Company generally projects future costs by using historical costs adjusted for both assumed long-term inflation rates and known or expected changes in future operations. Although the projected future costs are considered to be reasonable, at times, costs have been higher or lower than originally estimated.
In 2021 and 2020, the Company recognized pretax noncash impairment charges of $196.3 million and $1,206.3 million, respectively, to reduce the carrying values at select properties. In 2021, the Company recorded an impairment charge of $171.3 million for Terra Nova due to the status, including agreements with the partners, of operating and production plans and $25.0 million for assets reported as Assets held for sale in the Consolidated Balance Sheets.
In 2020, declines in future oil and natural gas prices (principally driven by reduced commodity demand in response to the COVID-19 pandemic and increased supply in the first quarter of 2020 from foreign oil producers) led to impairments in certain of the Company’s U.S. Offshore and Other Foreign properties and assets.
See also Note D – Property, Plant and Equipment for further discussion of impairment charges.
Income taxes – The Company is subject to income and other similar taxes in all areas in which it operates. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of its annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; (c) future events often impact the timing of when income tax expenses and benefits are recognized by the Company; and (d) changes to regulations may be subject to different interpretations and require future clarification from issuing authorities or others.
The Company has deferred tax assets mostly relating to U.S net operating losses, liabilities for dismantlement, retirement benefit plan obligations and net deferred tax liabilities relating to tax and accounting basis differences for property, plant & equipment.
The Company routinely evaluates all deferred tax assets to determine the likelihood of their realization and reduce such assets to the expected realizable amount by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In assessing the need for valuation allowances, we consider all available positive and negative evidence. Positive evidence includes projected future taxable income and assessment of future business assumptions, a history of utilizing tax assets before expiration, significant proven and probable reserves and reversals of taxable temporary differences. Negative evidence includes losses in recent years.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Critical Accounting Estimates (Contd.)
As of December 31, 2021 the Company had a U.S. deferred tax asset associated with net operating losses of $577.5 million. In reviewing the likeliness of realizing this asset the Company considered the reversal of taxable temporary differences, carryforward periods, and future taxable income estimates based on projected financial information which, based on currently available evidence, we believe to be reasonably likely to occur. Certain estimates and assumptions are used in the estimation of future taxable income, including (but not limited to) (a) future commodity prices for crude oil and condensate, NGLs and natural gas, (b) estimated reserves for crude oil and condensate, NGLs and natural gas, (c) expected timing of production, (d) estimated lease operating costs, and (e) future capital requirements. In the future, the underlying actual assumptions utilized in estimating future taxable income could be different and result in different conclusions about the likelihood of the future utilization of our net operating loss carryforwards.
Accounting for retirement and postretirement benefit plans – Murphy and certain of its subsidiaries maintain defined benefit retirement plans covering certain full-time employees. The Company also sponsors health care and life insurance benefit plans covering most retired U.S. employees. The expense associated with these plans is estimated by management based on a number of assumptions and with consultation assistance from qualified third-party actuaries. The most important of these assumptions for the retirement plans involve the discount rate used to measure future plan obligations and the expected long-term rate of return on plan assets. For the retiree medical and insurance plans, the most important assumptions are the discount rate for future plan obligations and the health care cost trend rate. Discount rates are based on the universe of high-quality corporate bonds that are available within each country. Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans. The discounted cash flows are used to determine an equivalent single rate which is the basis for selecting the discount rate within each country. Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics. Anticipated health care cost trend rates are determined based on prior experience of the Company and an assessment of near-term and long-term trends for medical and drug costs.
Based on bond yields as of December 31, 2021, the Company has used a weighted average discount rate of 2.83% at year-end 2021 for the primary U.S. plans. This weighted average discount rate is 0.4% higher than prior year, which decreased the Company’s recorded liabilities for retirement plans compared to a year ago. The Company presently assumes a return on plan assets of 5.25% for the primary U.S. plan, it periodically reconsiders the appropriateness of this and other key assumptions. The Company’s retirement and postretirement plan (health care and life insurance benefit plans) expenses in 2022 are expected to be $9.9 million lower than 2021 primarily due to the increase in expected return assumptions for the US pension plan from 5.25% in 2021 to 6.60% in 2022, coupled with the impact of 2021 pension plan gain on reducing the amount of accumulated loss to be amortized as expense. Cash contributions to all plans are anticipated to be $5.5 million higher in 2022.
In 2021, the Company paid $36.5 million into various retirement plans and $1.1 million into postretirement plans. In 2022, the Company is expecting to fund payments of approximately $38.2 million into various retirement plans and $4.9 million for postretirement plans. The Company could be required to make additional and more significant funding payments to retirement plans in future years. Future required payments and the amount of liabilities recorded on the balance sheet associated with the plans could be unfavorably affected if the discount rate declines, the actual return on plan assets falls below the assumed return, or the health care cost trend rate increase is higher than expected.
Recent Accounting Pronouncements
See Note B – New Accounting Principles and Recent Accounting Pronouncements our Consolidated Financial Statements regarding the impact or potential impact of recent accounting pronouncements upon our financial position and results of operations.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Contractual obligations and guarantees – The Company is obligated to make future cash payments under borrowing arrangements, operating leases, purchase obligations primarily associated with existing capital expenditure plans, and other long-term liabilities. Total payments due after 2021 under such contractual obligations and arrangements are shown in the table below. Amounts are undiscounted and therefore may differ to those presented in the financial statements.
(Millions of dollars) Amount of Obligations
Total 2022 2023 - 2024 2025 - 2026 After 2026
Debt, excluding interest $ 2,483.3 — 242.4 548.7 1,692.2
Operating leases and other leases ¹ 1,258.5 185.9 272.5 148.9 651.2
Capital expenditures, drilling rigs and other ² 1,572.9 704.2 340.1 172.2 356.4
Other long-term liabilities, including debt interest ³ 2,747.2 195.7 353.8 456.0 1,741.7
Total $ 8,061.9 1,085.8 1,208.8 1,325.8 4,441.5
1 Other leases refers to a finance lease in Brunei (see Note U – Leases to the financial statements).
2 Capital expenditures, drilling rigs and other includes $175.9 million, $84.7 million, $24.9 million, and $18.1 million in 2022 for approved capital projects in non-operated interests in U.S. Gulf of Mexico, Canada Offshore, Other Foreign Offshore, and U.S. Onshore, respectively.
Also includes $72.0 million (2022), $129.5 million (2023 - 2024), $98.2 million (2025 - 2026) and $227.7 million (After 2026) for pipeline transportation commitments in Canada.
Also includes $4.5 million (2022), $10.7 million (2023 - 2024), $10.3 million (2025 - 2026) and $32.3 million (After 2026) for long term take or pay commitments relating to gas processing in Canada.
3 Other long-term liabilities, including debt interest includes future cash outflows for asset retirement obligations.
The Company has entered into agreements to lease production facilities for various producing oil fields as well as other arrangements that call for future payments as described in the following section. The Company’s share of the contractual obligations under these leases and other arrangements has been included in the table above.
In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide letters of credit that may be drawn upon if the Company fails to perform under those contracts. Total outstanding letters of credit were $223.5 million as of December 31, 2021.
Material off-balance sheet arrangements – Certain U.S. transportation contracts require minimum monthly payments through 2045, while Western Canada processing contracts call for minimum monthly payments through 2051. Future required minimum annual payments under these arrangements are included in the contractual obligation table above.
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Outlook
Prices for the Company’s primary products are often volatile. The price of crude oil is primarily affected by the levels of supply and demand for energy. Anticipated future variances between the predicted demand for crude oil and the projected available supply can lead to significant movement in the price of crude oil. As of close on February 24, 2022, the NYMEX WTI forward curve price for the remainder of 2022 and 2023 were $86.31 and $77.72 per barrel, respectively; however we cannot predict what impact economic factors (including the ongoing COVID-19 pandemic and OPEC+ decisions) may have on future commodity pricing. Lower prices, should they occur, will result in lower profits and operating cash-flows.
The Company’s capital expenditure spend for 2022 is expected to be between $840.0 million and $890.0 million, excluding the amount attributable to noncontrolling interest. Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its capital program in 2022 using operating cash flow and available cash. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.
The Company currently expects average daily production in 2022 to be between 172,600 and 180,600 barrels of oil equivalent per day (including noncontrolling interest of 8,600 BOEPD). If significant price declines occur, the Company will review the option of production curtailments to avoid incurring losses on certain produced barrels.
The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, or payment to noncontrolling interests) to repay outstanding debt and return to shareholders through dividends.
The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note G – Financing Arrangements and Debt ). The Company continues to monitor the effects of the COVID-19 pandemic and is encouraged by the increase in oil and natural gas demand through 2021 and into 2022.
The Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:
Volumes
(MMcf/d) Price/Mcf Remaining Period
Area Commodity Type Start Date End Date
Montney Natural Gas Fixed price forward sales 186 C$2.36 1/1/2022 1/31/2022
Montney Natural Gas Fixed price forward sales 176 C$2.34 2/1/2022 4/30/2022
Montney Natural Gas Fixed price forward sales 205 C$2.34 5/1/2022 5/31/2022
Montney Natural Gas Fixed price forward sales 247 C$2.34 6/1/2022 10/31/2022
Montney Natural Gas Fixed price forward sales 266 C$2.36 11/1/2022 12/31/2022
Montney Natural Gas Fixed price forward sales 269 C$2.36 1/1/2023 3/31/2023
Montney Natural Gas Fixed price forward sales 250 C$2.35 4/1/2023 12/31/2023
Montney Natural Gas Fixed price forward sales 162 C$2.39 1/1/2024 12/31/2024
Montney Natural Gas Fixed price forward sales 45 US$2.05 1/1/2022 12/31/2022
Montney Natural Gas Fixed price forward sales 25 US$1.98 1/1/2023 10/31/2024
Montney Natural Gas Fixed price forward sales 15 US$1.98 11/1/2024 12/31/2024
Commodity Type Volumes
(Bbl/d) Price
(USD/Bbl) Remaining Period
Area Start Date End Date
United States WTI ¹ Fixed price derivative swap 20,000 $44.88 1/1/2022 12/31/2022
Volumes
(Bbl/d) Average
Put
(USD/Bbl) Average
Call
(USD/Bbl) Remaining Period
Area Commodity Type Start Date End Date
United States WTI ¹ Derivative collars 25,000 $63.24 $75.20 1/1/2022 12/31/2022
1 West Texas Intermediate
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Forward-Looking Statements
This Form 10-K contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement include, but are not limited to: macro conditions in the oil and gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets or economies in general. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see Item 1A. Risk Factors , which begins on page 15 of this Annual Report on Form 10-K. Murphy undertakes no duty to publicly update or revise any forward-looking statements.