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Item 7. Management’s Discussion and Analysis

2024-02-23 compared with 2023-02-27 · 51 added, 428 removed, 122 unchanged (80% of the section changed)

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

United States E&P operations reported earnings of $1,521.9 million in 2022 compared to earnings of $766.3 million in 2021.

Results were favorable $755.6 million in 2022 compared to the 2021 period driven by higher total revenues ($1,123.7 million), partially offset by higher LOE ($116.3 million), income tax expense ($186.9 million), other operating expense ($26.9 million), severance and ad valorem taxes ($16.1 million) and transportation, gathering and processing costs ($15.7 million).

Higher revenues are primarily attributable to higher realized prices in 2022 compared to 2021 and higher sales volumes (4,026 barrels of oil equivalent per day higher) which includes additional sales volumes from the Khaleesi, Mormont, Samurai field development project in the Gulf of Mexico.

Higher LOE relates to higher production volumes, cost increases from inflationary pressures related to the onshore business and higher production handling fees at the Khaleesi and Mormont assets.

Higher income tax expense is a result of higher pre-tax income.

Increases in other operating expenses is primarily due to a higher asset retirement adjustments related to non-producing fields, ($37.2 million) and higher unfavorable mark to market revaluation on contingent consideration ($15.1 million) from prior Gulf of Mexico acquisitions.

Higher severance and ad valorem taxes are due to higher revenues at Eagle Ford Shale and higher transportation, gathering and processing costs are due to higher sales volumes at the Gulf of Mexico.

Canadian E&P operations reported earnings of $134.2 million in 2022 compared to a loss of $16.1 million in 2021.

Results were favorable $150.3 million compared to 2021 primarily due to higher revenue from production ($105.1 million), no impairment charges in 2022 (2021:$171.3 million) and lower DD&A ($22.3 million), partially offset by higher other operating expense ($78.6 million), higher income tax charges ($45.3 million), higher LOE ($18.8 million) and higher transportation, gathering and processing ($10.0 million).

Higher revenue is primarily attributable to higher realized prices and higher gas volumes (new wells added in 2022).

Lower impairment and higher other operating expense in 2022 was the result of the 2021 impairment charge for Terra Nova.

The impairment charge was recorded in the first quarter of 2021 following notice from the operator of asset abandonment at Terra Nova at the time of the assessment, which was later partially offset with a credit of $71.8 million in the third quarter of 2021 which was 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 income tax expense is a result of higher pre-tax income.

Higher LOE is due to higher gas volumes and higher processing rates at Tupper Montney.

Increased transportation, gathering and processing expense is due to higher sales volumes and an increase in transportation rates at Tupper Montney.

Other international E&P operations reported a loss from continuing operations of $77.0 million in 2022 compared to a loss of $33.5 million in 2021.

Results were unfavorable $43.5 million in 2022 compared to 2021 and were largely driven by higher exploration expenses ($57.7 million) and higher income tax charges ($12.4 million), partially offset by lower impairment charges ($18.0 million) and higher revenues ($17.9 million).

Exploration expenses in 2022 primarily relate to the Cutthroat-1 exploration well in block SEAL-M-428 in the Sergipe-Alagoas Basin offshore Brazil and the Tulum-1EXP exploration well in Block 5 in the Salina Basin offshore Mexico that failed to encounter commercial hydrocarbons.

The results of operations in this section 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 earnings of $716.7 million in 2021 compared to a loss of $1,134.9 million in 2020.

Results were favorable $1,851.6 million in 2021 compared to 2020 primarily due to higher oil, natural gas liquid and natural gas prices, significantly lower impairment charges, lower DD&A, lower LOE, lower exploration expenses and lower general and administrative (G&A) expenses, partially offset by higher transportation, gathering and processing and income tax charges.

See below for further details.

Crude oil price realizations averaged $66.80 per barrel in 2021 compared to $38.02 per barrel in 2020, a price increase of 76% year over year.

natural gas realized price per MCF averaged $3.71 in 2021 compared to $2.02 per MCF in 2020, an increase of 84% year over year.

Canada natural gas realized price per MCF averaged U.S.

$2.43 in 2021 compared to U.S.

$1.79 per MCF in 2020, an increase of 36% year over year.

Oil and natural gas production costs, on a per-unit basis, were $9.53 in 2021 (2020:

The decrease in per-unit production

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

costs in 2021 was primarily attributable to reduced costs associated with well workovers and concerted efficiency efforts.

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 2020 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 primarily resulted from the prior year impairment charge reducing the depreciable asset base.

Lower LOE was primarily due to higher Gulf of Mexico workover costs in the prior year at Cascade ($51.3 million) and Dalmatian ($20.5 million).

Higher income tax expense was a result of higher pre-tax income principally due to higher oil price and lower DD&A and LOE.

Higher other operating expense was primarily due to an unfavorable mark-to-market revaluation on contingent consideration ($63.2 million;

as a result of higher commodity prices) from prior Gulf of Mexico 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 LOE ($14.7 million), transportation, gathering and processing ($15.8 million) and income tax charges ($19.7 million).

2021 results included 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 was primarily attributable to higher natural gas prices and volumes at Tupper Montney and higher oil prices at Hibernia and Kaybob Duvernay.

Lower DD&A was primarily due to lower production volumes at Kaybob Duvernay following reduced capital expenditures throughout 2020.

Higher LOE and transportation, gathering and processing costs were due to the cost of 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).

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 )

2022 2021 2020

Continuing operations

United States – Eagle Ford Shale

Lease operating expense $ 10.97 $ 8.96 $ 9.08

Severance and ad valorem taxes 4.27 2.91 2.06

DD&A expense 25.61 27.59 26.22

United States – Gulf of Mexico 1

Lease operating expense $ 13.19 $ 10.63 $ 11.95

Severance and ad valorem taxes 0.07 0.07 —

DD&A expense 10.12 9.51 13.48

Canada – Onshore

Lease operating expense $ 6.75 $ 6.20 $ 4.63

Severance and ad valorem taxes 0.06 0.09 0.07

DD&A expense 6.20 7.64 9.93

Canada – Offshore

Lease operating expense $ 14.20 $ 13.04 $ 17.86

DD&A expense 12.25 12.80 12.01

Total E&P continuing operations

Lease operating expense $ 10.65 $ 8.86 $ 9.34

Severance and ad valorem taxes 0.89 0.68 0.44

DD&A expense 12.18 13.05 15.36

Total oil and natural gas continuing operations –

excluding noncontrolling interest

Lease operating expense

$ 10.50 $ 8.65 $ 9.10

Severance and ad valorem taxes 0.93 0.71 0.47

DD&A expense 12.30 13.23 15.49

1 Includes results attributable to a noncontrolling interest in MP GOM.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

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 $438.3 million in 2022 compared to a loss of $668.0 million in 2021.

The $229.7 million favorable variance is principally due to lower net losses on derivative instruments in 2022 compared to 2021 (2022:

$320.4 million loss;

$525.9 million loss), lower interest expense ($71.0 million) and higher foreign exchange gains ($26.0 million), partially offset by a lower tax benefit ($70.8 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.

As of December 31, 2022, the Company had no fixed price derivative swaps or collars contracts outstanding.

Interest charges are lower in 2022 primarily due to lower overall debt and lower debt redemption costs ($8.3 million in 2022;

$39.3 million in 2021) incurred by the Company.

The Company reduced debt by $649.7 million in 2022.

Lower income tax benefit is a result of lower pre-tax losses.

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 was principally due to higher net losses on derivative instruments in 2021 compared to the 2020 period (2021:

$525.9 million loss;

$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 were due to an increase in market pricing in future periods whereby the swap contracts provided the Company with a fixed price and the collar contracts provided for a minimum (floor) and a maximum (ceiling) price, with variability in between the floor and ceiling.

Higher interest costs were 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 was the result of higher pre-tax loss driven by the higher realized and unrealized losses on derivative instruments.

Lower restructuring charges and G&A were 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.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Production Volumes and Prices

Total hydrocarbon production from all E&P continuing operations averaged 175,156 barrels of oil equivalent per day in 2022, and represents a 5% increase from the 167,356 barrels per day produced in 2021.

The increase is principally due to the Khaleesi, Mormont, Samurai field development project that started production in the second quarter of 2022, new wells at Tupper Montney and lower weather related downtime in 2022.

Average crude oil and condensate production from continuing operations was 97,365 barrels per day in 2022 compared to 95,705 barrels per day in 2021.

The increase of 1,660 barrels per day is principally due to increased production in the Gulf of Mexico (4,694 barrels per day) with new production from Khaleesi, Mormont, Samurai field development project, partially offset by normal declines at other fields in the Gulf of Mexico.

Eagle Ford Shale production is lower (1,202 barrels per day) due to lower capital expenditures in 2020 and 2021, partially offset by new wells in 2022.

Canada production is lower (2,260 barrels per day) due to normal field decline at Kaybob Duvernay and Hibernia, as well as a turnaround at Hibernia.

On a worldwide basis, the Company’s crude oil and condensate prices average $94.89 per barrel in 2022 compared to $66.80 per barrel in the 2021 period, an increase of 42% year over year.

Total production of natural gas liquids (NGL) from continuing operations was 10,681 barrels per day in 2022 compared to 10,385 barrels per day in 2021.

The average sales price for U.S.

NGL was $34.87 per barrel in 2022 compared to $27.97 per barrel in 2021.

The average sales price for NGL in Canada was $55.65 per barrel in 2022 compared to $40.18 per barrel in 2021.

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 403 MMCFD in 2022 compared to 368 MMCFD in 2021.

The increase of 35 MMCFD was primarily the result of higher volumes in Canada (32.4 MMCFD) and higher volumes in the Gulf of Mexico (2.1 MMCFD).

The higher natural gas volumes in Canada was the result of new wells on production in 2022.

Natural gas prices for the total Company averaged $3.66 per MCF in 2022, versus $2.74 per MCF average in the same period of 2021.

Average realized natural gas prices in the U.S.

and Canada in 2022 were $6.68 and $2.76 per MCF, respectively.

Average realized natural gas prices in Canada are lower as a result of certain fixed price sales volume contracts.

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 2020, 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 2020.

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 of NGL in Canada was $40.18 per barrel in 2021 compared to $18.54 per barrel in 2020.

NGL prices were 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 368 MMCFD in 2021 compared to 355 MMCFD in 2020.

The increase of 13 MMCFD was a primarily the result of higher volumes in Canada due to bringing online 14 new wells at Tupper Montney in 2021.

Higher volumes at Tupper Montney were partially offset by lower natural gas volumes in the Gulf of Mexico.

Natural gas prices for the total Company averaged $2.74 per MCF in 2021, versus $1.85 per MCF average in 2020.

Average realized natural gas prices in the U.S.

and Canada in 2021 were $3.71 and $2.43 per MCF, respectively.

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, 2022.

(Barrels per day unless otherwise noted) 2022 2021 2020

Continuing operations

Net crude oil and condensate

United States Onshore 24,437 25,655 26,420

Gulf of Mexico 1

65,411 60,717 64,680

Canada Onshore 4,005 5,312 7,888

Offshore 2,812 3,765 4,893

Other 700 256 85

Total net crude oil and condensate - continuing operations 97,365 95,705 103,966

Net natural gas liquids

United States Onshore 5,181 5,092 5,248

Gulf of Mexico 1

4,597 4,176 4,978

Canada Onshore 903 1,117 1,315

Total net natural gas liquids - continuing operations 10,681 10,385 11,541

Net natural gas – thousands of cubic feet per day

United States Onshore 29,050 28,565 27,985

Gulf of Mexico 1

63,380 61,240 66,105

Canada Onshore 310,230 277,790 260,683

Total net natural gas - continuing operations 402,660 367,595 354,773

Total net hydrocarbons - continuing operations including NCI 2,3

175,156 167,356 174,636

Noncontrolling interest

Net crude oil and condensate – barrels per day (7,452) (8,623) (9,962)

Net natural gas liquids – barrels per day (280) (303) (416)

Net natural gas – thousands of cubic feet per day 2

(2,468) (3,236) (3,843)

Total noncontrolling interest (8,143) (9,465) (11,019)

Total net hydrocarbons produced - continuing and discontinued operations, excluding NCI 2,3

167,013 157,891 163,617

Estimated total proved net hydrocarbon reserves - million equivalent barrels 3,4

715.4 716.9 714.9

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, 2022, 2021 and 2020, include 18.2 MMBOE, 18.4 MMBOE and 17.4 MMBOE, respectively, relating to

noncontrolling interest.

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, 2022.

(Barrels per day unless otherwise noted) 2022 2021 2020

Continuing operations

Net crude oil and condensate

United States Onshore 24,437 25,655 26,420

Gulf of Mexico 1

64,840 60,544 65,621

Canada Onshore 4,005 5,312 7,888

Offshore 3,002 3,559 4,958

Other 663 195 78

Total net crude oil and condensate - continuing operations 96,947 95,265 104,965

Net natural gas liquids

United States Onshore 5,181 5,092 5,248

Gulf of Mexico 1

4,597 4,176 4,978

Canada Onshore 903 1,117 1,315

Total net natural gas liquids - continuing operations 10,681 10,385 11,541

Net natural gas – thousands of cubic feet per day

United States Onshore 29,050 28,565 27,985

Gulf of Mexico 1

63,380 61,240 66,105

Canada Onshore 310,230 277,790 260,683

Total net natural gas - continuing operations 402,660 367,595 354,773

Total net hydrocarbons - continuing operations including NCI 2,3

174,738 166,916 175,635

Noncontrolling interest

Net crude oil and condensate – barrels per day (7,369) (8,605) (10,127)

Net natural gas liquids – barrels per day (280) (303) (416)

Net natural gas – thousands of cubic feet per day 2

(2,468) (3,236) (3,843)

Total noncontrolling interest (8,060) (9,447) (11,184)

Total net hydrocarbons sold - continuing and discontinued operations, excluding NCI 2,3

166,678 157,469 164,451

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.

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, 2022.

2022 2021 2020

(Weighted average Exploration and Production sales prices)

Continuing operations

Crude oil and condensate – dollars per barrel

United States Onshore $ 96.00 $ 66.90 $ 36.54

Gulf of Mexico 1

94.21 66.93 39.15

Onshore 89.88 61.79 32.42

Offshore 107.47 71.39 39.40

Other 94.37 69.21 63.51

Natural gas liquids – dollars per barrel

United States Onshore $ 33.85 $ 26.97 $ 11.67

Gulf of Mexico 1

36.01 29.14 10.84

Onshore 55.65 40.18 18.54

Natural gas – dollars per thousand cubic feet

United States Onshore $ 6.04 $ 3.83 $ 1.95

Gulf of Mexico 1

6.97 3.67 2.04

Onshore 2.76 2.43 1.79

1 Prices include the effect of noncontrolling interest share for MP GOM.

dollar equivalent.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Financial Condition

The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its senior unsecured revolving credit facility.

The Company’s liquidity requirements consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments and, as applicable, share repurchases.

See below for additional discussion and analysis of the Company’s cash flows.

Cash Provided by Operating Activities

Net cash provided by continuing operating activities was $2,180.2 million in 2022 compared to $1,422.2 million in 2021.

The increased cash provided by continuing operating activities of $758.0 million is primarily attributable to higher revenue from sales from production ($1,237.2 million), partially offset by higher LOE ($139.8 million), higher realized losses on derivative instruments ( $121.5 million) and the change in receivable and payable working capital balances ($65.7 million).

Higher revenues were primarily due to higher commodity prices driven by demand recovery from COVID-19 and geopolitical uncertainty and market disruption resulting from the Russia/Ukraine conflict.

Net cash provided by continuing operating activities was $619.5 million higher in 2021 than in 2020 due to higher revenue from sales from production ($1,049.5 million), the positive effect of movements on payable and receivable working capital balances ($118.5 million), lower lease operating expenses ($60.5 million) and 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;

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.

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, 2022, 2021 and 2020 were $150.0 million, $165.7 million and $191.6 million, respectively.

Lower cash interest paid in 2022 was primarily due to the early redemption of $649.7 million of the 2024 notes, 2025 notes, 2028 notes and the 2042 notes.

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.

Cash Used for Investing Activities

Net cash required by investing activities were $1,109.5 million and $417.7 million in 2022 and 2021, respectively.

In 2022, the Company acquired additional working interest in Kodiak (11.0%) and Lucius (3.4%) for $50.0 million and $78.5 million, respectively (also see Note D ).

Property additions and dry hole costs (excluding King’s Quay FPS), which include amounts expensed, were $985.5 million and $650.2 million in 2022 and 2021, respectively.

In 2021, the Company received sales proceeds for the King’s Quay FPS of $267.7 million and also acquired additional interests in the proved property Lucius for $19.9 million.

In 2020, cash used by investing activities included $113 million used to fund the development of the King’s Quay FPS.

The accrual (value of work done) basis capital expenditures were as follows:

Year Ended December 31,

(Millions of dollars) 2022 2021 2020

Capital Expenditures

Exploration and production $ 1,161.5 $ 690.1 $ 813.3

Corporate 21.7 21.1 13.3

Total capital expenditures 1,183.2 711.2 826.6

Total capital expenditures excluding proved property acquisitions 1,054.7 711.2 826.6

Total capital expenditures excluding proved property acquisitions and NCI $ 1,028.8 $ 688.2 $ 804.9

A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Year Ended December 31,

(Millions of dollars) 2022 2021 2020

Property additions and dry hole costs per cash flow statements 1

$ 985.5 $ 650.2 $ 759.8

Property additions King's Quay FPS per cash flow statements — 17.7 113.0

Geophysical and other exploration expenses 30.6 26.9 32.3

Capital expenditure accrual changes and other 38.6 (3.9) (78.5)

Acquisition of oil properties per the cash flow statements 1

Total capital expenditures $ 1,183.2 $ 711.2 $ 826.6

1 Certain prior-period amounts have been reclassified to conform to the current period presentation.

Capital expenditures in the exploration and production business in 2022 compared to 2021 have increased and is primarily attributable to expenditures related to the Kodiak and Lucius acquisitions in the Gulf of Mexico ($128.5 million), Cutthroat-1 exploration well in Brazil ($38.4 million),Tulum-1EXP exploration well in Mexico ($21.6 million), higher capital invested at the Khaleesi, Mormont, Samurai field development project in the Gulf of Mexico, higher development drilling activities in Eagle Ford Shale and Tupper Montney assets and higher expenditures related to the asset life extension at Terra Nova.

Capital expenditures in the exploration and production business in 2021 compared to 2020 have decreased as 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 $1,081.6 million in 2022 compared to $794.5 million in 2021.

In 2022, the cash required by financing activities was principally due to the early redemption of $647.7 million (excluding non cash gain of $2.0 million) of the 2024 notes, 2025 notes, 2028 notes and the 2042 notes, costs associated with early redemption ($8.3 million), distributions to noncontrolling interest ($183.0 million), dividends paid ($128.2 million) and payment of contingent consideration related to prior Gulf of Mexico acquisitions ($81.7 million).

The Company anticipates the final payments for the contingent consideration liability, related to the Gulf of Mexico acquisitions, to be paid in the first half of 2023.

See Note P for further details.

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, 2022, the Company has a $800 million senior unsecured guaranteed credit facility (RCF) with a major banking consortium, which expires in November 2027.

At December 31, 2022, the Company had no outstanding borrowings under the RCF and $57.6 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF.

If required, this provides the Company approximately $742 million availability on its RCF to fund investing activities from borrowings.

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)

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).

Working Capital

At the end of 2022, working capital (total current assets less total current liabilities, excluding assets and liabilities held for sale) amounted to a net working capital liability of $285.5 million (2021:

net working capital liability of $298.9 million).

The total working capital liability decrease of $13.4 million in 2022 is primarily attributable to higher accounts receivable, net ($133.0 million) and lower accounts payable ($79.3 million), partially offset by higher other accrued liabilities ($82.7 million), higher operating lease liabilities ($81.0 million) and lower cash and cash equivalents ($29.2 million).

Higher accounts receivable are principally due to higher

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

crude oil and natural gas pricing.

Lower accounts payable is primarily due to the decrease in unrealized losses on derivative instruments (commodity price swaps and collars) which matured at the end of 2022, partially offset by higher revenue payables principally due to higher crude oil and natural gas pricing and higher trades payable related to timing of Gulf of Mexico activities.

Higher other accrued liabilities are associated with higher short-term contingent consideration obligations (from prior Gulf of Mexico acquisitions) due to a reclassification from long-term liabilities.

Higher operating lease liabilities are associated with a rig contract to support the Khaleesi, Mormont, Samurai field development project.

Cash and cash equivalents as of December 31, 2022 totaled $492.0 million (2021:

$521.2 million).

There were no borrowings from the RCF outstanding at the end of the 2022 or 2021.

Cash and invested cash are maintained in several operating locations outside the U.S.

As of December 31, 2022, cash and cash equivalents held outside the U.S.

included U.S dollar equivalents of approximately $147.7 million (2021:

$242.9 million), the majority of which was held in Canada ($83.3 million) and Mexico ($27.7 million).

In addition, approximately $12.3 million and $6.1 million of cash was held in the U.K.

and Brazil, 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 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, 2022, long-term debt of $1,822.4 million had decreased by $643.0 million compared to December 31, 2021, as a result the early redemption, in whole or in part, of the 2024 notes, 2025 notes, 2028 notes and the 2042 notes.

The fixed-rate notes had a weighted average maturity of 7.7 years and a weighted average coupon of 6.2%.

A summary of capital employed as of December 31, 2022 and 2021 follows.

December 31, 2022 December 31, 2021

(Millions of dollars) Amount % Amount %

Capital employed

Long-term debt $ 1,822.4 26.7 % $ 2,465.4 37.2 %

Murphy shareholders' equity 4,994.8 73.3 % 4,157.3 62.8 %

Total capital employed $ 6,817.2 100.0 % $ 6,622.7 100.0 %

Murphy shareholders’ equity was $4.99 billion at the end of 2022 (2021:

$4.16 billion).

Shareholders’ equity increased in 2022 primarily due to 2022 net income ($965.0 million) and a favorable revaluation of pension assets and liabilities ($99.4 million), partially offset by dividends paid ($128.2 million) and foreign currency translation losses, net of income taxes ($106.3 million).

A summary of transactions in stockholders’ equity accounts is presented in the Consolidated Statements of Stockholders’ Equity on page 71 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 2022, compared to 2021 are discussed below.

Property, plant and equipment, net of depreciation increased $100.2 million principally due to capital expenditures in the year, partially offset by DD&A expense ($776.8 million) and foreign exchange rates applicable for our Canadian assets.

Capital expenditures are discussed above in the ‘Cash Used for Investing Activities’ section.

Murphy had commitments for capital expenditures of approximately $282.4 million at December 31, 2022 (2021:

$520.1 million).

This amount includes $103.5 million for approved expenditure for capital projects relating to non-operated interests in deepwater U.S.

Gulf of Mexico, principally at St.

Malo ($98.9 million), non-operated Canada interests, mainly offshore ($33.3 million), non-operated Eagle Ford Shale ($13.3 million) and Brunei ($1.0 million).

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Operating lease assets increased $65.0 million principally due to additions for drilling rig lease extensions, partially offset by depreciation and a decrease related to changes in foreign exchange rates applicable for our Canadian assets.

Deferred Income tax assets decreased by $267.6 million as a result of the decrease in the U.S.

net operating loss carryforward of $2.10 billion at year-end 2022, down from $2.75 billion at year-end 2021.

Deferred credits and other liabilities decreased $265.6 million primarily as a result reclassification of amounts to current, a favorable pension fair value remeasurement and cash pension contributions to the plan in 2022.

At December 31, 2022, the Company had no outstanding borrowings under the RCF and $57.6 million of outstanding letters of credit, which reduce the borrowing capacity of the RCF.

Borrowings under the RCF are subject to certain interest rates, please refer to Note G for further details.

At December 31, 2022, the interest rate in effect on borrowings under the facility would have been 6.96%.

At December 31, 2022, the Company was in compliance with all covenants related to the RCF.

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 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 10.

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 GHG, which could 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 2022 Sustainability Report issued on August 4, 2022, which is not incorporated by reference hereto.

Other Matters

Impact of inflation – In 2022, many countries worldwide continued to experience a rise in inflation, including countries where the Company operates (this follows a sustained period of relatively low inflation prior to 2021).

In the U.S., inflation continued as a result of ongoing supply constraints and increasing demand of goods and services as countries continue their recovery from the COVID-19 pandemic.

The Company’s revenues, capital and operating costs are influenced to a larger extent by specific price changes in the oil and 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.

Costs 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, since the start of 2022, higher costs for goods and services in the oil and 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

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

protected from the 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 costs.

and other industry services which could expose Murphy to the impact of higher costs.

Murphy continues to strive toward safely executing our work in an ever-increasing efficient manner to mitigate possible inflationary pressures in our business.

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.

Natural gas demand is also impacted by demand driven by lower carbon emissions 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.

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.

Critical Accounting Estimates – In preparing the Company’s consolidated financial statements in accordance with 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.

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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.

The Company often uses significantly different oil and natural gas prices 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.

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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.

It was utilized in certain undrilled acreage at distances

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

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.

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See further discussion of proved reserves and changes in proved reserves during the three years ended December 31, 2023 beginning on pages 4 and 103 of this Form 10-K report.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Property, Plant and Equipment - impairment of long-lived assets – The Company continually monitors its long-lived assets recorded in “Property, plant and equipment” in the Consolidated Balance Sheet to make sure that they are fairly presented.

The Company must evaluate its property, plant and equipment for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable from future cash flows.

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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.

Estimates of future oil and natural gas production and sales volumes are based on a combination of proved and risked probable reserves.

Although the estimation of reserves and future production is uncertain, the Company believes that its estimates are reasonable;

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Although the projected future costs are considered to be reasonable, at times, costs have been higher or lower than originally estimated.

There were no impairments recognized in 2022.

In 2021, the Company recognized pretax noncash impairment charges of $196.3 million 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.

See also Note D for further discussion of impairment charges.

There were no impairments recognized in 2023 or 2022.

Income taxes – The Company is subject to income and other similar taxes in all areas in which it operates.

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Negative evidence includes losses in recent years.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

As of December 31, 2023 the Company had a U.S.

deferred tax asset associated with net operating losses of $357.5 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

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

information which, based on currently available evidence, we believe to be reasonably likely to occur.

In reviewing the likelihood 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.

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Based on bond yields as of December 31, 2023, the Company has used a weighted average discount rate of 5.15% at year-end 2023 for the primary U.S.

This weighted average discount rate is 2.6% higher than prior year, which decreased the Company’s recorded liabilities for retirement plans compared to a year ago.

This weighted average discount rate is 0.3% lower than prior year, which increased the Company’s recorded liabilities for retirement plans compared to a year ago.

The Company assumed a return on plan assets of 8.00% 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 2023 are expected to be $6.4 million higher than 2022 primarily due to the increase in the discount rate assumption for U.S.

pension plan, which increases the amount of interest cost recognized in net periodic benefit expense.

Cash contributions to all plans are anticipated to be $6.2 million lower in 2023.

The Company’s retirement and postretirement plan (health care and life insurance benefit plans) expenses in 2024 are expected to be $0.7 million higher than in 2023 primarily due to the increase in the benefit obligations at December 31, 2023 compared to the prior year, which increases the interest cost recognized in net periodic benefit costs.

Cash contributions to all plans are anticipated to be $2.9 million higher in 2024.

In 2023, the Company paid $37.5 million into various retirement plans and $2.0 million into postretirement plans.

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Recent Accounting Pronouncements

See Note B our Consolidated Financial Statements regarding the impact or potential impact of recent accounting pronouncements upon our financial position and results of operations.

See Note B in our Consolidated Financial Statements regarding the impact or potential impact of recent accounting pronouncements upon our financial position and results of operations.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

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Total $ 6,022.8 $ 779.0 $ 610.2 $ 1,278.1 $ 3,355.5

1 Other leases refers to a finance lease in Brunei (see Note U to the financial statements).

1 Other leases refers to a finance lease in Brunei (see Note T ).

2 Capital expenditures, drilling rigs and other includes $51.6 million, $11.8 million, $11.6 million and $4.0 million, in 2024 for approved capital projects in non-operated interests in U.S.

Gulf of Mexico, Canada Offshore, U.S.

Onshore and Other Foreign Offshore, respectively.

Gulf of Mexico, U.S.

Onshore, Canada Offshore and Other Foreign Offshore, respectively.

Capital expenditures, drilling rigs and other includes $23.5 million in 2025 for approved capital projects in non-operated interests in U.S.

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Also includes $74.6 million (2024), $145.3 million (2025 - 2026), $140.2 million (2027 - 2028) and $308.1 million (After 2028) for pipeline transportation commitments in Canada.

Also includes $5.0 million (2023), $9.8 million (2024 - 2025), $9.2 million (2026 - 2027) and $25.8 million (After 2027) for long term take or pay commitments relating to gas processing in Canada.

Also includes $4.1 million (2024), $7.7 million (2025 - 2026), $7.7 million (2027 - 2028) and $22.5 million (After 2028) for long term take or pay commitments relating to natural gas processing in Canada.

3 Other long-term liabilities, including debt interest, includes future cash outflows for asset retirement obligations.

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Material off-balance sheet arrangements – Certain U.S.

transportation contracts require minimum monthly payments through 2045, while onshore Canada processing contracts call for minimum monthly payments through 2051.

transportation contracts require minimum monthly payments through 2045, while Onshore Canada transportation and 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.

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

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 23, 2023, the NYMEX WTI forward curve price for the remainder of 2023 and 2024 were $75.05 and $71.85 per barrel, respectively;

however we cannot predict what impact economic factors (including inflation, the Russia/Ukraine conflict and the COVID-19 pandemic) may have on future commodity pricing.

The oil and gas industry is impacted by global commodity pricing and as a result the prices for the Company’s primary products are often volatile a nd are aff ected by the levels of supply and demand for energy.

As discussed in the Results of Operations section discussing revenues, on page 37 , lower average crude oil price during in 2023 directly impacted the Company’s product sales revenue.

As of close on February 21, 2024, forward price curves for existing forward contracts for the remainder of 2024 and 2025 are shown in the table below:

NYMEX ($/MMBTU)

AECO (US$ Equivalent/MCF)

In 2023, liquids from continuing operations represented approximately 60% of total hydrocarbons produced on an energy equivalent basis.

In 2024, the Company’s ratio of hydrocarbon production represented by liquids is expected to be 59%.

If the prices for crude oil and natural gas are lower in 2024 or beyond, this will have an unfavorable impact on the Company’s operating profits;

likewise, if prices are higher, this will have a favorable impact.

The Company, from time to time, may choose to use a variety of commodity hedge instruments to reduce commodity price risk, including forward sale fixed financial swaps and long-term fixed-price physical commodity sales.

The Company currently expects average daily production in 2024 to be between 187,100 and 195,100 barrels of oil equivalent per day (including noncontrolling interest of 7,100 BOEPD).

If significant price declines occur, the Company will review the option of production curtailments to avoid incurring losses on certain produced barrels.

Similar to the overall inflation and higher interest rates in the wider economy, the oil and gas industry and the Company are observing higher costs for goods and services used in E&P operations.

Murphy continues to manage input costs through its dedicated procurement department focused on managing supply chain and other costs to deliver cash flow from operations.

We cannot predict what impact economic factors (including, but not limited to, inflation, global conflicts and possible economic recession) 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 2023 is expected to be between $875 million and $1025 million, excluding the amount attributable to noncontrolling interest.

The Company’s capital expenditure spend for 2024 is expected to be between $920 million and $1,020 million, excluding 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.

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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 2023 to be between 182,700 and 190,700 barrels of oil equivalent per day (including noncontrolling interest of 7,200 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, dividends or payment to noncontrolling interests) in accordance with the Company’s capital allocation framework.

The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests), in accordance with the Company’s capital allocation framework designed to allow for additional shareholder returns and debt reduction.

Details of the framework can be found in the “Capital Allocation Framework” section of the Company’s Form 8-K filed on August 4, 2022.

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 ).

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:

During 2023, the Board authorized a $300 million increase to the original share repurchase program announced in the Capital Allocation Framework, bringing the total amount allowed to be repurchased under the program to $600 million.

As of December 31, 2023, the Company has $450 million remaining available to repurchase.

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 F ).

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

As of February 21, 2024, the Company has entered into forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:

(MMcf/d) Price/MCF Remaining Period

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Canada Natural Gas Fixed price forward sales 162 C$2.39 1/1/2024 12/31/2024

Canada Natural Gas Fixed price forward sales 250 C$2.35 4/1/2023 12/31/2023

Canada Natural Gas Fixed price forward sales 162 C$2.39 1/1/2024 12/31/2024

Canada Natural Gas Fixed price forward sales 25 US$1.98 1/1/2024 10/31/2024

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These statements, which express management’s current views concerning future events, results and plans, are subject to inherent risks, uncertainties and assumptions (many of which are beyond our control) and are not guarantees of performance.

In particular, statements, express or implied, concerning the Company’s future operating results or activities and returns or the Company's ability and decisions to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other ESG matters, or pay and/or increase dividends or make share repurchases and other capital allocation decisions, are all forward-

Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

looking statements.

In particular, statements, express or implied, concerning the Company’s future operating results or activities and returns or the Company's ability and decisions to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and expenditures, generate cash flows, pay down or refinance indebtedness, achieve, reach or otherwise meet initiatives, plans, goals, ambitions or targets with respect to emissions, safety matters or other ESG (environmental/social/governance) matters, make capital expenditures or pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements.

Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, 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;

geopolitical concerns;

increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves;

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or adverse developments in the U.S.

or global capital markets, credit markets or economies in general.

or global capital markets, credit markets, banking system or economies in general, including inflation.

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, except as required by law.

Investors and others should note that we may announce material information using SEC filings, press releases, public conference calls, webcasts and the investors page of our website.

We may use these channels to distribute material information about the Company;

therefore, we encourage investors, the media, business partners and others interested in the Company to review the information we post on our website.

The information on our website is not part of, and is not incorporated into, this report.

Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statements.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis