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Item 7. Management’s Discussion and Analysis

2023-02-27 compared with 2022-02-25 · 193 added, 247 removed, 357 unchanged (55% of the section changed)

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

Exploration and Production (Contd.)

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.

1 unchanged sentence

$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.

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 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.

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 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.

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).

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.

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:

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.

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.

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

6 unchanged sentences

Severance and ad valorem taxes 4.27 2.91 2.06

Depreciation, depletion and amortization (DD&A) expense 27.59 26.22 24.19

DD&A expense 25.61 27.59 26.22

United States – Gulf of Mexico 1

9 unchanged sentences

DD&A expense 12.25 12.80 12.01

Total oil and natural gas continuing operations

Total E&P continuing operations

Lease operating expense $ 10.65 $ 8.86 $ 9.34

1 unchanged sentence

DD&A expense 12.18 13.05 15.36

Total oil and natural gas continuing operations – excluding noncontrolling interest

Total oil and natural gas continuing operations –

excluding noncontrolling interest

Lease operating expense

2 unchanged sentences

DD&A expense 12.30 13.23 15.49

Discontinued Operations

Lease operating expense — — 16.49

DD&A expense — — 4.60

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 $547.7 million unfavorable variance is principally due to higher net losses on derivative instruments in 2021 compared to the 2020 period (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;

$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).

$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.

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.

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).

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;

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 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.

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 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 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.

1 unchanged sentence

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 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.

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.

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.

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 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.

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.

1 unchanged sentence

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 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.

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

30 unchanged sentences

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

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

Total discontinued operations — — 21,000

Total net hydrocarbons produced excluding NCI 2,3

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

167,013 157,891 163,617

Estimated net hydrocarbon reserves - million equivalent barrels 3,4

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

715.4 716.9 714.9

2 unchanged sentences

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.

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

30 unchanged sentences

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

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

Total discontinued operations — — 20,856

Total net hydrocarbons sold excluding NCI 2,3

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

166,678 157,469 164,451

4 unchanged sentences

The following table contains the weighted average sales prices excluding transportation cost deduction for the three years ended December 31, 2022.

Comparative periods are conformed to current presentation.

2022 2021 2020

18 unchanged sentences

Onshore 2.76 2.43 1.79

Discontinued operations

Crude oil and condensate – dollars per barrel

Sarawak — — 70.39

Block K — — 65.75

Natural gas liquids – dollars per barrel

Sarawak — — 48.23

Natural gas – dollars per thousand cubic feet

Sarawak — — 3.60

Block K — — 0.24

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

dollar equivalent.

3 Prices are net of payments under the terms of the respective production sharing contracts.

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 $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:

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;

1 unchanged sentence

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, 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.

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:

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,

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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

Financial Condition (Contd.)

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

Year Ended December 31,

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Property additions and dry hole costs per cash flow statements 1

Property additions King's Quay per cash flow statements 17.7 113.0 100.2

$ 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

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Total capital expenditures $ 1,183.2 $ 711.2 $ 826.6

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.

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 $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).

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, 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.

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 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

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net working capital liability of $298.9 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.

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 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.

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

Financial Condition (Contd.)

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.

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

$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.

$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.

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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.

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, 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.

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%.

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$4.16 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).

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.

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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 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.

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.

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 $282.4 million at December 31, 2022 (2021:

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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.

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

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.

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 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%.

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.

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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.

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.

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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 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.

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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.

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;

• Including processes to stress-test our GHG emissions under various portfolio scenarios.

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

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;

• 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).

(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.

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.

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.

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 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 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.

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.

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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.

Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data (including hydrocarbon prices, operating costs, and development costs), 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.

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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.

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.

A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events.

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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.

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.

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.

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.

See also Note D 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.

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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.

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Negative evidence includes losses in recent years.

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

Critical Accounting Estimates (Contd.)

As of December 31, 2022 the Company had a U.S.

deferred tax asset associated with net operating losses of $442.7 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.

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.

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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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.

The Company presently assumes a return on plan assets of 5.25% for the primary U.S.

The Company assumed a return on plan assets of 6.60% 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.

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.

In 2022, the Company paid $41.1 million into various retirement plans and $2.1 million into postretirement plans.

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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.

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.

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

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Total $ 6,841.1 $ 948.6 $ 1,180.8 $ 1,248.2 $ 3,463.5

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

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

2 Capital expenditures, drilling rigs and other includes $67.6 million, $33.3 million, $13.3 million and $1.1 million, in 2023 for approved capital projects in non-operated interests in U.S.

Gulf of Mexico, Canada Offshore, Other Foreign Offshore, and U.S.

Onshore, respectively.

Gulf of Mexico, Canada Offshore, U.S.

Onshore and Other Foreign Offshore, respectively.

Capital expenditures, drilling rigs and other includes $35.9 million in 2024 for approved capital projects in non-operated interests in U.S.

Gulf of Mexico.

Also includes $66.5 million (2023), $105.5 million (2024 - 2025), $87.5 million (2026 - 2027) and $183.7 million (After 2027) for pipeline transportation commitments in Canada.

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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 has entered into agreements to lease production facilities for various producing oil fields as well as other arrangements that require 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.

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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.

transportation contracts require minimum monthly payments through 2045, while onshore 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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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 the ongoing COVID-19 pandemic and OPEC+ decisions) may have on future commodity pricing.

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.

Lower prices, should they occur, will result in lower profits and operating cash-flows.

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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 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.

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:

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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

(Bbl/d) Average

(USD/Bbl) Average

(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

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

Canada Natural Gas Fixed price forward sales 269 C$2.36 1/1/2023 3/31/2023

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 1/1/2023 10/31/2024

Canada Natural Gas Fixed price forward sales 15 US$1.98 11/1/2024 12/31/2024

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.

This Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995.

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:

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.

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;

12 unchanged sentences

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.

Murphy undertakes no duty to publicly update or revise any forward-looking statements, except as required by law.

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