What changed in this filing

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Item 2. Management’s Discussion and Analysis

2023-05-03 compared with 2022-11-03 · 108 added, 191 removed, 116 unchanged (72% of the section changed)

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (contd.)

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Results of Operations (Continued)

Exploration and Production

Third quarter 2022 vs.

All amounts include amount attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM), unless otherwise noted.

United States E&P operations reported earnings of $481.5 million in the third quarter of 2022 compared to income of $168.1 million in the third quarter of 2021.

Results were $313.4 million favorable in the 2022 quarter compared to the 2021 period primarily due to higher revenues ($408.6 million), lower exploration expenses ($17.1 million) and other operating expense ($66.8 million), partially offset by higher lease operating expenses ($62.1 million), higher depreciation, depletion and amortization (DD&A, $22.4 million) and higher income tax expense ($82.3 million).

Higher revenues were primarily due to higher commodity prices, higher production volumes from the Khaleesi and Mormont fields and lower weather related downtime.

Lower exploration expenses are due to no repeat of 2021 dry hole costs related to Silverback.

Lower other operating expense is primarily due to favorable mark to market revaluations on contingent consideration (as a result of commodity prices) related to prior Gulf of Mexico (GOM) acquisitions.

Higher lease operating expense is due to higher production volumes, cost increases from inflationary pressures related to the onshore business, and higher production at the Khaleesi and Mormont assets flowing to the King’s Quay facility.

Higher DD&A is a result of higher production volumes, partially offset by lower rates driven by positive reserve revisions primarily in the Eagle Ford Shale.

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

Canadian E&P operations reported earnings of $41.4 million in the third quarter 2022 compared to income of $73.9 million in the third quarter of 2021.

Results were unfavorable $32.5 million compared to the 2021 period primarily due to a credit of $71.8 million reported in 2021 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.

The current year results also include higher revenues from production ($39.5 million), partially offset by higher lease operating expenses ($6.2 million) and higher tax expense ($9.9 million).

Higher revenue is primarily attributable to higher oil and gas prices and higher natural gas volumes at Tupper Montney.

Higher lease operating expenses is primarily the result of higher volumes and related gas processing costs.

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

Other international E&P operations reported a loss from continuing operations of $5.8 million in the third quarter of 2022 compared to a loss of $5.2 million in the third quarter of 2021.

The result was $0.6 million unfavorable in the 2022 period versus 2021 primarily due to higher exploration expenses and higher taxes partially offset by higher revenue from Brunei.

Nine months 2022 vs.

First quarter 2023 vs.

All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.

United States E&P operations reported earnings of $1,225.9 million in the first nine months of 2022 compared to earnings of $481.8 million in the first nine months of 2021.

Results were $744.1 million favorable in the 2022 period compared to the 2021 period, driven by higher revenues ($954.6 million) and lower DD&A ($27.0 million), other operating expense ($23.1 million) and exploration expenses ($16.9 million) partially offset by higher income tax expense ($188.4 million), lease operating expenses ($64.9 million) and severance and ad valorem taxes ($15.8 million).

Higher revenues are primarily attributable to higher realized prices in 2022 compared to 2021.

Lower DD&A is a result of lower rates driven by positive reserve revisions primarily in the Eagle Ford Shale.

Lower other operating expenses is primarily due to a lower unfavorable mark to market revaluation on contingent consideration ($98.5 million;

as a result of commodity prices increasing less drastically) from prior GOM acquisitions and no repeat of rig standby charges.

Lower exploration expenses are due to no repeat of 2021 dry hole costs related to Silverback.

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

Higher lease operating expenses relate to higher production volumes, cost increases from inflationary pressures related to the onshore business, and higher production at the Khaleesi and Mormont assets flowing to the King’s Quay facility.

Higher severance and ad valorem taxes are due to higher revenues at Eagle Ford Shale.

Canadian E&P operations reported earnings of $111.3 million in the first nine months of 2022 compared to a loss of $37.7 million in the first nine months of 2021.

Results were $149.0 million favorable compared to the 2021 period.

Prior year results included an impairment charge ($171.3 million) recorded in the first quarter following an asset abandonment notice from the operator of 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.

The current year results also include higher revenue from production ($101.0 million) and lower DD&A ($17.3 million) offset by higher income tax expense ($52.7 million) and lease operating expenses ($13.4 million).

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

Lower DD&A is primarily due to lower production volumes at Kaybob Duvernay due to normal well decline.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (contd.)

Higher income tax expense is a result of higher pre-tax income principally due to higher revenue and no repeat of the impairment charge.

Higher lease operating expenses are due to higher gas volumes and higher processing rates.

Other international E&P operations reported a loss of $53.5 million in the first nine months of 2022 compared to a loss of $22.5 million in the prior year.

Results were $31.0 million unfavorable compared to the 2021 period primarily due to the Cutthroat-1 exploration well in block SEAL-M-428 in the Sergipe-Alagoas Basin offshore Brazil being expensed because no hydrocarbons were discovered.

Third quarter 2022 vs.

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported income of $57.4 million in the third quarter of 2022 compared to a loss of $98.8 million in the third quarter of 2021.

The $156.2 million favorable variance is principally due to current period gains on derivative instruments in the third quarter of 2022 compared to losses in the same 2021 period (2022:

$115.2 million gain;

$59.2 million loss) for a favorable variance of $174.4 million.

In addition, favorable variances were recorded due to lower interest expense ($10.9 million) and favorable exchange rate gains ($18.3 million) partially offset by higher tax expense ($47.1 million).

Realized and unrealized gains on derivative instruments are due to a decrease in oil prices for current (realized) and/or future (unrealized) 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.

As of September 30, 2022, the average forward NYMEX WTI price for the remainder of 2022 was $79.11 (versus swap contract fixed hedge price of $44.88).

Interest charges are lower in the third quarter of 2022 due to lower overall debt in the period.

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

Nine months 2022 vs.

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/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 $363.7 million in the first nine months of 2022 compared to a loss of $577.6 million in the first nine months of 2021.

The $213.9 million favorable variance is primarily due to lower losses on derivative instruments in 2022 ($191.1 million) compared to 2021 (2022:

$308.7 million loss;

$499.8 million loss), lower interest expense ($62.4 million) and foreign exchange gains ($31.0 million), partially offset by lower tax benefits ($66.6 million).

Interest charges are lower in the first nine months of 2022 primarily due to lower overall debt and lower debt redemption premiums ($5.4 million in 2022;

$36.8 million in 2021) incurred by the Company in the period.

In the first nine months of 2022 the Company reduced debt by $447.6 million compared to the 2021 reduction of $726.4 million.

Realized and unrealized losses on derivative instruments are due to an increase in oil prices for current (realized) and future (unrealized) 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.

As of September 30, 2022, the average forward NYMEX WTI price for the remainder of 2022 was $79.11 (versus swap contract fixed hedge price of $44.88).

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

E&P operations reported earnings of $226.0 million in the first quarter of 2023 compared to earnings of $252.9 million in the first quarter of 2022.

Results were $26.9 million unfavorable in the 2023 period compared to the 2022 period primarily due to lower revenues ($25.1 million), higher lease operating expenses ($62.7 million) and higher depreciation, depletion and amortization expense (DD&A) ($33.8 million), partially offset by lower other operating expense ($93.4 million).

Lower revenues were primarily due to lower realized prices, partially offset by higher sales volumes from the Gulf of Mexico primarily related to new wells from the Khaleesi, Mormont and Samurai development project.

Higher lease operating expenses were primarily due to increased production volumes and additional costs associated with workover and maintenance from the Gulf of Mexico operations.

Higher DD&A was primarily the result of higher production volumes from the Gulf of Mexico, partially offset by lower volumes at Eagle Ford Shale.

Lower other operating expense was due to a lower unfavorable contingent consideration adjustment of $3.9 million in 2023 (2022:

$98.1 million) as a result of meeting contractual thresholds or reaching time limitations that ended in 2022 (see N ote K) .

Canadian E&P operations reported earnings of $21.9 million in the first quarter of 2023 compared to earnings of $22.7 million in the first quarter of 2022.

Results were unfavorable $0.8 million compared to the 2022 period primarily due to lower revenues ($10.3 million), partially offset by lower selling and general expense (G&A) ($2.8 million) and lower DD&A ($2.6 million).

Lower revenues were due to lower pricing and sales volumes at Kaybob Duvernay and Hibernia, partially offset by higher natural gas production volumes and pricing at Tupper Montney.

Lower G&A was primarily due to lower incentive expenses in the current year.

Lower DD&A was the result of lower production volumes at Kaybob Duvernay, partially offset by higher production volumes at Tupper Montney.

Other international E&P operations reported a loss from continuing operations of $5.2 million in the first quarter of 2023 compared to a loss of $44.2 million in the first quarter of 2022.

The result was $39.0 million favorable in the 2023 period versus the 2022 period primarily due to lower exploration expenses ($34.5 million) mainly resulting from lower dry hole costs in the current period and higher revenues from Brunei ($3.6 million).

First quarter 2023 vs.

Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/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 $28.7 million in the first quarter of 2023 compared to a loss of $296.3 million in same period of 2022.

The $267.6 million favorable variance was principally due to no current period losses on derivative instruments in the first quarter of 2023 compared to a loss for the same period in 2022 of $320.8 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.

During the first quarter of 2023 and as of March 31, 2023, the Company did not enter into or have any fixed price derivative swaps or collar contracts outstanding.

Favorable variances were also recorded due to lower interest expense resulting from overall lower debt levels ($8.4 million) and favorable G&A primarily due to lower current period incentive related expenses ($8.4 million), partially offset by lower income tax benefit ($72.0 million).

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

Production Volumes and Prices

Third quarter 2022 vs.

Total hydrocarbon production from continuing operations averaged 196,243 barrels of oil equivalent per day in the third quarter of 2022, which was 20% higher than the 163,224 barrels per day produced in third quarter 2021.

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

Average crude oil and condensate production from continuing operations was 103,386 barrels per day in the third quarter of 2022 compared to 88,245 barrels per day in the third quarter of 2021.

The increase of 15,141 barrels per day was associated with higher volumes in the Gulf of Mexico (15,304 barrels per day) principally due to the increased production from the Khaleesi, Mormont, Samurai development as well as lower weather related downtime in the third quarter of 2022.

Canada production is lower (2,680 barrels per day) primarily attributable to Kaybob Duvernay well decline and planned downtime at Hibernia.

Eagle Ford Shale production is higher (2,329 barrels per day) due to new wells at Karnes and Catarina.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $93.56 per barrel in the third quarter 2022 compared to $68.88 per barrel in the 2021 period, an increase of 36% quarter over quarter.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (contd.)

Total production of natural gas liquids (NGL) from continuing operations was 11,548 barrels per day in the third quarter 2022 compared to 10,391 barrels per day in the 2021 period.

The increase of 1,157 barrels per day was associated with higher volumes in the Gulf of Mexico principally due to the increased production from the Khaleesi, Mormont, Samurai development as well as lower weather related downtime in the third quarter of 2022.

First quarter 2023 vs.

Total hydrocarbon production from continuing operations averaged 179,745 barrels of oil equivalent per day in the first quarter of 2023, which was 20% higher than the 149,854 barrels per day produced in first quarter of 2022.

The increase in production was principally due to increased production from the Gulf of Mexico primarily attributable to the Khaleesi, Mormont and Samurai field development project starting production in Q2 2022 as well as higher production from Canada Onshore, related primarily to new wells at Tupper Montney.

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Results of Operations (Continued)

Average crude oil and condensate production from continuing operations was 100,987 barrels per day in the first quarter of 2023 compared to 83,560 barrels per day in the first quarter of 2022.

The increase of 17,427 barrels per day was associated with higher volumes in the Gulf of Mexico (20,446 barrels per day) principally due to production from the Khaleesi, Mormont, Samurai field development project, that started production in the second quarter of 2022.

In addition, Canada production was lower (1,959 barrels per day) primarily attributable to Kaybob Duvernay well decline and lower production volumes at Hibernia, due to higher operational downtime.

Eagle Ford Shale production was lower (1,053 barrels per day) due to normal well decline primarily at Tilden.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $73.80 per barrel in the first quarter of 2023 compared to $95.17 per barrel in the same period of 2022 period, representing a decrease of 22%.

Total production of natural gas liquids (NGL) from continuing operations was 11,325 barrels per day in the first quarter of 2023 compared to 9,342 barrels per day in the first quarter of 2022.

The increase of 1,983 barrels per day was associated with higher volumes in the Gulf of Mexico principally due to production from the Khaleesi, Mormont, Samurai field development project that had not yet started producing in the first quarter of 2022.

The average sales price for U.S.

NGL was $35.37 per barrel in the 2022 quarter compared to $32.01 per barrel in 2021.

The average sales price for NGL in Canada was $54.40 per barrel in the 2022 quarter compared to $45.12 per barrel in 2021.

NGL was $24.23 per barrel in the first quarter of 2023 compared to $40.76 per barrel in the same period of 2022.

The average sales price for NGL in Canada was $46.59 per barrel in the first quarter of 2023 compared to $55.02 per barrel in the same period of 2022.

NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets.

Natural gas production volumes from continuing operations averaged 487.9 million cubic feet per day (MMCFD) in the third quarter 2022 compared to 387.5 MMCFD in 2021.

Natural gas production volumes from continuing operations averaged 404.6 million cubic feet per day (MMCFD) in the first quarter of 2023 compared to 341.7 MMCFD in the first quarter 2022.

The increase of 62.9 MMCFD was a result of higher volumes in Canada (46.9 MMCFD) as well as higher volumes in the Gulf of Mexico (19.1 MMCFD).

Higher natural gas volumes in Canada are primarily due to bringing online 20 new wells at Tupper Montney since the second quarter of 2022.

Natural gas prices for the total Company averaged $3.84 per thousand cubic feet (MCF) in the 2022 quarter, versus $2.78 per MCF average in the same quarter of 2021.

Higher natural gas volumes in Canada are primarily due to bringing online 25 new wells at Tupper Montney since the first quarter of 2022, partially offset by normalized royalty rates in the first quarter of 2023.

Royalty rates in the first quarter of 2022 were lower due to royalty infrastructure credits received.

The higher natural gas volumes in the Gulf of Mexico primarily related to increased production from the Khaleesi, Mormont, Samurai field development project as production began during the second quarter of 2022.

Natural gas prices for the total Company averaged $2.68 per thousand cubic feet (MCF) in the first quarter of 2023, versus $3.13 per MCF average in the same period of 2022.

Average natural gas prices in the U.S.

and Canada in the quarter were $8.34 and $2.75 per MCF, respectively.

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

Nine months 2022 vs.

Total hydrocarbon production from Exploration and Production averaged 173,260 barrels of oil equivalent per day in the first nine months of 2022, which represented a 1.8% increase from the 170,209 barrels per day produced in the first nine months of 2021.

The increase is principally due to production from 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 was 95,275 barrels per day in the first nine months of 2022 compared to 98,314 barrels per day in the first nine months of 2021.

The decrease of 3,039 barrels per day was principally due to normal declines partially offset by new production from the Khaleesi, Mormont, Samurai field development project.

In addition, Canada production is lower (2,517 barrels per day) due to normal field decline at Kaybob and temporary operational issues at Hibernia.

Eagle Ford Shale production is lower (1,470 barrels per day) due to normal well decline partially offset by 2022 new well production.

Higher Gulf of Mexico production (475 barrels per day) due to production from the Khaleesi, Mormont, Samurai field development project that started production in the second quarter of 2022, and lower weather related downtime in 2022 partially offset by normal declines.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $99.38 per barrel in the first nine months of 2022 compared to $64.19 per barrel in the 2021 period, an increase of 54.8% year over year.

Total production of natural gas liquids (NGL) was 10,621 barrels per day in the first nine months of 2022 compared to 10,498 barrels per day in the 2021 period.

The average sales price for U.S.

NGL was $38.30 per barrel in 2022 compared to $25.63 per barrel in 2021.

The average sales price for NGL in Canada was $57.53 per barrel in 2022 compared to $37.05 per barrel in 2021.

NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets.

Natural gas production volumes averaged 404.2 million cubic feet per day (MMCFD) in the first nine months of 2022 compared to 368.4 MMCFD in 2021.

The increase of 35.8 MMCFD was primarily the result of higher volumes in Canada 36.3 MMCFD) and Eagle Ford Shale (1.3 MMCFD), partially offset by the Gulf of Mexico (1.8 MMCFD).

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

Natural gas prices for the total Company averaged $3.66 per thousand cubic feet (MCF) in the first nine months of 2022, versus $2.56 per MCF average in the same period of 2021.

Average realized natural gas prices in the U.S.

and Canada in the quarter were $7.00 per MCF and $2.70 per MCF, respectively.

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

Additional details about results of oil and natural gas operations are presented in the tables on pages 25 and 26.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (contd.)

The following table reports hydrocarbons produced during the three-month and nine-month periods ended September 30, 2022 and 2021.

and in Canada for the first quarters of 2023 and 2022 were $3.08 and $2.55 per MCF, respectively.

Additional details about results of oil and natural gas operations are presented in the tables on page 25 .

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Results of Operations (Continued)

The following table contains hydrocarbons produced during the three-month periods ended March 31, 2023 and 2022.

Three Months Ended

September 30, Nine Months Ended

September 30,

(Barrels per day unless otherwise noted) 2023 2022

10 unchanged sentences

Gulf of Mexico 1

4,780 3,459 4,411 4,296

Canada Onshore 826 983

12 unchanged sentences

Net natural gas – thousands of cubic feet per day (2,354) (2,590)

(2,202) (2,331) (2,628) (3,498)

Total noncontrolling interest 3

(7,237) (8,847)

Total net hydrocarbons - continuing operations excluding NCI 2,3

3 unchanged sentences

3 NCI – noncontrolling interest in MP GOM.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (contd.)

The following table reports the weighted average sales prices excluding transportation cost deductions and sales of purchased natural gas for the three-month and nine-month periods ended September 30, 2022 and 2021.

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Results of Operations (Continued)

The following table contains the weighted average sales prices excluding transportation cost deduction for the three-month periods ended March 31, 2023 and 2022.

Three Months Ended

September 30, Nine Months Ended

September 30,

2022 2021 2022 2021

(Weighted average Exploration and Production sales prices)

3 unchanged sentences

Gulf of Mexico 1

92.96 68.93 99.04 64.44

Onshore 74.29 93.09

4 unchanged sentences

Gulf of Mexico 1

36.56 34.71 39.99 27.17

Onshore 46.59 55.02

2 unchanged sentences

Gulf of Mexico 1

8.68 4.09 7.23 3.28

Onshore 2.55 2.52

6 unchanged sentences

Cash Provided by Operating Activities

Net cash provided by continuing operating activities was $1,678.7 million for the first nine months of 2022 compared to $1,091.3 million during the same period in 2021.

The increased cash from operating activities of $587.4 million is primarily attributable to higher revenue from production ($1,062.8 million), offset by the timing of working capital settlements ($177.2 million;

primarily higher revenue received in cash following the end of the quarter), offset by higher realized losses on derivative instruments ($176.1 million).

Net cash provided by continuing operating activities was $279.8 million for the three months ended March 31, 2023 compared to $338.3 million during the same period in 2022.

The decreased cash from operating activities of $58.5 million was primarily attributable to payments of contingent consideration related to prior Gulf of Mexico acquisition in the first quarter of 2023 ($124.0 million), lower revenue from production ($38.3 million), and higher lease operating expenses ($63.2 million), offset by lower realized losses on derivative instruments ($132.3 million), lower G&A ($15.2 million) and the timing of working capital settlements ($5.9 million).

Payments of contingent consideration are shown both in operating activities and financing activities in the Company’s Consolidated Statement of Cash Flows;

amounts considered as financing activities are those amounts paid up to the original estimated contingent consideration liability included in the purchase price allocation, at the time of acquisition.

Any contingent consideration paid above the original estimated liability, included in the purchase price, are considered operating activities.

During the three months ended March 31, 2023, the Company paid a total of $171.7 million in contingent consideration, of which $124.0 million is shown in operating activities and $47.7 million is shown in financing activities.

The remaining $25.0 million contingent consideration liability balance as of March 31, 2023, was paid in April 2023.

Cash Required by Investing Activities

Net cash required by investing activities was $928.6 million for the first nine months of 2022 compared to $311.9 million during the same period in 2021.

In the first nine months of 2022, the Company acquired additional working interest in Kodiak (11.0%) and Lucius (3.4%) for $48.5 million and $77.1 million, respectively (also see Note D).

Property additions and dry hole costs (excluding King’s Quay), which include amounts expensed, were $800.9 million and $541.3 million in the first nine months of 2022 and 2021, respectively.

The first quarter of 2021 included sales proceeds for the King’s Quay FPS of $267.7 million, which was sold to ArcLight.

MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)

Financial Condition (contd.)

Net cash required by investing activities, including amount expensed, was $345.3 million for the three months ended March 31, 2023 compared to $244.9 million during the same period in 2022.

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Financial Condition (Continued)

Total accrual basis capital expenditures are shown below.

Nine Months Ended

September 30,

Three Months Ended

(Millions of dollars) 2023 2022

4 unchanged sentences

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

Nine Months Ended

September 30,

Three Months Ended

(Millions of dollars) 2023 2022

Property additions and dry hole costs per cash flow statements $ 345.3 $ 244.9

$ 800.9 541.3

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

Acquisition of oil and gas properties 1

Geophysical and other exploration expenses 4.9 9.4

1 unchanged sentence

Total capital expenditures $ 336.0 $ 304.7

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

The increase in capital expenditures in the exploration and production business in 2022 compared to 2021 is primarily attributable to expenditures related to the Kodiak and Lucius acquisition in Gulf of Mexi co ($125.6 million), Cutthroat-1 exploration well in Brazil ($25.3 million), higher capital invested at the Khaleesi, Mormont, Samurai field development project in 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.

The increase in capital expenditures in the exploration and production business in three months ended March 31, 2023 compared to the same period in 2022 was primarily attributable to development drilling activities at Eagle Ford Shale assets, development drilling at Samurai and St.

Malo fields and Oso exploration drilling at Other Offshore.

In the first quarter of 2023, drilling of the Oso well was temporarily suspended prior to reaching the objective.

The Company plans to return to the well in the third quarter of 2023.

Cash Required by Financing Activities

Net cash required by financing activities was $785.6 million for the first nine months of 2022 compared to $585.6 million during the same period in 2021.

In 2022, the cash used in financing activities was principally for the early redemption of the notes due 2024, 2025, 2028 and 2042 ($446.0 million), payment of contingent consideration related to prior Gulf of Mexico acquisitions ($81.7 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($145.3 million), and cash dividends to shareholders of $0.575 per share ($89.4 million).

Net cash required by financing activities was $114.7 million for the three months ended March 31, 2023 compared to $133.9 million during the same period in 2022.

In 2023, the cash used in financing activities was principally for the payment of contingent consideration related to prior Gulf of Mexico acquisitions ($47.7 million) as discussed the “Cash Required by Operating Activities” section, cash dividends to shareholders of $0.275 per share ($42.9 million) and distributions to the non-controlling interest in the Gulf of Mexico ($9.7 million).

Subsequent to quarter end, the Company declared a quarterly cash dividend of $0.275 per share, or $1.10 per share on an annualized basis.

As of September 30, 2022 and in the eve nt it is required to fund investing activities from borrowings, the Company has $1,546.1 million available on its committed RCF.

In first nine months of 2021, the cash used in financing activities was principally for the early redemption of the notes due 2022 and 2024 ($726.4 million ), early redemption cost (make whole payment) of the notes due 2022 ($36.8 million), repayment of the previously outstanding balance on the Company’s unsecured RCF ($200.0 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($100.9 million), and cash dividends to shareholders ($57.9 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($541.9 million).

As of March 31, 2023 and in the event it is required to fund investing activities from borrowings, the Company has $769.7 million available on its committed RCF.

Working Capital

Working capital (total current assets less total current liabilities, excluding assets and liabilities held for sale) as of September 30, 2022 was a deficit of $268.5 million, $30.4 million lower than December 31, 2021, with the decrease primarily attributable to higher accounts receivable ($127.0 million) and lower accounts payable ($83.6 million), partially offset by higher other accrued liabilities ($74.9 million), a lower cash balance ($55.2 million) and higher operating lease liabilities ($27.5 million).

Higher accounts receivable are principally due to higher crude oil and gas pricing.

Lower accounts payable is primarily due to the decrease in unrealized losses on derivative instruments (commodity price swaps and collars) maturing (payable) over the

MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.)

Financial Condition (contd.)

remainder of 2022 partially offset by higher revenue payables principally due to higher crude oil and gas pricing.

Higher other accrued liabilities are associated with higher short term contingent consideration obligations (from prior Gulf of Mexico acquisitions), due to higher commodity prices and timing of payments.

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

As of March 31, 2023, working capital (total current assets less total current liabilities) amounted to a net working capital liability of $226.2 million, $59.3 million lower than December 31, 2022, with the favorable decrease primarily attributable to lower other accrued liabilities ($225.5 million) and lower accounts payable ($26.9 million), partially offset by a lower cash balance ($179.6 million) and higher operating lease liabilities ($19.0 million).

Lower accrued liabilities are primarily due to payments made for contingent consideration obligation from prior Gulf of Mexico acquisitions and incentive payments made in the first quarter of 2023.

Lower accounts payable was primarily due to the decrease in unrealized losses on derivative instruments (commodity price swaps and collars), as there were no commodity derivative instrument contracts outstanding during the first quarter of 2023.

Higher current operating lease liabilities are associated with scheduled rate increases for a drilling vessel resulting in additional amounts being reclassified from long-term to current operating lease liabilities.

Capital Employed

At September 30, 2022, long-term debt of $2,023.0 million had decreased by $442.4 million compared to December 31, 2021, primarily as a result of the partial repayment of notes due 2024, 2025, 2028 and 2042 ($447.6 million).

At March 31, 2023, long-term debt of $1,823.0 million had increased by $0.5 million compared to December 31, 2022, primarily as a result of normal debt issuance cost amortization.

The total of the fixed-rate notes had a weighted average maturity of 7.5 years and a weighted average coupon of 6.2%.

A summary of capital employed at September 30, 2022 and December 31, 2021 follows.

September 30, 2022 December 31, 2021

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Financial Condition (Continued)

A summary of capital employed at March 31, 2023 and December 31, 2022 follows.

March 31, 2023 December 31, 2022

(Millions of dollars) Amount % Amount %

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Total capital employed $ 6,960.5 100.0 % $ 6,817.2 100.0 %

Cash and invested cash are maintained in several operating locations outside the United States.

As of September 30, 2022, Cash and cash equivalents held outside the U.S.

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

As of March 31, 2023, cash and cash equivalents held outside the U.S.

included U.S.

dollar equivalents of approximately $95.3 million in Canada.

In addition, approximately $25.5 million of cash was held in Brunei, $20.9 million of cash was held in Mexico and $12.5 million of cash was held in the U.K..

dollar equivalents of approximately $100.0 million, the majority of which was held in Canada ($49.2 million), U.K.

($13.1 million), Mexico ($10.9 million) and Brunei ($10.3 million).

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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Accounting changes and recent accounting pronouncements – see Note B to the Consolidated Financial Statements

As discussed in the Summary section on page 22, several factors have contributed to a lower average crude oil price during the third quarter, which directly impacts the Company’s product revenue from sales (Q3 2022 $91.55;

As discussed in the Summary section on page 19 , several factors have contributed to a lower average crude oil price during the first quarter of 2023, which directly impacts the Company’s product revenue from sales (Q1 2023 $76.13;

Q4 2022 $82.65;

Q1 2022 $94.29 ).

As of close on November 1, 2022, the NYMEX WTI forward curve price for the remainder of 2022 and 2023 were lower at $88.37 and $81.53 per barrel, respectively;

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

Lower prices will result in lower profits and operating cash-flows.

For the fourth quarter, production is expected to average between 173.5 and 181.5 MBOEPD, excluding noncontrolling interest (NCI).

The Company’s capital expenditure spend for 2022 is expected to be between $975.0 million and $1,025.0 million, excluding acquisitions and noncontrolling interest.

Capital expenditures 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.

As of close on May 1, 2023, the NYMEX WTI forward curve prices for the remainder of 2023 and 2024 were lower at $74.52 and $70.76 per barrel, respectively;

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

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

For the second quarter of 2023, production is expected to average between 173.0 and 181.0 MBOEPD, excluding noncontrolling interest.

The Company’s capital expenditure spend for 2023 is expected to be between $875.0 million and $1,025.0 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.

Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared.

The Company plans to fund its remaining capital program in 2022 using operating cash flow and available cash.

The Company will primarily fund its capital program in 2023 using operating cash flow and available cash.

If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects.

The Company 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 as part 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 F).

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

As of November 1, 2022, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows:

Commodity Type Volumes

(Bbl/d) Price

(USD/Bbl) Remaining Period

Area Start Date End Date

United States WTI² Fixed price derivative swap 20,000 $44.88 10/1/2022 12/31/2022

(Bbl/d) Average

(USD/Bbl) Remaining Period

Area Commodity Type Start Date End Date

United States WTI² Derivative collars 25,000 $63.24 $75.20 10/1/2022 12/31/2022

1 West Texas Intermediate

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 RCF (see Note E ).

As of May 1, 2023, 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 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 4/1/2023 10/31/2024

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

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Forward-Looking Statements

This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995.

This Form 10-Q 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 (environmental/social/governance) matters, 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;

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or adverse developments in the U.S.

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

For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in Murphy’s 2021 Annual Report on Form 10-K on file with the U.S.

Securities and Exchange Commission and on page 36 of this Form 10-Q report.

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

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

For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in our most recent Annual Report on Form 10-K filed with the U.S.

Securities and Exchange Commission (“SEC”) and on page 31 of this Form 10-Q report, and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC’s website and from Murphy Oil Corporation’s website at http://ir.murphyoilcorp.com.

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-Q

Item 2. Management’s Discussion and Analysis