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Item 2. Management’s Discussion and Analysis

2023-08-03 compared with 2023-05-03 · 333 added, 76 removed, 148 unchanged (73% of the section changed)

MANAGEMENT’S DISCUSSION AND ANALYSIS

Murphy Oil Corporation’s net income from continuing operations, including noncontrolling interest, for the three months ended June 30, 2023 was $92.5 million, compared to $410.4 million in the in the second quarter of 2022, reflecting a decrease of $317.9 million.

Lower net income from continuing operations was largely driven by lower revenues and other income ($286.5 million), increases in exploration expenses ($100.6 million) and higher lease operating expenses ($46.9 million), partially offset by lower income tax expense ($70.2 million).

Lower revenues resulted from lower pricing, partially offset by higher sales volumes.

Higher exploration costs were the result of dry hole expenses for the Chinook #7 exploration well in the Gulf of Mexico, the purchase of seismic data for Côte d’Ivoire in offshore Africa and the expensing of previously suspended exploration costs for the Cholula -1 EXP well in Mexico.

Increases in lease operating expenses were the result of higher sales volumes while lower income tax expense was the result of lower pre-tax income.

For the six months ended June 30, 2023, the Company reported net income from continuing operations of $306.5 million, compared to $345.5 million in the same period of 2022, reflecting a decrease of $39.0 million.

Lower net income from continuing operations was largely driven by higher lease operating expenses ($110.1 million) and increases in exploration expenses ($63.3 million), partially offset by lower other operating expense ($125.9 million).

Total revenues and other income were consistent period over period as higher sales volumes and no realized and unrealized losses on derivative instruments were offset by lower pricing for the six months ended June 30, 2023.

Increased lease operating expenses relate to higher sales volumes and additional costs associated with workover and maintenance activities at the Gulf of Mexico operations.

Higher exploration costs were the result of dry hole expense for the Chinook #7 exploration well in the Gulf of Mexico, the purchase of seismic data for Côte d’Ivoire in offshore Africa, and the expensing of previously suspended exploration costs for the Cholula -1 EXP well in Mexico.

Lower other expenses were due to lower contingent consideration adjustments relating to prior acquisitions in the Gulf of Mexico.

For the three months ended June 30, 2023, West Texas Intermediate (WTI) crude oil prices averaged approximately $73.78 per barrel (compared to $108.41 in the second quarter of 2022 and $76.13 in the first quarter of 2023).

The average price for WTI in June of 2023 was approximately $70.27 per barrel, reflecting a 39% reduction from June of 2022 and a 4% reduction from the average price from March of 2023.

The average price in July 2023 was $76.03 per barrel.

As of close on August 1, 2023, the NYMEX WTI forward curve prices for the remainder of 2023 and 2024 were $80.68 and $76.93 per barrel, respectively.

For the three months ended June 30, 2023, the New York Mercantile Exchange (NYMEX) natural gas price per million British Thermal Units (MMBTU) averaged approximately $2.12 per barrel (compared to $7.39 in the second quarter of 2022 and $2.67 in the first quarter of 2023).

The average price for NYMEX natural gas in June of 2023 was approximately $2.12 per barrel, reflecting a 72% reduction from June of 2022 and a 9% reduction from the average price from March of 2023.

As of close on August 1, 2023, the NYMEX natural gas forward curve prices for the remainder of 2023 and 2024 were $2.95 and $3.45 per barrel, respectively.

For the three months ended June 30, 2023, the Company produced 191 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $362.3 million in capital expenditures (on a value of work done basis), which included $32.3 million in acquisition-related capital.

Acquisition-related capital consisted primarily of the final milestone payment for the Block 15-1/05 farm-in agreement in Vietnam following government approval of the development plan and lease acquisition costs and seismic data for Côte d’Ivoire in offshore Africa.

For the six months ended June 30, 2023, the Company produced 185 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $698.3 million in capital expenditures (on a value of work done basis), which included acquisition capital of $32.3 million.

Acquisition capital consisted primarily of the final milestone payment for the Block 15-1/05 farm-in agreement in Vietnam following government approval of the development plan and lease acquisition costs for Côte d’Ivoire in offshore Africa.

During the three and six months ended June 30, 2023, crude oil and condensate, natural gas and natural gas liquids (NGL) volumes from continuing operations were higher than the comparable prior year periods.

The increase in production volumes was primarily due to higher production from Khaleesi, Mormont, Samurai field development project, reflecting a full second quarter of production in 2023 (the project started in Q2 2022) and

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Results of Operations (Continued)

increased production from new wells added since the second quarter of 2022.

In addition, there were higher gas volumes at Tupper Montney related to new well production.

For the three and six months ended June 30, 2023, revenue from production was 30% lower and 19% lower, respectively, compared to the same periods in 2022, primarily driven by the decrease in prices.

For the three months ended June 30, 2022, the Company produced 173 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $317.1 million in capital expenditures (on a value of work done basis), which included $46.5 million for an additional working interest in the Kodiak field in the Gulf of Mexico.

The Company reported net income from continuing operations of $410.4 million for the three months ended June 30, 2022;

this amount included after-tax gains on unrealized mark to market revaluations on commodity price swap and collar positions of $69.6 million and after-tax losses on contingent consideration of $25.1 million.

During the second quarter of 2022, the Company achieved first production at the Khaleesi, Mormont, Samurai field development project in the Gulf of Mexico, with production flowing through the Murphy-operated King’s Quay floating production system.

In June 2022, the Company also acquired an additional 11.0% working interest (there is no noncontrolling interest) in the Kodiak field in the Gulf of Mexico for a purchase price of $46.5 million.

For the six months ended June 30, 2022, the Company produced 162 thousand barrels of oil equivalent per day (including noncontrolling interest) from continuing operations and invested $621.9 million in capital expenditures (on a value of work done basis), which included $46.5 million related to acquisition capital and $24.3 million related to the Cutthroat -1 exploration well in Brazil.

The Company reported net income from continuing operations of $345.5 million for the six months ended June 30, 2022.

This amount included after-tax losses on unrealized mark to market revaluations on commodity price derivative positions and contingent consideration adjustments of $79.3 million and $102.3 million, respectively.

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Results of Operations (Continued)

Results of Operations

Murphy’s income (loss) by type of business is presented below.

Income (Loss)

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) 2023 2022 2023 2022

Exploration and production $ 139.1 $ 535.2 $ 381.7 $ 766.6

First quarter 2023 vs.

Corporate and other (46.6) (124.8) (75.2) (421.1)

Income from continuing operations 92.5 410.4 306.5 345.5

Discontinued operations ¹ (0.6) (0.9) (0.3) (1.5)

Net income including noncontrolling interest $ 91.9 $ 409.5 $ 306.2 $ 344.0

1 The Company has presented its former U.K.

refining and marketing operations as discontinued operations in its consolidated financial statements.

Exploration and Production

Results of Exploration and Production (E&P) continuing operations are presented by geographic segment below.

Income (Loss)

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) 2023 2022 2023 2022

Exploration and production

United States $ 168.9 $ 491.5 $ 394.9 $ 744.4

Canada 2.5 47.2 24.4 69.9

Other (32.3) (3.5) (37.6) (47.7)

Total $ 139.1 $ 535.2 $ 381.7 $ 766.6

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Results of Operations (Continued)

Other key performance metrics

The Company uses other operational performance and income metrics to review operational performance.

The table below presents Earnings before interest, taxes, depreciation and amortization (EBITDA) and Adjusted EBITDA.

Management uses EBITDA and Adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors.

EBITDA and Adjusted EBITDA are non-GAAP financial measures and should not be considered a substitute for Net income (loss) or Cash provided by operating activities as determined in accordance with GAAP.

Three Months Ended

June 30, Six Months Ended

(Millions of dollars) 2023 2022 2023 2022

Net income attributable to Murphy (GAAP) $ 98.3 $ 350.6 $ 289.9 $ 237.2

Income tax expense 34.9 105.1 88.7 88.1

Interest expense, net 29.9 41.4 58.7 78.7

Depreciation, depletion and amortization expense ¹ 210.1 188.2 399.3 344.8

EBITDA attributable to Murphy (Non-GAAP) 373.2 685.3 836.6 748.8

Write-off of previously suspended exploration well 17.1 — 17.1 —

Accretion of asset retirement obligations ¹ 10.1 10.2 20.0 20.7

Foreign exchange loss (gain) 7.9 (8.0) 8.3 (8.0)

Mark-to-market loss on contingent consideration 3.2 31.7 7.1 129.8

Discontinued operations loss 0.6 0.9 0.3 1.5

Mark-to-market (gain) loss on derivative instruments – (88.1) – 100.4

Adjusted EBITDA attributable to Murphy (Non-GAAP) $ 412.1 $ 632.0 $ 889.4 $ 993.2

1 Depreciation, depletion and amortization expense and accretion of asset retirement obligations used in the computation of Adjusted EBITDA exclude the portion attributable to the non-controlling interest (NCI).

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Results of Operations (Continued)

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED JUNE 30, 2023 AND 2022

(Millions of dollars) United

Canada Other Total

Three Months Ended June 30, 2023

Oil and gas sales and other operating revenues $ 696.2 $ 105.3 $ — $ 801.5

Sales of purchased natural gas — 13.0 – 13.0

Lease operating expenses 156.5 37.5 0.1 194.1

Severance and ad valorem taxes 12.4 0.4 – 12.8

Transportation, gathering and processing 39.9 20.1 – 60.0

Costs of purchased natural gas — 9.7 – 9.7

Depreciation, depletion and amortization 178.0 35.0 — 213.0

Accretion of asset retirement obligations 9.3 1.9 0.1 11.3

Exploration expenses

Dry holes and previously suspended exploration costs 79.8 – 15.8 95.6

Geological and geophysical 0.4 0.1 10.0 10.5

Other exploration 1.7 — 5.3 7.0

81.9 0.1 31.1 113.1

Undeveloped lease amortization 2.1 — 0.6 2.7

Total exploration expenses 84.0 0.1 31.7 115.8

Selling and general expenses (1.9) 4.7 2.6 5.4

Other 0.5 5.4 1.4 7.3

Results of operations before taxes 217.5 3.5 (35.9) 185.1

Income tax provisions (benefits) 48.6 1.0 (3.6) 46.0

Results of operations (excluding Corporate segment) $ 168.9 $ 2.5 $ (32.3) $ 139.1

Three Months Ended June 30, 2022

Oil and gas sales and other operating revenues $ 977.8 $ 156.8 $ 13.7 $ 1,148.3

Sales of purchased natural gas 0.2 49.8 – 50.0

Lease operating expenses 109.5 36.9 0.9 147.3

Severance and ad valorem taxes 17.3 0.3 – 17.6

Transportation, gathering and processing 32.3 17.6 – 49.9

Costs of purchased natural gas 0.2 47.7 – 47.9

Depreciation, depletion and amortization 153.7 35.6 3.4 192.7

Accretion of asset retirement obligations 9.1 2.4 0.1 11.6

Exploration expenses

Dry holes and previously suspended exploration costs (0.7) – 2.0 1.3

Geological and geophysical – 0.1 0.8 0.9

Other exploration 2.9 0.3 6.0 9.2

2.2 0.4 8.8 11.4

Undeveloped lease amortization 2.3 – 1.4 3.7

Total exploration expenses 4.5 0.4 10.2 15.1

Selling and general expenses 3.2 3.8 2.1 9.1

Other 35.3 (2.3) – 33.0

Results of operations before taxes 612.9 64.2 (3.0) 674.1

Income tax provisions 121.4 17.0 0.5 138.9

Results of operations (excluding Corporate segment) $ 491.5 $ 47.2 $ (3.5) $ 535.2

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

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Results of Operations (Continued)

OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE 30, 2023 AND 2022

(Millions of dollars) United

Canada Other Total

Six Months Ended June 30, 2023

Oil and gas sales and other operating revenues $ 1,378.5 $ 217.2 $ 3.6 $ 1,599.3

Sales of purchased natural gas – 56.8 – 56.8

Lease operating expenses 319.2 74.3 0.7 394.2

Severance and ad valorem taxes 23.5 0.7 – 24.2

Transportation, gathering and processing 77.3 36.5 – 113.8

Costs of purchased natural gas – 41.9 – 41.9

Depreciation, depletion and amortization 338.2 66.7 0.9 405.8

Accretion of asset retirement obligations 18.4 3.9 0.2 22.5

Exploration expenses

Dry holes and previously suspended exploration costs 79.6 – 16.9 96.5

Geological and geophysical 0.7 0.1 10.5 11.3

Other exploration 3.3 0.1 9.4 12.8

83.6 0.2 36.8 120.6

Undeveloped lease amortization 4.1 0.1 1.2 5.4

Total exploration expenses 87.7 0.3 38.0 126.0

Selling and general expenses 4.5 7.1 2.8 14.4

Other 9.9 9.7 1.4 21.0

Results of operations before taxes 499.8 32.9 (40.4) 492.3

Income tax provisions (benefits) 104.9 8.5 (2.8) 110.6

Results of operations (excluding Corporate segment) $ 394.9 $ 24.4 $ (37.6) $ 381.7

Six Months Ended June 30, 2022

Oil and gas sales and other operating revenues $ 1,685.2 $ 286.1 $ 13.7 $ 1,985.0

Sales of purchased natural gas 0.2 86.6 – 86.8

Lease operating expenses 209.4 73.8 0.9 284.1

Severance and ad valorem taxes 31.5 0.7 – 32.2

Transportation, gathering and processing 61.5 35.3 – 96.8

Costs of purchased natural gas 0.2 81.6 – 81.8

Depreciation, depletion and amortization 280.2 69.8 3.5 353.5

Accretion of asset retirement obligations 18.5 4.9 0.1 23.5

Exploration expenses

Dry holes and previously suspended exploration costs (0.7) – 34.8 34.1

Geological and geophysical 2.6 0.1 1.0 3.7

Other exploration 4.4 0.4 12.1 16.9

6.3 0.5 47.9 54.7

Undeveloped lease amortization 4.7 0.1 3.2 8.0

Total exploration expenses 11.0 0.6 51.1 62.7

Selling and general expenses 11.5 8.9 4.5 24.9

Other 138.1 2.8 0.4 141.3

Results of operations before taxes 923.5 94.5 (46.8) 971.2

Income tax provisions 179.1 24.6 0.9 204.6

Results of operations (excluding Corporate segment) $ 744.4 $ 69.9 $ (47.7) $ 766.6

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

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Results of Operations (Continued)

Exploration and Production

Second quarter 2023 vs.

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

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.

E&P operations reported earnings of $168.9 million in the second quarter of 2023 compared to earnings of $491.5 million in the second quarter of 2022.

Results were $322.6 million unfavorable in the 2023 period compared to the 2022 period primarily due to lower revenues ($281.6 million), higher dry hole and previously suspended exploration costs ($80.5 million), higher lease operating expenses ($47.0 million) and higher depreciation, depletion and amortization expense (DD&A) ($24.3 million), partially offset by lower other expense ($34.8 million) and lower income tax expense ($72.8 million).

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

Higher exploration costs related to the dry hole expense of Chinook #7 exploration well in the Gulf of Mexico, which encountered non-commercial hydrocarbons.

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

Higher DD&A was primarily the result of higher sales volumes from the Gulf of Mexico.

Lower other expense was primarily due to a lower contingent consideration adjustment of $3.2 million in 2023 (2022:

$31.7 million) as a result of reaching contractual thresholds or time limitations that ended in 2022 (see Note L ) .

Lower income tax expense was a result of lower pre-tax income.

Canadian E&P operations reported earnings of $2.5 million in the second quarter of 2023 compared to earnings of $47.2 million in the second quarter of 2022.

Results were unfavorable $44.7 million compared to the 2022 period primarily due to lower revenues ($51.5 million), partially offset by lower income tax expense ($16.0 million).

Lower revenues were due to lower oil and gas pricing in the second quarter of 2023 and lower sales volumes primarily as a result of natural decline at Kaybob Duvernay, partially offset by higher natural gas sales volumes and lower royalties at Tupper Montney.

Lower income tax expense was a result of lower pre-tax income.

Other international E&P operations reported a loss from continuing operations of $32.3 million in the second quarter of 2023 compared to a loss of $3.5 million in the second quarter of 2022.

The result was $28.8 million unfavorable versus the 2022 period primarily due to higher exploration expenses ($21.5 million) and lower revenues from Brunei ($13.7 million).

Higher exploration expenses related to the purchase of seismic data for Côte d’Ivoire in offshore Africa and writing off previously suspended exploration costs for the Cholula -1 EXP well in Mexico.

Six months 2023 vs.

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

E&P operations reported earnings of $394.9 million for the six months ended June 30, 2023, compared to earnings of $744.4 million for the six months ended June 30, 2022.

Results were $349.5 million unfavorable in the 2023 period compared to the 2022 period, driven by lower revenues ($306.9 million), higher lease operating expenses ($109.8 million), higher dry hole and previously suspended exploration costs ($80.3 million) and higher DD&A ($58.0 million), partially offset by lower other expense ($128.2 million) and lower income tax expense ($74.2 million).

Lower revenues were primarily attributable to lower realized prices in 2023 compared to 2022, partially offset by higher sales volumes from the Gulf of Mexico primarily related to new wells at Khaleesi, Mormont, Samurai development project.

Higher lease operating expenses related to increased sales volumes and additional costs associated with workover and maintenance from the Gulf of Mexico operations.

Higher exploration costs related to the dry hole expense of Chinook #7 exploration well in the Gulf of Mexico, which encountered non-commercial hydrocarbons.

Higher DD&A was primarily the result of higher sales volumes from the Gulf of Mexico.

Lower other expenses was primarily due to a lower contingent consideration adjustment of $7.1 million in 2023 (2022:

$129.8 million), as a result of reaching contractual thresholds or time limitations that ended in 2022 (see Note L ) .

Lower income tax expense was a result of lower pre-tax income.

Canadian E&P operations reported earnings of $24.4 million for the six months ended June 30, 2023, compared to earnings of $69.9 million for the six months ended June 30, 2022.

Results were $45.5 million unfavorable compared to the 2022 period.

The current year results include lower revenues ($68.9 million), partially offset by lower income tax expense ($16.1 million).

Lower revenue was primarily attributable to lower realized prices and

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Results of Operations (Continued)

lower volumes at Kaybob Duvernay primarily due to natural decline, partially offset by higher gas volumes at Tupper Montney related to new wells added and lower royalties.

Lower income tax expense was a result of lower pre-tax income.

Other international E&P operations reported a loss of $37.6 million for the six months ended June 30, 2023, compared to a loss of $47.7 million in the prior year.

Results were $10.1 million favorable compared to the 2022 period primarily due to lower exploration expenses ($13.1 million), partially offset by lower revenues from Brunei ($10.1 million).

Lower exploration expenses were primarily the result of higher dry hole costs in 2022 for Cutthroat -1 exploration well, partially offset by the purchase of seismic data for Côte d’Ivoire in offshore Africa in the current period.

During the six months ended June 30, 2023, the Company expensed costs for the previously suspended exploration costs for Cholula -1 EXP well in Block 5 in the Gulf of Mexico, and during the same period in 2022, the Company expensed costs associated with the Cutthroat -1 exploration well in block SEAL-M-428, in the Sergipe-Alagoas Basin offshore Brazil.

Second 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 $46.6 million in the second quarter of 2023 compared to a loss of $124.8 million in same period of 2022.

The $78.2 million favorable variance was principally due to no current period losses on derivative instruments in the second quarter of 2023 compared to a loss for the same period in 2022 of $103.1 million.

Realized and unrealized losses on derivative instruments are due to an increase in market pricing in future periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price, with variability in between the floor and ceiling.

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).

During the second quarter of 2023 and as of June 30, 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 ($11.6 million), partially offset by lower income tax benefit ($22.4 million).

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

Production Volumes and Prices

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.

Six months 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 $75.2 million for the six months ended June 30, 2023, compared to a loss of $421.1 million for the six months ended June 30, 2022.

The $345.9 million favorable variance was primarily due to no current period losses on derivative instruments for the six months ended June 30, 2023, compared to a loss for the same period in 2022 ($423.8 million) and lower interest expense ($19.9 million), partially offset by lower income tax benefits ($94.4 million) and higher foreign exchange losses ($15.9 million).

Interest charges are lower for the six months ended June 30, 2023, primarily due to lower overall debt levels as the Company reduced debt by $647.7 million during 2022 and the Company incurred debt redemption premiums of $3.4 million during the same period in 2022.

During the six months ended June 30, 2023 and as of June 30, 2023, the Company did not enter into or have any fixed price derivative swaps or collar contracts outstanding.

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

T able of Contents

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.

Production Volumes and Prices

Second quarter 2023 vs.

Total hydrocarbon production from continuing operations averaged 190,695 barrels of oil equivalent per day in the second quarter of 2023, which was 10% higher than the 173,173 barrels per day produced in second quarter of 2022.

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

Average crude oil and condensate production from continuing operations was 105,124 barrels per day in the second quarter of 2023 compared to 98,661 barrels per day in the second quarter of 2022.

The increase of 6,463 barrels per day was associated with higher volumes in the Gulf of Mexico (8,595 barrels per day) principally due to a full quarter of production from the Khaleesi, Mormont, Samurai field development project in 2023 and new wells added since the second quarter of 2022.

In addition, Canada production was lower (1,537 barrels per day) primarily attributable to natural well declines at Kaybob Duvernay.

Eagle Ford Shale production was higher (576 barrels per day) due to new well production.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $73.50 per barrel in the second quarter of 2023 compared to $109.25 per barrel in the same period of 2022 period, a decrease of 33%.

Total production of NGL from continuing operations was 11,177 barrels per day in the second quarter of 2023 compared to 10,950 barrels per day in the second quarter of 2022.

The increase of 227 barrels per day was associated with higher volumes in the Gulf of Mexico principally due to increased production from the Khaleesi, Mormont, Samurai field development project, partially offset with lower volumes at Eagle Ford Shale for planned downtime for offset frac impacts.

The average sales price for U.S.

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 was $18.71 per barrel in the second quarter of 2023 compared to $39.37 per barrel in the same period of 2022.

The average sales price for NGL in Canada was $29.90 per barrel in the second quarter of 2023 compared to $63.99 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 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 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.

Natural gas production volumes from continuing operations averaged 446.4 million cubic feet per day (MMCFD) in the second quarter of 2023 compared to 381.4 MMCFD in the second quarter 2022.

The increase of 65.0 MMCFD was primarily the result of higher volumes in Canada (64.2 MMCFD).

Higher natural gas volume in Canada is primarily due to new well production and lower natural gas royalty volumes.

Natural gas prices for the total Company averaged $1.92 per thousand cubic feet (MCF) in the second quarter of 2023, versus $3.90 per MCF average in the same period of 2022.

Average natural gas prices in the U.S.

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 .

and Canada for the second quarter of 2023 was $2.21 and $1.85 per MCF, respectively.

Six months 2023 vs.

Total hydrocarbon production from Exploration and Production averaged 185,250 barrels of oil equivalent per day for the six months ended June 30, 2023, which represented a 15% increase from the 161,579 barrels per day produced for the six months ended June 30, 2022.

The increase was principally due to increased production from the Khaleesi, Mormont, Samurai field development project, as well as higher production from Canada Onshore primarily due to new wells at Tupper Montney.

Average crude oil and condensate production was 103,067 barrels per day for the six months ended June 30, 2023, compared to 91,154 barrels per day for the six months ended June 30, 2022.

The increase of 11,913 barrels per day was principally due to increased production from the Gulf of Mexico largely attributable to the Khaleesi, Mormont, Samurai field development project for new wells added since the second quarter of 2022 (14,487 barrels per day).

In addition, Canada production was lower (1,747 barrels per day) primarily due to natural decline at Kaybob Duvernay.

Eagle Ford Shale production was lower (234 barrels per day) due to normal well decline partially offset by new well production.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $73.65 per barrel for the six months ended June 30, 2023, compared to $102.86 per barrel in the 2022 period, and decrease of 28.4% year over year.

Total production of NGL was 11,250 barrels per day for the six months ended June 30, 2023, compared to 10,150 barrels per day in the 2022 period.

The average sales price for U.S.

NGL was $21.44 per barrel in 2023

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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.

compared to $40.00 per barrel in 2022.

The average sales price for NGL in Canada was $39.82 per barrel in 2023 compared to $59.23 per barrel in 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 averaged 425.6 MMCFD for the six months ended June 30, 2023, compared to 361.7 MMCFD in 2022.

The increase of 63.9 MMCFD was primarily the result of higher volumes in Canada (55.6 MMCFD) and the Gulf of Mexico (12.6 MMCFD), partially offset by lower volumes at Eagle Ford Shale (4.3 MMCFD).

The higher natural gas volumes in Canada were the result of new wells brought into production during the second quarter of 2023 and new wells added since the second quarter of 2022.

Natural gas prices for the total Company averaged $2.28 per MCF for the six months ended June 30, 2023, versus $3.54 per MCF average in the same period of 2022.

Average realized natural gas prices in the U.S.

and Canada for the six months ended June 30, 2023 were $2.66 per MCF and $2.17 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 27 a nd 28 .

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MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Results of Operations (Continued)

The following table contains hydrocarbons produced during the three-month and six-month periods ended June 30, 2023 and 2022.

Three Months Ended

June 30, Six Months Ended

(Barrels per day unless otherwise noted) 2023 2022 2023 2022

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Gulf of Mexico 1

6,291 4,913 6,316 4,223

Canada Onshore 558 859 691 921

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3 NCI – noncontrolling interest in MP GOM.

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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.

The following table contains the weighted average sales prices for the three-month and six-month periods ended June 30, 2023 and 2022.

Three Months Ended

June 30, Six Months Ended

2023 2022 2023 2022

(Weighted average Exploration and Production sales prices)

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Gulf of Mexico 1

73.82 109.55 73.54 102.76

Onshore 68.50 100.51 71.46 96.84

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Gulf of Mexico 1

20.16 40.46 22.89 41.95

Onshore 29.90 63.99 39.82 59.23

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Gulf of Mexico 1

2.33 7.52 2.81 6.43

Onshore 1.85 2.78 2.17 2.66

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Cash Provided by Operating Activities

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).

Net cash provided by continuing operating activities was $749.7 million for the six months ended June 30, 2023 compared to $959.2 million during the same period in 2022.

The lower cash from operating activities of $209.5 million was primarily attributable to lower revenue from production ($384.8 million), payments of contingent consideration related to prior Gulf of Mexico acquisition ($139.6 million), and higher lease operating expenses ($110.1 million), partially offset by lower realized losses on derivative instruments ($323.5 million) and the timing of working capital settlements ($106.3 million).

Payments of contingent consideration are shown both in “Operating Activities” and “Financing Activities” in the Company’s Consolidated Statement of Cash Flows;

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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, 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.

During the six months ended June 30, 2023, the Company paid a total of $199.8 million in contingent consideration, of which $139.6 million is shown in “Operating Activities” and $60.2 million is shown in “Financing Activities” in the Company’s Consolidated Statement of Cash Flows.

As of June 30, 2023, the Company has no further obligation payable for contingent consideration relating to prior Gulf of Mexico acquisitions.

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Financial Condition (Continued)

Cash Required by Investing Activities

Net cash required by investing activities, including amount expensed, was $694.8 million for the six months ended June 30, 2023 compared to $599.3 million during the same period in 2022.

In the second quarter of 2023, the Company accrued for acquisition-related capital of $32.3 million, which consisted primarily of the final milestone payment for the Block 15-1/05 farm-in agreement in Vietnam following government approval of the development plan and lease acquisition costs for Côte d’Ivoire in offshore Africa (also see Note D ).

During the six months ended 2022, the Company acquired an 11.0% additional working interest in Kodiak of $46.5 million.

Total accrual basis capital expenditures are shown below.

Three Months Ended

Six Months Ended

(Millions of dollars) 2023 2022

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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.

Three Months Ended

Six Months Ended

(Millions of dollars) 2023 2022

Property additions and dry hole costs per cash flow statements $ 694.8 $ 552.8

Acquisition of oil and gas properties – 46.5

Geophysical and other exploration expenses 20.0 16.3

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Total capital expenditures $ 698.3 $ 621.9

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.

The increase in capital expenditures in the exploration and production business in six months ended June 30, 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 in the Gulf of Mexico, and exploration drilling at Chinook #7, Oso #1 and Longclaw #1 within the Gulf of Mexico.

Costs associated with Chinook #7 were expensed to dry hole costs in the second quarter of 2023 as the Company determined there were non- commercial hydrocarbons present.

In the first quarter of 2023, drilling of the Oso #1 well was temporarily suspended prior to reaching the objective.

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Cash Required by Financing Activities

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 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.

Net cash required by financing activities was $176.6 million for the six months ended June 30, 2023 compared to $447.5 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 ($60.2 million) as discussed in the “Cash Provided by Operating Activities” section, cash dividends to shareholders of $0.55 per share ($85.9 million) and distributions to the non-controlling interest in the Gulf of Mexico ($16.0 million).

As of June 30, 2023 and in the event it is required to fund investing activities from borrowings, the Company has $769.6 million available on its committed RCF.

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

Financial Condition (Continued)

Working Capital

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.

As of June 30, 2023, working capital (total current assets less total current liabilities) amounted to a net working capital liability of $165.4 million, $120.1 million lower than December 31, 2022, with the favorable decrease primarily attributable to lower other accrued liabilities ($307.8 million), partially offset with higher accounts payable ($40.3 million), higher operating lease liabilities ($37.9 million) and a lower cash balance ($122.6 million).

Lower accrued liabilities were primarily due to payments made for contingent consideration obligation from prior Gulf of Mexico acquisitions, payments for abandonment activities and incentive payments made during the six months ended June 30, 2023.

Higher accounts payable was primarily due to increased drilling and completions activities and an increase in current payables for abandonment activities, partially offset by the decrease in unrealized losses on derivative instruments (commodity price swaps and collars), as there were no commodity derivative instrument contracts outstanding during 2023.

Higher current operating lease liabilities were 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 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.

At June 30, 2023, long-term debt of $1,823.5 million had increased by $1.1 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 7.2 years and a weighted average coupon of 6.1%.

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

A summary of capital employed at June 30, 2023 and December 31, 2022 follows.

June 30, 2023 December 31, 2022

(Millions of dollars) Amount % Amount %

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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.

As of June 30, 2023, cash and cash equivalents held outside the U.S.

included U.S.

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).

dollar equivalents of approximately $76.9 million, the majority of which was held in Mexico ($21.1 million), Canada ($20.8 million), U.K.

($11.8 million), Brunei ($8.8 million) and Spain ($8.2 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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Canada currently collects a 5% withholding tax on any earnings repatriated to the U.S.

On July 31, 2023 the Company entered into a purchase and sale agreement to sell a portion of our operated non-core Kaybob Duvernay assets and all of our non-operated Placid Montney assets, located in Alberta, Canada for net cash consideration of C$150 million.

The transaction is anticipated to close in the third quarter of 2023, subject to closing conditions and adjustments.

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

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;

Prices for the Company’s primary products are often volatile.

The price of crude oil is primarily affected by the levels of supply and demand for energy.

As discussed in the Summary section on page 23 , lower average crude oil price during the second quarter of 2023 directly impacts the Company’s product revenue from sales.

NYMEX WTI pricing for recent and comparable periods was as follows:

Q2 2023 $73.78;

Q1 2023 $76.13;

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.

Q2 2022 $108.41.

As of close on August 1, 2023 the NYMEX WTI forward curve prices for the remainder of 2023 and 2024 were lower at $80.68 and $76.93 per barrel, respectively;

however, we cannot predict what impact economic factors (including, but not limited to, inflation, global conflicts and possible economic recession) may have on future commodity pricing.

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

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

For the third quarter of 2023, production is expected to average between 188.0 and 196.0 thousand barrels of oil equivalents (MBOEPD), excluding noncontrolling interest.

MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)

The Company’s capital expenditure spend for 2023 is expected to be between $950.0 million and $1,025.0 million, excluding noncontrolling interest.

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

The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests) in accordance with the Company’s capital allocation framework.

The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests), including proceeds from the Company’s divestiture of a portion of our operated non-core Kaybob Duvernay assets and all of our non-operated Placid Montney assets, in accordance with the Company’s capital allocation framework designed to allow for additional shareholder returns and debt reduction.

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

The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the 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:

As of August 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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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.

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

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

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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