Item 2. Management’s Discussion and Analysis
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
Summary
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
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ITEM 2. 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.
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ITEM 2. 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
June 30,
(Millions of dollars) 2023 2022 2023 2022
Exploration and production $ 139.1 $ 535.2 $ 381.7 $ 766.6
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. and U.S. 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
June 30,
(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
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ITEM 2. 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
June 30,
(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).
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ITEM 2. 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
States 1
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.
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ITEM 2. 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
States 1
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.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Results of Operations (Continued)
Exploration and Production
Second quarter 2023 vs. 2022
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
U.S. 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. 2022
All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted.
U.S. 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
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ITEM 2. 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.
Corporate
Second quarter 2023 vs. 2022
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 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.
Six months 2023 vs. 2022
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. 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 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.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Results of Operations (Continued)
Production Volumes and Prices
Second quarter 2023 vs. 2022
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 $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 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 Canada for the second quarter of 2023 was $2.21 and $1.85 per MCF, respectively.
Six months 2023 vs. 2022
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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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Results of Operations (Continued)
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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ITEM 2. 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
June 30,
(Barrels per day unless otherwise noted) 2023 2022 2023 2022
Net crude oil and condensate
United States Onshore 26,880 26,304 23,100 23,334
Gulf of Mexico 1
72,022 63,427 73,850 59,363
Canada Onshore 3,097 4,419 3,190 4,400
Offshore 2,913 3,128 2,687 3,224
Other 212 1,383 240 833
Total net crude oil and condensate - continuing operations 105,124 98,661 103,067 91,154
Net natural gas liquids
United States Onshore 4,328 5,178 4,243 5,006
Gulf of Mexico 1
6,291 4,913 6,316 4,223
Canada Onshore 558 859 691 921
Total net natural gas liquids - continuing operations 11,177 10,950 11,250 10,150
Net natural gas – thousands of cubic feet per day
United States Onshore 24,195 29,651 24,178 28,512
Gulf of Mexico 1
69,904 63,703 72,539 59,902
Canada Onshore 352,265 288,019 328,878 273,237
Total net natural gas - continuing operations 446,364 381,373 425,595 361,651
Total net hydrocarbons - continuing operations including NCI 2,3
190,695 173,173 185,250 161,579
Noncontrolling interest
Net crude oil and condensate – barrels per day (5,949) (7,962) (6,279) (8,044)
Net natural gas liquids – barrels per day (204) (319) (218) (303)
Net natural gas – thousands of cubic feet per day (1,751) (3,097) (2,051) (2,845)
Total noncontrolling interest 3
(6,445) (8,797) (6,839) (8,821)
Total net hydrocarbons - continuing operations excluding NCI 2,3
184,250 164,376 178,411 152,758
1 Includes net volumes attributable to a noncontrolling interest in MP GOM.
2 Natural gas converted on an energy equivalent basis of 6:1.
3 NCI – noncontrolling interest in MP GOM.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Results of Operations (Continued)
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
June 30,
2023 2022 2023 2022
(Weighted average Exploration and Production sales prices)
Continuing operations
Crude oil and condensate – dollars per barrel
United States Onshore $ 72.39 $ 110.66 $ 73.47 $ 103.39
Gulf of Mexico 1
73.82 109.55 73.54 102.76
Canada 2
Onshore 68.50 100.51 71.46 96.84
Offshore 80.14 115.65 79.26 113.46
Other – 86.51 89.05 86.51
Natural gas liquids – dollars per barrel
United States Onshore 16.60 38.29 19.28 38.30
Gulf of Mexico 1
20.16 40.46 22.89 41.95
Canada 2
Onshore 29.90 63.99 39.82 59.23
Natural gas – dollars per thousand cubic feet
United States Onshore 1.88 7.06 2.19 5.89
Gulf of Mexico 1
2.33 7.52 2.81 6.43
Canada 2
Onshore 1.85 2.78 2.17 2.66
1 Prices include the effect of noncontrolling interest share for MP GOM.
2 U.S. dollar equivalent.
Financial Condition
The Company’s primary sources of liquidity are cash on hand, net cash provided by continuing operations activities and available borrowing capacity under its senior unsecured revolving credit facility. The Company’s liquidity requirements consist primarily of capital expenditures, debt maturity, retirement and interest payments, working capital requirements, dividend payments, and, as applicable, share repurchases. See below for additional discussion and analysis of the Company’s cash flows.
Cash Provided by Operating Activities
Net cash provided by continuing operating activities was $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; 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 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.
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ITEM 2. 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.
Six Months Ended
June 30,
(Millions of dollars) 2023 2022
Capital Expenditures
Exploration and production $ 688.4 $ 611.4
Corporate 9.9 10.5
Total capital expenditures $ 698.3 $ 621.9
A reconciliation of “Property additions and dry hole costs” in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.
Six Months Ended
June 30,
(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
Capital expenditure accrual changes and other (16.5) 6.3
Total capital expenditures $ 698.3 $ 621.9
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. 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 $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.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Financial Condition (Continued)
Working Capital
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 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%.
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 %
Capital employed
Long-term debt $ 1,823.5 25.8 % $ 1,822.4 26.7 %
Murphy shareholders' equity 5,234.3 74.2 % 4,994.8 73.3 %
Total capital employed $ 7,057.8 100.0 % $ 6,817.2 100.0 %
Cash and invested cash are maintained in several operating locations 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 $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. in future periods. 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
Outlook
Prices for the Company’s primary products are often volatile. The price of crude oil is primarily affected by the levels of supply and demand for energy. 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; 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 third quarter of 2023, production is expected to average between 188.0 and 196.0 thousand barrels of oil equivalents (MBOEPD), excluding noncontrolling interest.
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ITEM 2. 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. Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its capital program in 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), 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 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:
Volumes
(MMcf/d) Price/Mcf Remaining Period
Area Commodity Type Start Date End Date
Canada Natural Gas Fixed price forward sales 250 C$2.35 7/1/2023 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 7/1/2023 10/31/2024
Canada Natural Gas Fixed price forward sales 15 US$1.98 11/1/2024 12/31/2024
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED)
Forward-Looking Statements
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, 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, make capital expenditures or pay and/or increase dividends or make share repurchases and other capital allocation decisions are forward-looking statements. Factors that could cause one or more of these future events, results or plans not to occur as implied by any forward-looking statement, which consequently could cause actual results or activities to differ materially from the expectations expressed or implied by such forward-looking statements, include, but are not limited to: macro conditions in the oil and gas industry, including supply/demand levels, actions taken by major oil exporters and the resulting impacts on commodity prices; increased volatility or deterioration in the success rate of our exploration programs or in our ability to maintain production rates and replace reserves; reduced customer demand for our products due to environmental, regulatory, technological or other reasons; adverse foreign exchange movements; political and regulatory instability in the markets where we do business; the impact on our operations or market of health pandemics such as COVID-19 and related government responses; other natural hazards impacting our operations or markets; any other deterioration in our business, markets or prospects; any failure to obtain necessary regulatory approvals; any inability to service or refinance our outstanding debt or to access debt markets at acceptable prices; or adverse developments in the U.S. or global capital markets, credit markets, 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 40 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.
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Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.