MURPHY OIL CORP 10-Q

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.) Results of Operations (contd.) Exploration and Production Third quarter 2022 vs. 2021 All amounts include amount attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM), unless otherwise noted. United States E&P operations reported earnings of $481.5 million in the third quarter of 2022 compared to income of $168.1 million in the third quarter of 2021. Results were $313.4 million favorable in the 2022 quarter compared to the 2021 period primarily due to higher revenues ($408.6 million), lower exploration expenses ($17.1 million) and other operating expense ($66.8 million), partially offset by higher lease operating expenses ($62.1 million), higher depreciation, depletion and amortization (DD&A, $22.4 million) and higher income tax expense ($82.3 million). Higher revenues were primarily due to higher commodity prices, higher production volumes from the Khaleesi and Mormont fields and lower weather related downtime. Lower exploration expenses are due to no repeat of 2021 dry hole costs related to Silverback. Lower other operating expense is primarily due to favorable mark to market revaluations on contingent consideration (as a result of commodity prices) related to prior Gulf of Mexico (GOM) acquisitions. Higher lease operating expense is due to higher production volumes, cost increases from inflationary pressures related to the onshore business, and higher production at the Khaleesi and Mormont assets flowing to the King’s Quay facility. Higher DD&A is a result of higher production volumes, partially offset by lower rates driven by positive reserve revisions primarily in the Eagle Ford Shale. Higher income tax expense is a result of higher pre-tax profits. Canadian E&P operations reported earnings of $41.4 million in the third quarter 2022 compared to income of $73.9 million in the third quarter of 2021. Results were unfavorable $32.5 million compared to the 2021 period primarily due to a credit of $71.8 million reported in 2021 in other operating expense as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project. The current year results also include higher revenues from production ($39.5 million), partially offset by higher lease operating expenses ($6.2 million) and higher tax expense ($9.9 million). Higher revenue is primarily attributable to higher oil and gas prices and higher natural gas volumes at Tupper Montney. Higher lease operating expenses is primarily the result of higher volumes and related gas processing costs. Higher income tax expense is a result of higher pre-tax profits. Other international E&P operations reported a loss from continuing operations of $5.8 million in the third quarter of 2022 compared to a loss of $5.2 million in the third quarter of 2021. The result was $0.6 million unfavorable in the 2022 period versus 2021 primarily due to higher exploration expenses and higher taxes partially offset by higher revenue from Brunei. Nine months 2022 vs. 2021 All amounts include amount attributable to a noncontrolling interest in MP GOM, unless otherwise noted. United States E&P operations reported earnings of $1,225.9 million in the first nine months of 2022 compared to earnings of $481.8 million in the first nine months of 2021. Results were $744.1 million favorable in the 2022 period compared to the 2021 period, driven by higher revenues ($954.6 million) and lower DD&A ($27.0 million), other operating expense ($23.1 million) and exploration expenses ($16.9 million) partially offset by higher income tax expense ($188.4 million), lease operating expenses ($64.9 million) and severance and ad valorem taxes ($15.8 million). Higher revenues are primarily attributable to higher realized prices in 2022 compared to 2021. Lower DD&A is a result of lower rates driven by positive reserve revisions primarily in the Eagle Ford Shale. Lower other operating expenses is primarily due to a lower unfavorable mark to market revaluation on contingent consideration ($98.5 million; as a result of commodity prices increasing less drastically) from prior GOM acquisitions and no repeat of rig standby charges. Lower exploration expenses are due to no repeat of 2021 dry hole costs related to Silverback. Higher income tax expense is a result of higher pre-tax income. Higher lease operating expenses relate to higher production volumes, cost increases from inflationary pressures related to the onshore business, and higher production at the Khaleesi and Mormont assets flowing to the King’s Quay facility. Higher severance and ad valorem taxes are due to higher revenues at Eagle Ford Shale. Canadian E&P operations reported earnings of $111.3 million in the first nine months of 2022 compared to a loss of $37.7 million in the first nine months of 2021. Results were $149.0 million favorable compared to the 2021 period. Prior year results included an impairment charge ($171.3 million) recorded in the first quarter following an asset abandonment notice from the operator of Terra Nova at the time of the assessment and a partially offsetting credit of $71.8 million as of September 30, 2021 reported in other operating expense as a result of the deferral of an asset retirement obligation at Terra Nova following the sanction of an asset life extension project. The current year results also include higher revenue from production ($101.0 million) and lower DD&A ($17.3 million) offset by higher income tax expense ($52.7 million) and lease operating expenses ($13.4 million). Higher revenue is primarily attributable to higher realized prices and higher gas volumes (new wells added in 2022). Lower DD&A is primarily due to lower production volumes at Kaybob Duvernay due to normal well decline. 27 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.) Results of Operations (contd.) Higher income tax expense is a result of higher pre-tax income principally due to higher revenue and no repeat of the impairment charge. Higher lease operating expenses are due to higher gas volumes and higher processing rates. Other international E&P operations reported a loss of $53.5 million in the first nine months of 2022 compared to a loss of $22.5 million in the prior year. Results were $31.0 million unfavorable compared to the 2021 period primarily due to the Cutthroat-1 exploration well in block SEAL-M-428 in the Sergipe-Alagoas Basin offshore Brazil being expensed because no hydrocarbons were discovered. Corporate Third quarter 2022 vs. 2021 Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge/fix the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported income of $57.4 million in the third quarter of 2022 compared to a loss of $98.8 million in the third quarter of 2021. The $156.2 million favorable variance is principally due to current period gains on derivative instruments in the third quarter of 2022 compared to losses in the same 2021 period (2022: $115.2 million gain; 2021: $59.2 million loss) for a favorable variance of $174.4 million. In addition, favorable variances were recorded due to lower interest expense ($10.9 million) and favorable exchange rate gains ($18.3 million) partially offset by higher tax expense ($47.1 million). Realized and unrealized gains on derivative instruments are due to a decrease in oil prices for current (realized) and/or future (unrealized) periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. As of September 30, 2022, the average forward NYMEX WTI price for the remainder of 2022 was $79.11 (versus swap contract fixed hedge price of $44.88). Interest charges are lower in the third quarter of 2022 due to lower overall debt in the period. Higher income tax expense is a result of higher pre-tax gains. Nine months 2022 vs. 2021 Corporate activities, which include interest expense and income, foreign exchange effects, realized and unrealized gains/losses on derivative instruments (forward swaps and collars to hedge the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $363.7 million in the first nine months of 2022 compared to a loss of $577.6 million in the first nine months of 2021. The $213.9 million favorable variance is primarily due to lower losses on derivative instruments in 2022 ($191.1 million) compared to 2021 (2022: $308.7 million loss; 2021: $499.8 million loss), lower interest expense ($62.4 million) and foreign exchange gains ($31.0 million), partially offset by lower tax benefits ($66.6 million). Interest charges are lower in the first nine months of 2022 primarily due to lower overall debt and lower debt redemption premiums ($5.4 million in 2022; $36.8 million in 2021) incurred by the Company in the period. In the first nine months of 2022 the Company reduced debt by $447.6 million compared to the 2021 reduction of $726.4 million. Realized and unrealized losses on derivative instruments are due to an increase in oil prices for current (realized) and future (unrealized) periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price. As of September 30, 2022, the average forward NYMEX WTI price for the remainder of 2022 was $79.11 (versus swap contract fixed hedge price of $44.88). Lower income tax benefit is a result of lower pre-tax losses. Production Volumes and Prices Third quarter 2022 vs. 2021 Total hydrocarbon production from continuing operations averaged 196,243 barrels of oil equivalent per day in the third quarter of 2022, which was 20% higher than the 163,224 barrels per day produced in third quarter 2021. The increase in production is principally due to production from the Khaleesi, Mormont and Samurai field development project that started production in the second quarter of 2022, new well production at Tupper Montney and lower weather related downtime in the third quarter of 2022. Average crude oil and condensate production from continuing operations was 103,386 barrels per day in the third quarter of 2022 compared to 88,245 barrels per day in the third quarter of 2021. The increase of 15,141 barrels per day was associated with higher volumes in the Gulf of Mexico (15,304 barrels per day) principally due to the increased production from the Khaleesi, Mormont, Samurai development as well as lower weather related downtime in the third quarter of 2022. Canada production is lower (2,680 barrels per day) primarily attributable to Kaybob Duvernay well decline and planned downtime at Hibernia. Eagle Ford Shale production is higher (2,329 barrels per day) due to new wells at Karnes and Catarina. On a worldwide basis, the Company’s crude oil and condensate prices averaged $93.56 per barrel in the third quarter 2022 compared to $68.88 per barrel in the 2021 period, an increase of 36% quarter over quarter. 28 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.) Results of Operations (contd.) Total production of natural gas liquids (NGL) from continuing operations was 11,548 barrels per day in the third quarter 2022 compared to 10,391 barrels per day in the 2021 period. The increase of 1,157 barrels per day was associated with higher volumes in the Gulf of Mexico principally due to the increased production from the Khaleesi, Mormont, Samurai development as well as lower weather related downtime in the third quarter of 2022. The average sales price for U.S. NGL was $35.37 per barrel in the 2022 quarter compared to $32.01 per barrel in 2021. The average sales price for NGL in Canada was $54.40 per barrel in the 2022 quarter compared to $45.12 per barrel in 2021. NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets. Natural gas production volumes from continuing operations averaged 487.9 million cubic feet per day (MMCFD) in the third quarter 2022 compared to 387.5 MMCFD in 2021. The increase of 100.3 MMCFD was a result of higher volumes in Canada (82.8 MMCFD) as well as higher volumes in the Gulf of Mexico (19.0 MMCFD). Higher natural gas volumes in Canada are primarily due to bringing online 20 new wells at Tupper Montney since the second quarter of 2022. Natural gas prices for the total Company averaged $3.84 per thousand cubic feet (MCF) in the 2022 quarter, versus $2.78 per MCF average in the same quarter of 2021. Average natural gas prices in the U.S. and Canada in the quarter were $8.34 and $2.75 per MCF, respectively. Average natural gas prices in Canada are lower as a result of certain fixed price sales volume contracts. Nine months 2022 vs. 2021 Total hydrocarbon production from Exploration and Production averaged 173,260 barrels of oil equivalent per day in the first nine months of 2022, which represented a 1.8% increase from the 170,209 barrels per day produced in the first nine months of 2021. The increase is principally due to production from the Khaleesi, Mormont, Samurai field development project that started production in the second quarter of 2022, new wells at Tupper Montney and lower weather related downtime in 2022. Average crude oil and condensate production was 95,275 barrels per day in the first nine months of 2022 compared to 98,314 barrels per day in the first nine months of 2021. The decrease of 3,039 barrels per day was principally due to normal declines partially offset by new production from the Khaleesi, Mormont, Samurai field development project. In addition, Canada production is lower (2,517 barrels per day) due to normal field decline at Kaybob and temporary operational issues at Hibernia. Eagle Ford Shale production is lower (1,470 barrels per day) due to normal well decline partially offset by 2022 new well production. Higher Gulf of Mexico production (475 barrels per day) due to production from the Khaleesi, Mormont, Samurai field development project that started production in the second quarter of 2022, and lower weather related downtime in 2022 partially offset by normal declines. On a worldwide basis, the Company’s crude oil and condensate prices averaged $99.38 per barrel in the first nine months of 2022 compared to $64.19 per barrel in the 2021 period, an increase of 54.8% year over year. Total production of natural gas liquids (NGL) was 10,621 barrels per day in the first nine months of 2022 compared to 10,498 barrels per day in the 2021 period. The average sales price for U.S. NGL was $38.30 per barrel in 2022 compared to $25.63 per barrel in 2021. The average sales price for NGL in Canada was $57.53 per barrel in 2022 compared to $37.05 per barrel in 2021. NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets. Natural gas production volumes averaged 404.2 million cubic feet per day (MMCFD) in the first nine months of 2022 compared to 368.4 MMCFD in 2021. The increase of 35.8 MMCFD was primarily the result of higher volumes in Canada 36.3 MMCFD) and Eagle Ford Shale (1.3 MMCFD), partially offset by the Gulf of Mexico (1.8 MMCFD). The higher natural gas volumes in Canada was the result of new wells on production in the nine months of the year. Natural gas prices for the total Company averaged $3.66 per thousand cubic feet (MCF) in the first nine months of 2022, versus $2.56 per MCF average in the same period of 2021. Average realized natural gas prices in the U.S. and Canada in the quarter were $7.00 per MCF and $2.70 per MCF, respectively. Average realized gas prices in Canada are lower as a result of certain fixed price sales volume contracts. Additional details about results of oil and natural gas operations are presented in the tables on pages 25 and 26. 29 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.) Results of Operations (contd.) The following table reports hydrocarbons produced during the three-month and nine-month periods ended September 30, 2022 and 2021. Three Months Ended September 30, Nine Months Ended September 30, Barrels per day unless otherwise noted 2022 2021 2022 2021 Net crude oil and condensate United States Onshore 28,522 26,193 25,082 26,552 Gulf of Mexico 1 68,315 53,011 62,380 61,905 Canada Onshore 3,891 4,963 4,228 5,598 Offshore 2,171 3,779 2,869 4,016 Other 487 299 716 243 Total net crude oil and condensate - continuing operations 103,386 88,245 95,275 98,314 Net natural gas liquids United States Onshore 5,782 5,847 5,268 5,043 Gulf of Mexico 1 4,780 3,459 4,411 4,296 Canada Onshore 986 1,085 942 1,159 Total net natural gas liquids - continuing operations 11,548 10,391 10,621 10,498 Net natural gas – thousands of cubic feet per day United States Onshore 30,054 31,478 29,032 27,750 Gulf of Mexico 1 65,319 46,339 61,727 63,557 Canada Onshore 392,483 309,709 313,422 277,077 Total net natural gas - continuing operations 487,856 387,526 404,181 368,384 Total net hydrocarbons - continuing operations including NCI 2,3 196,243 163,224 173,260 170,209 Noncontrolling interest Net crude oil and condensate – barrels per day (7,125) (7,546) (7,735) (8,834) Net natural gas liquids – barrels per day (264) (243) (290) (322) Net natural gas – thousands of cubic feet per day 2 (2,202) (2,331) (2,628) (3,498) Total noncontrolling interest (7,756) (8,178) (8,463) (9,739) Total net hydrocarbons - continuing operations excluding NCI 2,3 188,487 155,046 164,797 160,470 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. 30 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.) Results of Operations (contd.) The following table reports the weighted average sales prices excluding transportation cost deductions and sales of purchased natural gas for the three-month and nine-month periods ended September 30, 2022 and 2021. Three Months Ended September 30, Nine Months Ended September 30, 2022 2021 2022 2021 Weighted average Exploration and Production sales prices Continuing operations Crude oil and condensate – dollars per barrel United States Onshore $ 94.33 69.30 $ 99.92 64.16 Gulf of Mexico 1 92.96 68.93 99.04 64.44 Canada 2 Onshore 82.25 63.76 92.31 58.70 Offshore 111.76 72.64 112.93 68.93 Other 117.18 — 92.91 — Natural gas liquids – dollars per barrel United States Onshore 34.33 30.37 36.83 24.29 Gulf of Mexico 1 36.56 34.71 39.99 27.17 Canada 2 Onshore 54.40 45.12 57.53 37.05 Natural gas – dollars per thousand cubic feet United States Onshore 7.62 3.85 6.49 3.23 Gulf of Mexico 1 8.68 4.09 7.23 3.28 Canada 2 Onshore 2.75 2.47 2.70 2.33 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 $1,678.7 million for the first nine months of 2022 compared to $1,091.3 million during the same period in 2021. The increased cash from operating activities of $587.4 million is primarily attributable to higher revenue from production ($1,062.8 million), offset by the timing of working capital settlements ($177.2 million; primarily higher revenue received in cash following the end of the quarter), offset by higher realized losses on derivative instruments ($176.1 million). Cash Required by Investing Activities Net cash required by investing activities was $928.6 million for the first nine months of 2022 compared to $311.9 million during the same period in 2021. In the first nine months of 2022, the Company acquired additional working interest in Kodiak (11.0%) and Lucius (3.4%) for $48.5 million and $77.1 million, respectively (also see Note D). Property additions and dry hole costs (excluding King’s Quay), which include amounts expensed, were $800.9 million and $541.3 million in the first nine months of 2022 and 2021, respectively. The first quarter of 2021 included sales proceeds for the King’s Quay FPS of $267.7 million, which was sold to ArcLight. 31 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.) Financial Condition (contd.) Total accrual basis capital expenditures are shown below. Nine Months Ended September 30, (Millions of dollars) 2022 2021 Capital Expenditures Exploration and production $ 904.1 556.0 Corporate 13.9 12.7 Total capital expenditures $ 918.0 568.7 A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows. Nine Months Ended September 30, (Millions of dollars) 2022 2021 Property additions and dry hole costs per cash flow statements 1 $ 800.9 541.3 Property additions King's Quay per cash flow statements — 17.7 Acquisition of oil and gas properties 1 125.6 22.9 Geophysical and other exploration expenses 20.4 13.3 Capital expenditure accrual changes and other (28.9) (26.6) Total capital expenditures $ 918.0 568.7 1 Certain prior-period amounts have been reclassified to conform to the current period presentation The increase in capital expenditures in the exploration and production business in 2022 compared to 2021 is primarily attributable to expenditures related to the Kodiak and Lucius acquisition in Gulf of Mexi co ($125.6 million), Cutthroat-1 exploration well in Brazil ($25.3 million), higher capital invested at the Khaleesi, Mormont, Samurai field development project in Gulf of Mexico, higher development drilling activities in Eagle Ford Shale and Tupper Montney assets and higher expenditures related to the asset life extension at Terra Nova. Cash Required by Financing Activities Net cash required by financing activities was $785.6 million for the first nine months of 2022 compared to $585.6 million during the same period in 2021. In 2022, the cash used in financing activities was principally for the early redemption of the notes due 2024, 2025, 2028 and 2042 ($446.0 million), payment of contingent consideration related to prior Gulf of Mexico acquisitions ($81.7 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($145.3 million), and cash dividends to shareholders of $0.575 per share ($89.4 million). Subsequent to quarter end, the Company declared a quarterly cash dividend of $0.25 per share, or $1.00 per share on an annualized basis. As of September 30, 2022 and in the eve nt it is required to fund investing activities from borrowings, the Company has $1,546.1 million available on its committed RCF. In first nine months of 2021, the cash used in financing activities was principally for the early redemption of the notes due 2022 and 2024 ($726.4 million ), early redemption cost (make whole payment) of the notes due 2022 ($36.8 million), repayment of the previously outstanding balance on the Company’s unsecured RCF ($200.0 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($100.9 million), and cash dividends to shareholders ($57.9 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($541.9 million). Working Capital Working capital (total current assets less total current liabilities, excluding assets and liabilities held for sale) as of September 30, 2022 was a deficit of $268.5 million, $30.4 million lower than December 31, 2021, with the decrease primarily attributable to higher accounts receivable ($127.0 million) and lower accounts payable ($83.6 million), partially offset by higher other accrued liabilities ($74.9 million), a lower cash balance ($55.2 million) and higher operating lease liabilities ($27.5 million). Higher accounts receivable are principally due to higher crude oil and gas pricing. Lower accounts payable is primarily due to the decrease in unrealized losses on derivative instruments (commodity price swaps and collars) maturing (payable) over the 32 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.) Financial Condition (contd.) remainder of 2022 partially offset by higher revenue payables principally due to higher crude oil and gas pricing. Higher other accrued liabilities are associated with higher short term contingent consideration obligations (from prior Gulf of Mexico acquisitions), due to higher commodity prices and timing of payments. Higher operating lease liabilities are associated with a rig contract to support the Khaleesi, Mormont, Samurai field development project. Capital Employed At September 30, 2022, long-term debt of $2,023.0 million had decreased by $442.4 million compared to December 31, 2021, primarily as a result of the partial repayment of notes due 2024, 2025, 2028 and 2042 ($447.6 million). The total of the fixed-rate notes had a weighted average maturity of 7.5 years and a weighted average coupon of 6.1%. A summary of capital employed at September 30, 2022 and December 31, 2021 follows. September 30, 2022 December 31, 2021 (Millions of dollars) Amount % Amount % Capital employed Long-term debt $ 2,023.0 30.1 % $ 2,465.4 37.2 % Murphy shareholders' equity 4,708.9 69.9 % 4,157.3 62.8 % Total capital employed $ 6,731.9 100.0 % $ 6,622.7 100.0 % Cash and invested cash are maintained in several operating locations outside the United States. As of September 30, 2022, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $95.3 million in Canada. In addition, approximately $25.5 million of cash was held in Brunei, $20.9 million of cash was held in Mexico and $12.5 million of cash was held in the U.K.. 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. Accounting changes and recent accounting pronouncements – see Note B to the Consolidated Financial Statements Outlook As discussed in the Summary section on page 22, several factors have contributed to a lower average crude oil price during the third quarter, which directly impacts the Company’s product revenue from sales (Q3 2022 $91.55; Q2 2022 $108.41; Q3 2021 $70.56). As of close on November 1, 2022, the NYMEX WTI forward curve price for the remainder of 2022 and 2023 were lower at $88.37 and $81.53 per barrel, respectively; however, we cannot predict what impact economic factors (including the ongoing COVID-19 pandemic, exploration and production sector investment, inflation and the Russia/Ukraine conflict) may have on future commodity prices. Lower prices will result in lower profits and operating cash-flows. For the fourth quarter, production is expected to average between 173.5 and 181.5 MBOEPD, excluding noncontrolling interest (NCI). The Company’s capital expenditure spend for 2022 is expected to be between $975.0 million and $1,025.0 million, excluding acquisitions and noncontrolling interest. Capital expenditures and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company plans to fund its remaining capital program in 2022 using operating cash flow and available cash. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects. The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests) in accordance with the Company’s capital allocation framework. Details of the framework can be found as part of the Company’s Form 8-K filed on August 4, 2022. The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the revolving credit facility (see Note F). 33 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.) As of November 1, 2022, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows: Commodity Type Volumes (Bbl/d) Price (USD/Bbl) Remaining Period Area Start Date End Date United States WTI² Fixed price derivative swap 20,000 $44.88 10/1/2022 12/31/2022 Volumes (Bbl/d) Average Put (USD/Bbl) Average Call (USD/Bbl) Remaining Period Area Commodity Type Start Date End Date United States WTI² Derivative collars 25,000 $63.24 $75.20 10/1/2022 12/31/2022 1 West Texas Intermediate Volumes (MMcf/d) Price/Mcf Remaining Period Area Commodity Type Start Date End Date Canada Natural Gas Fixed price forward sales 247 C$2.34 10/1/2022 10/31/2022 Canada Natural Gas Fixed price forward sales 266 C$2.36 11/1/2022 12/31/2022 Canada Natural Gas Fixed price forward sales 269 C$2.36 1/1/2023 3/31/2023 Canada Natural Gas Fixed price forward sales 250 C$2.35 4/1/2023 12/31/2023 Canada Natural Gas Fixed price forward sales 162 C$2.39 1/1/2024 12/31/2024 Canada Natural Gas Fixed price forward sales 45 US$2.05 10/1/2022 12/31/2022 Canada Natural Gas Fixed price forward sales 25 US$1.98 1/1/2023 10/31/2024 Canada Natural Gas Fixed price forward sales 15 US$1.98 11/1/2024 12/31/2024 Forward-Looking Statements This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements are generally identified through the inclusion of words such as “aim”, “anticipate”, “believe”, “drive”, “estimate”, “expect”, “expressed confidence”, “forecast”, “future”, “goal”, “guidance”, “intend”, “may”, “objective”, “outlook”, “plan”, “position”, “potential”, “project”, “seek”, “should”, “strategy”, “target”, “will” or variations of such words and other similar expressions. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement include, but are not limited to: 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 or economies in general. For further discussion of factors that could cause one or more of these future events or results not to occur as implied by any forward-looking statement, see “Risk Factors” in Murphy’s 2021 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission and on page 36 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements. 34 Table of Contents