MURPHY OIL CORP 10-Q

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.) Results of Operations (contd.) Exploration and Production First quarter 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 $252.9 million in the first quarter of 2022 compared to earnings of $119.0 million in the first quarter of 2021. Results were $133.9 million favorable in the 2022 period compared to the 2021 period, driven by higher revenues ($217.1 million), lower DD&A ($23.1 million), lower lease operating expenses (LOE: $16.2 million), partially offset by higher income tax expense ($29.7 million) and higher other operating expense ($81.3 million). Higher revenues are primarily attributable to higher realized prices (oil and condensate, natural gas and NGLs) in 2022 compared to 2021, offset by lower oil sales and production volumes driven primarily by a focused effort to reduce capital expenditures to prioritize corporate debt reduction. Lower DD&A is a result of lower production volumes and lower rates driven by positive reserve revisions. Lower lease operating expenses were primarily due to higher GOM workover costs in the prior year at St. Malo. Higher income tax expense is a result of higher pre-tax income principally due to higher oil price and lower DD&A and LOE. Higher other operating expense is primarily due to an unfavorable mark to market revaluation on contingent consideration ($98.1 million; as a result of higher commodity prices) from prior GOM acquisitions. Canadian E&P operations reported earnings of $22.7 million in the first quarter of 2022 compared to a loss of $124.3 million in the first quarter of 2021. Results were $147.0 million favorable compared to the 2021 period. Prior year results included an impairment charge ($171.3 million) recorded in the first quarter of 2021 following notice from the operator of asset abandonment at Terra Nova at the time of the assessment, and prior to the sanctioning of an asset life extension project in the third quarter of 2021. The current year results also include higher revenue from production ($25.3 million) and lower DD&A ($10.6 million) offset by higher income tax expense ($49.7 million), lease operating expenses ($6.1 million) and transportation, gathering and processing expenses ($3.3 million). Higher revenue is primarily attributable to higher oil prices at Hibernia and Kaybob Duvernay and higher natural gas prices and volumes at Tupper Montney. Lower DD&A is primarily due to lower production volumes at Kaybob Duvernay following reduced capital expenditures throughout 2020 and 2021. 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 oper ating expenses and transportation, gathering and processing costs are due to higher gas processing and downstream transportation rates and capacity. Higher capacity is expected to be utilized by growth at Tupper Montney in the future. Other international E&P operations reported a loss of $44.2 million in the first quarter of 2022 compared to a loss of $6.9 million in the prior year. Results were $37.3 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 First 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 the price of oil sold) and corporate overhead not allocated to Exploration and Production, reported a loss of $296.3 million in the first quarter of 2022 compared to a loss of $254.8 million in the first quarter of 2021. The $41.5 million unfavorable variance is primarily due to higher realized and unrealized losses on derivative instruments in 2022 compared to 2021 (2022: $320.8 million loss; 2021: $214.4 million loss), partially offset by lower interest expense ($56.0 million) and higher tax benefits ($7.8 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 March 31, 2022, the average forward NYMEX WTI price for the remainder of 2022 was $94.52 (versus swap contract fixed hedge price of $44.88). Interest charges are lower in the first quarter of 2022 primarily due the prior year redemption premium ($34.2 million) incurred by the Company upon the early retirement of the notes originally due June and December 2022, lower overall debt and higher capitalized interest on GOM capital projects. Higher income tax benefit is a result of pre-tax losses driven by the higher realized and unrealized losses on derivative instruments. 25 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.) Results of Operations (contd.) Production Volumes and Prices First quarter 2022 vs. 2021 Total hydrocarbon production from Exploration and Production averaged 149,854 barrels of oil equivalent per day in the first quarter of 2022, which represented a 9% decrease from the 165,382 barrels per day produced in the first quarter of 2021. The decrease in production is principally due to an ongoing focused effort to reduce capital expenditures that began in 2020 to prioritize corporate debt reduction. Average crude oil and condensate production was 83,560 barrels per day in the first quarter of 2022 compared to 97,475 barrels per day in the first quarter of 2021. The decrease of 13,915 barrels per day was principally due to lower Gulf of Mexico production (9,110 barrels per day) due to the focused effort to reduce capital expenditures and several planned downtime events including a facility upgrade which lowered current production at Neidermeyer and Marmalard as well as maintenance operations at Front Runner, Habanero and Chinook. Canada production is lower (3,176 barrels per day) due to normal field decline at Kaybob coupled with temporary operational issues at Hibernia. Eagle Ford Shale production is lower (1,835 barrels per day) due to normal well decline and temporary operational issues impacting production in the first quarter of 2022. On a worldwide basis, the Company’s crude oil and condensate prices averaged $95.17 per barrel in the first quarter of 2022 compared to $58.08 per barrel in the 2021 period, an increase of 64% year over year. Total production of natural gas liquids (NGL) was 9,342 barrels per day in the first quarter of 2022 compared to 9,845 barrels per day in the 2021 period. The average sales price for U.S. NGL was $40.76 per barrel in 2022 compared to $22.68 per barrel in 2021. The average sales price for NGL in Canada was $55.02 per barrel in 2022 compared to $35.92 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 341.7 million cubic feet per day (MMCFD) in the first quarter of 2022 compared to 348.4 MMCFD in 2021. The decrease of 6.7 MMCFD was primarily the result of lower volumes in the Gulf of Mexico (16.6 MMCFD) partially offset by higher volumes at Eagle Ford Shale (5.3 MMCFD) and Canada (4.6 MMCFD). The lower natural gas volumes in the Gulf of Mexico are principally due to planned facility and maintenance downtime. Natural gas prices for the total Company averaged $3.13 per thousand cubic feet (MCF) in the first quarter 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 $5.00 and $2.52, 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 page 24. 26 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 periods ended March 31, 2022 and 2021. Three Months Ended March 31, Barrels per day unless otherwise noted 2022 2021 Net crude oil and condensate United States Onshore 20,330 22,165 Gulf of Mexico 1 55,253 64,363 Canada Onshore 4,380 6,288 Offshore 3,321 4,589 Other 276 70 Total net crude oil and condensate - continuing operations 83,560 97,475 Net natural gas liquids United States Onshore 4,833 3,933 Gulf of Mexico 1 3,526 4,679 Canada Onshore 983 1,233 Total net natural gas liquids - continuing operations 9,342 9,845 Net natural gas – thousands of cubic feet per day United States Onshore 27,361 22,016 Gulf of Mexico 1 56,058 72,658 Canada Onshore 258,291 253,697 Total net natural gas - continuing operations 341,710 348,371 Total net hydrocarbons - continuing operations including NCI 2,3 149,854 165,382 Noncontrolling interest Net crude oil and condensate – barrels per day (8,128) (9,174) Net natural gas liquids – barrels per day (287) (354) Net natural gas – thousands of cubic feet per day 2 (2,590) (4,159) Total noncontrolling interest (8,847) (10,221) Total net hydrocarbons - continuing operations excluding NCI 2,3 141,007 155,161 1 Includes net volumes attributable to a noncontrolling interest in MP Gulf of Mexico, LLC (MP GOM). 2 Natural gas converted on an energy equivalent basis of 6:1 3 NCI – noncontrolling interest in MP GOM. 27 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 deduction and sales of purchased natural gas for the three-month periods ended March 31, 2022 and 2021. Three Months Ended March 31, 2022 2021 Weighted average Exploration and Production sales prices Continuing operations Crude oil and condensate – dollars per barrel United States Onshore $ 93.87 57.41 Gulf of Mexico 1 95.02 58.78 Canada 2 Onshore 93.09 52.84 Offshore 110.66 59.39 Natural gas liquids – dollars per barrel United States Onshore 38.32 21.25 Gulf of Mexico 1 44.05 23.87 Canada 2 Onshore 55.02 35.92 Natural gas – dollars per thousand cubic feet United States Onshore 4.61 3.27 Gulf of Mexico 1 5.19 3.39 Canada 2 Onshore 2.52 2.26 1 Prices include the effect of noncontrolling interest share for MP GOM. 2 U.S. dollar equivalent. Financial Condition Cash Provided by Operating Activities Net cash provided by continuing operating activities was $338.3 million for the first three months of 2022 compared to $237.8 million during the same period in 2021. The increased cash from operating activities is primarily attributable to higher revenue from production ($242.0 million), offset by the timing of working capital settlements ($80.9 million; primarily higher revenue received in cash following the end of the quarter) and higher realized losses on derivative instruments ($71.4 million). Cash Required by Investing Activities Net cash required by investing activities was $244.9 million for the first three months of 2022 compared to net cash provided by investing activities of $9.7 million during the same period in 2021. The first quarter of 2021 included sales proceeds for the King’s Quay FPS of $268.0 million, which was sold to ArcLight Capital Partners, LLC (ArcLight). Property additions and dry hole costs (excluding King’s Quay), which includes amounts expensed, were $244.9 million and $240.5 million in the first three months of 2022 and 2021, respectively. Total accrual basis capital expenditures were as follows: Three Months Ended March 31, (Millions of dollars) 2022 2021 Capital Expenditures Exploration and production $ 299.4 247.3 Corporate 5.3 3.8 Total capital expenditures $ 304.7 251.1 A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows. 28 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.) Financial Condition (contd.) Three Months Ended March 31, (Millions of dollars) 2022 2021 Property additions and dry hole costs per cash flow statements $ 244.9 240.5 Property additions King's Quay per cash flow statements — 17.7 Geophysical and other exploration expenses 9.4 5.8 Capital expenditure accrual changes and other 50.4 (13.0) Total capital expenditures $ 304.7 251.1 The increase in capital expenditures in the exploration and production business in 2022 compared to 2021 is primarily attributable to expenditures related to the Cutthroat-1 exploration well in Brazil, capital invested at the Khaleesi, Mormont, Samurai field development project and higher development drilling activities in Tupper Montney and Kaybob Duvernay assets. Cash Required by Financing Activities Net cash required by financing activities was $133.9 million for the first three months of 2022 compared to $327.8 million during the same period in 2021. In 2022, the cash used in financing activities was principally for payment of contingent consideration related prior Gulf of Mexico acquisitions ($55.2 million), distributions to the non-controlling interest (NCI) in the Gulf of Mexico ($39.9 million), and cash dividends to shareholders of $0.15 per share ($23.3 million). Subsequent to quarter end, the Company declared a quarterly cash dividend of $0.175 per share, or $0.70 per share on an annualized basis. This amount represents a 17% increase from the first quarter of 2022 and a 40% increase from fourth quarter 2021. As of March 31, 2022 and in the event it is required to fund investing activities from borrowings, the Company has $1,568.6 million available on its committed RCF. In first three months of 2021, the cash used in financing activities was principally for the early redemption of the notes due 2022 ($576.4 million ), early redemption cost of the notes due 2022 ($34.2 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 ($36.0 million), and cash dividends to shareholders ($19.3 million), partially offset by the issuance of new notes due 2028, net of debt issuance cost ($542.0 million). Working Capital Working capital (total current assets less total current liabilities, excluding assets and liabilities held for sale) as of March 31, 2022 was a deficit of $654.5 million, $355.7 million lower than December 31, 2021, with the decrease p rimarily attributable to higher accounts payable ($316.8 million), higher other accrued liabilities ($80.5 million), a lower cash balance ($40.6 million) and higher operating lease liabilities ($34.5 million), partially offset by higher accounts receivable ($113.7 million). Higher accounts payable is primarily due to the increase in unrealized losses on derivative instruments (commodity price swaps and collars) maturing over the remainder of 2022. Higher other accrued liabilities are associated with higher contingent consideration obligations due to higher commodity prices (from prior Gulf of Mexico acquisitions). Higher operating lease liabilities are associated with a rig contract to support the Khaleesi, Mormont, Samurai field development project which will utilize the King’s Quay FPS. Higher accounts receivable are principally due to higher crude oil pricing. Capital Employed At March 31, 2022, long-term debt of $2,466.1 million had increased by $0.7 million compared to December 31, 2021, 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 6.2%. 29 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (contd.) Financial Condition (contd.) A summary of capital employed at March 31, 2022 and December 31, 2021 follows. March 31, 2022 December 31, 2021 (Millions of dollars) Amount % Amount % Capital employed Long-term debt $ 2,466.1 37.9 % $ 2,465.4 37.2 % Murphy shareholders' equity 4,032.8 62.1 % 4,157.3 62.8 % Total capital employed $ 6,499.0 100.0 % $ 6,622.7 100.0 % Cash and invested cash are maintained in several operating locations outside the United States. As of March 31, 2022, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $144.3 million in Canada. In addition, approximately $28.4 million of cash was held in Brazil. 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 21, several factors continue to provide upward pressure to the average crude oil price, which directly impacts the Company’s product revenue from sales (Q1 2022: $94.29; Q1 2021: $57.84; Q4 2021: $77.19). As of close on May 2, 2022, the NYMEX WTI forward curve price for the remainder of 2022 and 2023 were $99.44 and $86.38 per barrel, respectively; however we cannot predict what impact economic factors (including the ongoing COVID-19 pandemic, exploration and production sector investment and the Russia/Ukraine conflict) may have on future commodity prices. Lower prices, should they occur, will result in lower profits and operating cash-flows. For the second quarter, production is expected to average between 156.0 and 164.0 MBOEPD, excluding noncontrolling interest (NCI). The Company’s capital expenditure spend for 2022 is expected to be between $900.0 million and $950.0 million. The increase from the original 2022 guidance of $840.0 million to $890.0 million is principally a result of inflationary pressures, scope changes and rig standby costs related to the Cutthroat-1 exploration well in Brazil. 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) to repay outstanding debt. 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). As of May 2, 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 WTI ¹ Fixed price derivative swap 20,000 $44.88 4/1/2022 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 WTI ¹ Derivative collars 25,000 $63.24 $75.20 4/1/2022 12/31/2022 1 West Texas Intermediate 30 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.) Volumes (MMcf/d) Price/Mcf Remaining Period Area Commodity Type Start Date End Date Montney Natural Gas Fixed price forward sales 176 C$2.34 4/1/2022 4/30/2022 Montney Natural Gas Fixed price forward sales 205 C$2.34 5/1/2022 5/31/2022 Montney Natural Gas Fixed price forward sales 247 C$2.34 6/1/2022 10/31/2022 Montney Natural Gas Fixed price forward sales 266 C$2.36 11/1/2022 12/31/2022 Montney Natural Gas Fixed price forward sales 269 C$2.36 1/1/2023 3/31/2023 Montney Natural Gas Fixed price forward sales 250 C$2.35 4/1/2023 12/31/2023 Montney Natural Gas Fixed price forward sales 162 C$2.39 1/1/2024 12/31/2024 Montney Natural Gas Fixed price forward sales 45 US$2.05 4/1/2022 12/31/2022 Montney Natural Gas Fixed price forward sales 25 US$1.98 1/1/2023 10/31/2024 Montney Natural Gas Fixed price forward sales 15 US$1.98 11/1/2024 12/31/2024 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 33 of this Form 10-Q report. Murphy undertakes no duty to publicly update or revise any forward-looking statements. 31 Table of Contents