MURPHY OIL CORP 10-Q

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED) Results of Operations (Continued) Exploration and Production First 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 $226.0 million in the first quarter of 2023 compared to earnings of $252.9 million in the first quarter of 2022. Results were $26.9 million unfavorable in the 2023 period compared to the 2022 period primarily due to lower revenues ($25.1 million), higher lease operating expenses ($62.7 million) and higher depreciation, depletion and amortization expense (DD&A) ($33.8 million), partially offset by lower other operating expense ($93.4 million). Lower revenues were primarily due to lower realized prices, partially offset by higher sales volumes from the Gulf of Mexico primarily related to new wells from the Khaleesi, Mormont and Samurai development project. Higher lease operating expenses were primarily due to increased production volumes and additional costs associated with workover and maintenance from the Gulf of Mexico operations. Higher DD&A was primarily the result of higher production volumes from the Gulf of Mexico, partially offset by lower volumes at Eagle Ford Shale. Lower other operating expense was due to a lower unfavorable contingent consideration adjustment of $3.9 million in 2023 (2022: $98.1 million) as a result of meeting contractual thresholds or reaching time limitations that ended in 2022 (see N ote K) . Canadian E&P operations reported earnings of $21.9 million in the first quarter of 2023 compared to earnings of $22.7 million in the first quarter of 2022. Results were unfavorable $0.8 million compared to the 2022 period primarily due to lower revenues ($10.3 million), partially offset by lower selling and general expense (G&A) ($2.8 million) and lower DD&A ($2.6 million). Lower revenues were due to lower pricing and sales volumes at Kaybob Duvernay and Hibernia, partially offset by higher natural gas production volumes and pricing at Tupper Montney. Lower G&A was primarily due to lower incentive expenses in the current year. Lower DD&A was the result of lower production volumes at Kaybob Duvernay, partially offset by higher production volumes at Tupper Montney. Other international E&P operations reported a loss from continuing operations of $5.2 million in the first quarter of 2023 compared to a loss of $44.2 million in the first quarter of 2022. The result was $39.0 million favorable in the 2023 period versus the 2022 period primarily due to lower exploration expenses ($34.5 million) mainly resulting from lower dry hole costs in the current period and higher revenues from Brunei ($3.6 million). Corporate First 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 $28.7 million in the first quarter of 2023 compared to a loss of $296.3 million in same period of 2022. The $267.6 million favorable variance was principally due to no current period losses on derivative instruments in the first quarter of 2023 compared to a loss for the same period in 2022 of $320.8 million. Realized and unrealized losses on derivative instruments are due to an increase in market pricing in future periods whereby the swap contracts provide the Company with a fixed price and the collar contracts provide for a minimum (floor) and a maximum (ceiling) price, with variability in between the floor and ceiling. During the first quarter of 2023 and as of March 31, 2023, the Company did not enter into or have any fixed price derivative swaps or collar contracts outstanding. Favorable variances were also recorded due to lower interest expense resulting from overall lower debt levels ($8.4 million) and favorable G&A primarily due to lower current period incentive related expenses ($8.4 million), partially offset by lower income tax benefit ($72.0 million). Lower income tax benefit was a result of lower pre-tax losses. Production Volumes and Prices First quarter 2023 vs. 2022 Total hydrocarbon production from continuing operations averaged 179,745 barrels of oil equivalent per day in the first quarter of 2023, which was 20% higher than the 149,854 barrels per day produced in first quarter of 2022. The increase in production was principally due to increased production from the Gulf of Mexico primarily attributable to the Khaleesi, Mormont and Samurai field development project starting production in Q2 2022 as well as higher production from Canada Onshore, related primarily to new wells at Tupper Montney. 23 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED) Results of Operations (Continued) Average crude oil and condensate production from continuing operations was 100,987 barrels per day in the first quarter of 2023 compared to 83,560 barrels per day in the first quarter of 2022. The increase of 17,427 barrels per day was associated with higher volumes in the Gulf of Mexico (20,446 barrels per day) principally due to production from the Khaleesi, Mormont, Samurai field development project, that started production in the second quarter of 2022. In addition, Canada production was lower (1,959 barrels per day) primarily attributable to Kaybob Duvernay well decline and lower production volumes at Hibernia, due to higher operational downtime. Eagle Ford Shale production was lower (1,053 barrels per day) due to normal well decline primarily at Tilden. On a worldwide basis, the Company’s crude oil and condensate prices averaged $73.80 per barrel in the first quarter of 2023 compared to $95.17 per barrel in the same period of 2022 period, representing a decrease of 22%. Total production of natural gas liquids (NGL) from continuing operations was 11,325 barrels per day in the first quarter of 2023 compared to 9,342 barrels per day in the first quarter of 2022. The increase of 1,983 barrels per day was associated with higher volumes in the Gulf of Mexico principally due to production from the Khaleesi, Mormont, Samurai field development project that had not yet started producing in the first quarter of 2022. The average sales price for U.S. NGL was $24.23 per barrel in the first quarter of 2023 compared to $40.76 per barrel in the same period of 2022. The average sales price for NGL in Canada was $46.59 per barrel in the first quarter of 2023 compared to $55.02 per barrel in the same period of 2022. NGL prices are higher in Canada due to the higher value of the product at the Kaybob Duvernay and Placid Montney assets. Natural gas production volumes from continuing operations averaged 404.6 million cubic feet per day (MMCFD) in the first quarter of 2023 compared to 341.7 MMCFD in the first quarter 2022. The increase of 62.9 MMCFD was a result of higher volumes in Canada (46.9 MMCFD) as well as higher volumes in the Gulf of Mexico (19.1 MMCFD). Higher natural gas volumes in Canada are primarily due to bringing online 25 new wells at Tupper Montney since the first quarter of 2022, partially offset by normalized royalty rates in the first quarter of 2023. Royalty rates in the first quarter of 2022 were lower due to royalty infrastructure credits received. The higher natural gas volumes in the Gulf of Mexico primarily related to increased production from the Khaleesi, Mormont, Samurai field development project as production began during the second quarter of 2022. Natural gas prices for the total Company averaged $2.68 per thousand cubic feet (MCF) in the first quarter of 2023, versus $3.13 per MCF average in the same period of 2022. Average natural gas prices in the U.S. and in Canada for the first quarters of 2023 and 2022 were $3.08 and $2.55 per MCF, respectively. Additional details about results of oil and natural gas operations are presented in the tables on page 25 . 24 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED) Results of Operations (Continued) The following table contains hydrocarbons produced during the three-month periods ended March 31, 2023 and 2022. Three Months Ended March 31, (Barrels per day unless otherwise noted) 2023 2022 Net crude oil and condensate United States Onshore 19,277 20,330 Gulf of Mexico 1 75,699 55,253 Canada Onshore 3,283 4,380 Offshore 2,459 3,321 Other 269 276 Total net crude oil and condensate - continuing operations 100,987 83,560 Net natural gas liquids United States Onshore 4,157 4,833 Gulf of Mexico 1 6,342 3,526 Canada Onshore 826 983 Total net natural gas liquids - continuing operations 11,325 9,342 Net natural gas – thousands of cubic feet per day United States Onshore 24,160 27,361 Gulf of Mexico 1 75,203 56,058 Canada Onshore 305,232 258,291 Total net natural gas - continuing operations 404,595 341,710 Total net hydrocarbons - continuing operations including NCI 2,3 179,745 149,854 Noncontrolling interest Net crude oil and condensate – barrels per day (6,613) (8,128) Net natural gas liquids – barrels per day (232) (287) Net natural gas – thousands of cubic feet per day (2,354) (2,590) Total noncontrolling interest 3 (7,237) (8,847) Total net hydrocarbons - continuing operations excluding NCI 2,3 172,508 141,007 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. 25 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED) Results of Operations (Continued) The following table contains the weighted average sales prices excluding transportation cost deduction for the three-month periods ended March 31, 2023 and 2022. Three Months Ended March 31, 2023 2022 (Weighted average Exploration and Production sales prices) Continuing operations Crude oil and condensate – dollars per barrel United States Onshore $ 74.98 $ 93.87 Gulf of Mexico 1 73.27 95.02 Canada 2 Onshore 74.29 93.09 Offshore 77.93 110.66 Other 89.05 – Natural gas liquids – dollars per barrel United States Onshore 22.11 38.32 Gulf of Mexico 1 25.63 44.05 Canada 2 Onshore 46.59 55.02 Natural gas – dollars per thousand cubic feet United States Onshore 2.51 4.61 Gulf of Mexico 1 3.27 5.19 Canada 2 Onshore 2.55 2.52 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 $279.8 million for the three months ended March 31, 2023 compared to $338.3 million during the same period in 2022. The decreased cash from operating activities of $58.5 million was primarily attributable to payments of contingent consideration related to prior Gulf of Mexico acquisition in the first quarter of 2023 ($124.0 million), lower revenue from production ($38.3 million), and higher lease operating expenses ($63.2 million), offset by lower realized losses on derivative instruments ($132.3 million), lower G&A ($15.2 million) and the timing of working capital settlements ($5.9 million). Payments of contingent consideration are shown both in operating activities and financing activities in the Company’s Consolidated Statement of Cash Flows; amounts considered as financing activities are those amounts paid up to the original estimated contingent consideration liability included in the purchase price allocation, at the time of acquisition. Any contingent consideration paid above the original estimated liability, included in the purchase price, are considered operating activities. During the three months ended March 31, 2023, the Company paid a total of $171.7 million in contingent consideration, of which $124.0 million is shown in operating activities and $47.7 million is shown in financing activities. The remaining $25.0 million contingent consideration liability balance as of March 31, 2023, was paid in April 2023. Cash Required by Investing Activities Net cash required by investing activities, including amount expensed, was $345.3 million for the three months ended March 31, 2023 compared to $244.9 million during the same period in 2022. 26 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED) Financial Condition (Continued) Total accrual basis capital expenditures are shown below. Three Months Ended March 31, (Millions of dollars) 2023 2022 Capital Expenditures Exploration and production $ 329.7 $ 299.4 Corporate 6.3 5.3 Total capital expenditures $ 336.0 $ 304.7 A reconciliation of “Property additions and dry hole costs” in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows. Three Months Ended March 31, (Millions of dollars) 2023 2022 Property additions and dry hole costs per cash flow statements $ 345.3 $ 244.9 Geophysical and other exploration expenses 4.9 9.4 Capital expenditure accrual changes and other (14.2) 50.4 Total capital expenditures $ 336.0 $ 304.7 The increase in capital expenditures in the exploration and production business in three months ended March 31, 2023 compared to the same period in 2022 was primarily attributable to development drilling activities at Eagle Ford Shale assets, development drilling at Samurai and St. Malo fields and Oso exploration drilling at Other Offshore. In the first quarter of 2023, drilling of the Oso well was temporarily suspended prior to reaching the objective. The Company plans to return to the well in the third quarter of 2023. Cash Required by Financing Activities Net cash required by financing activities was $114.7 million for the three months ended March 31, 2023 compared to $133.9 million during the same period in 2022. In 2023, the cash used in financing activities was principally for the payment of contingent consideration related to prior Gulf of Mexico acquisitions ($47.7 million) as discussed the “Cash Required by Operating Activities” section, cash dividends to shareholders of $0.275 per share ($42.9 million) and distributions to the non-controlling interest in the Gulf of Mexico ($9.7 million). Subsequent to quarter end, the Company declared a quarterly cash dividend of $0.275 per share, or $1.10 per share on an annualized basis. As of March 31, 2023 and in the event it is required to fund investing activities from borrowings, the Company has $769.7 million available on its committed RCF. Working Capital As of March 31, 2023, working capital (total current assets less total current liabilities) amounted to a net working capital liability of $226.2 million, $59.3 million lower than December 31, 2022, with the favorable decrease primarily attributable to lower other accrued liabilities ($225.5 million) and lower accounts payable ($26.9 million), partially offset by a lower cash balance ($179.6 million) and higher operating lease liabilities ($19.0 million). Lower accrued liabilities are primarily due to payments made for contingent consideration obligation from prior Gulf of Mexico acquisitions and incentive payments made in the first quarter of 2023. Lower accounts payable was primarily due to the decrease in unrealized losses on derivative instruments (commodity price swaps and collars), as there were no commodity derivative instrument contracts outstanding during the first quarter of 2023. Higher current operating lease liabilities are associated with scheduled rate increases for a drilling vessel resulting in additional amounts being reclassified from long-term to current operating lease liabilities. Capital Employed At March 31, 2023, long-term debt of $1,823.0 million had increased by $0.5 million compared to December 31, 2022, primarily as a result of normal debt issuance cost amortization. The total of the fixed-rate notes had a weighted average maturity of 7.5 years and a weighted average coupon of 6.2%. 27 Table of Contents ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (CONTINUED) Financial Condition (Continued) A summary of capital employed at March 31, 2023 and December 31, 2022 follows. March 31, 2023 December 31, 2022 (Millions of dollars) Amount % Amount % Capital employed Long-term debt $ 1,823.0 26.2 % $ 1,822.4 26.7 % Murphy shareholders' equity 5,137.6 73.8 % 4,994.8 73.3 % Total capital employed $ 6,960.5 100.0 % $ 6,817.2 100.0 % Cash and invested cash are maintained in several operating locations outside the U.S. As of March 31, 2023, cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $100.0 million, the majority of which was held in Canada ($49.2 million), U.K. ($13.1 million), Mexico ($10.9 million) and Brunei ($10.3 million). 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 19 , several factors have contributed to a lower average crude oil price during the first quarter of 2023, which directly impacts the Company’s product revenue from sales (Q1 2023 $76.13; Q4 2022 $82.65; Q1 2022 $94.29 ). As of close on May 1, 2023, the NYMEX WTI forward curve prices for the remainder of 2023 and 2024 were lower at $74.52 and $70.76 per barrel, respectively; however, we cannot predict what impact economic factors (including inflation, the Russia/Ukraine conflict and possible economic recession) may have on future commodity pricing. Lower prices, should they occur, will result in lower profits and operating cash-flows. For the second quarter of 2023, production is expected to average between 173.0 and 181.0 MBOEPD, excluding noncontrolling interest. The Company’s capital expenditure spend for 2023 is expected to be between $875.0 million and $1,025.0 million, excluding noncontrolling interest. Capital and other expenditures are routinely reviewed and planned capital expenditures may be adjusted to reflect differences between budgeted and forecast cash flow during the year. Capital expenditures may also be affected by asset purchases or sales, which often are not anticipated at the time a budget is prepared. The Company will primarily fund its capital program in 2023 using operating cash flow and available cash. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or borrowings under available credit facilities might be required during the year to maintain funding of the Company’s ongoing development projects. The Company plans to utilize surplus cash (not planned to be used by operations, investing activities, dividends or payment to noncontrolling interests) in accordance with the Company’s capital allocation framework. Details of the framework can be found in the “Capital Allocation Framework” section of the Company’s Form 8-K filed on August 4, 2022. The Company continues to monitor the impact of commodity prices on its financial position and is currently in compliance with the covenants related to the RCF (see Note E ). As of May 1, 2023, the Company has entered into forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as follows: 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 4/1/2023 12/31/2023 Canada Natural Gas Fixed price forward sales 162 C$2.39 1/1/2024 12/31/2024 Canada Natural Gas Fixed price forward sales 25 US$1.98 4/1/2023 10/31/2024 Canada Natural Gas Fixed price forward sales 15 US$1.98 11/1/2024 12/31/2024 28 Table of Contents 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, 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 31 of this Form 10-Q report, and any subsequent Quarterly Report on Form 10-Q or Current Report on Form 8-K that we file, available from the SEC’s website and from Murphy Oil Corporation’s website at http://ir.murphyoilcorp.com. Investors and others should note that we may announce material information using SEC filings, press releases, public conference calls, webcasts and the investors page of our website. We may use these channels to distribute material information about the Company; therefore, we encourage investors, the media, business partners and others interested in the Company to review the information we post on our website. The information on our website is not part of, and is not incorporated into, this report. Murphy Oil Corporation undertakes no duty to publicly update or revise any forward-looking statements. 29 Table of Contents