MURPHY OIL CORP (MUR) FY 2023 MD&A

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read together with the consolidated financial statements and accompanying notes to consolidated financial statements, which are included in Item 8 of this Annual Report on Form 10-K. This MD&A includes forward-looking statements that involve certain risks and uncertainties. See Forward-Looking Statements at the end of this section and Risk Factors under Item 1A. Discussion and analysis of 2021 results and year-over-year comparisons between 2022 and 2021 are not included in this Form 10-K and can be found in Item 7 of the 2022 Annual Report on Form 10-K available via the SEC’s website at www.sec.gov and on our website at www.murphyoilcorp.com.

Murphy Oil Corporation is a worldwide oil and gas exploration and production company with both onshore and offshore operations and properties. The Company produces crude oil, natural gas and natural gas liquids primarily in the U.S. and Canada and explores for crude oil, natural gas and natural gas liquids in targeted areas worldwide. A more detailed description of the Company’s significant assets can be found in Item 1 of this Form 10-K report.

The analysis and discussion in this section includes amounts attributable to a noncontrolling interest in MP GOM, unless otherwise noted.

Significant Company financial and operational highlights during 2023 were as follows:

•Generated net income of $661.6 million and net cash provided by operating activities of $1,748.8 million;

•Produced 193 thousand barrels of oil equivalent (BOE) per day (186 thousand excluding noncontrolling interest, NCI);

•Sanctioned the Lac Da Vang field development project in Vietnam;

•Enhanced exploration portfolio with signing production sharing contracts for five blocks in Côte d’Ivoire;

•Drilled a discovery at the Longclaw #1 operated exploration well in Green Canyon 433 in the Gulf of Mexico;

•Acquired an 8% working interest in the non-operated Zephyrus discovery in the Gulf of Mexico for a purchase price of approximately $13 million, net of closing adjustments;

•Resumed operations at non-operated Terra Nova field in offshore Canada during the fourth quarter of 2023, with production ramping up through first quarter 2024;

•Advances made under the capital allocation framework1:

◦Early debt retirement of approximately $500 million, a 27% debt reduction in the year

◦Repurchased shares of common stock under the share repurchase program for $150 million, excluding excise taxes, commissions and fees

◦Increased cash dividends by 10% since the fourth quarter of 2022 to $0.275 per share, or $1.10 per share annualized

•Achieved 134% (139% excluding NCI) total proved reserve replacement with year-end proved reserves of 739.5 million barrels of oil equivalent (724.0 million excluding NCI).

1 Details of the capital allocation framework can be found as part of the Company’s Form 8-K filed on August 4, 2022. On October 30, 2023, the initial share repurchase program of $300 million of the Company’s common stock was increased by an additional $300 million, bringing the total amount allowed to be repurchased under the program to $600 million.

32

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Murphy’s continuing operations generate revenue by producing crude oil, natural gas liquids, and natural gas in the United States and Canada and then selling these products to customers. The Company’s revenue is affected by the prices of crude oil, natural gas and natural gas liquids. In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products and expenses related to exploration, administration and capital borrowing from lending institutions and note holders.

For the year ended December 31, 2023, the Company’s net income from continuing operations was $725.2 million, a decrease of $415.6 million compared to 2022. Lower net income from continuing operations was largely driven by lower revenues and other income ($472.5 million), higher lease operating expenses ($105.1 million) and higher exploration expenses ($101.6 million), partially offset by lower other operating expense ($91.0 million) and lower income tax expense ($113.5 million). Lower revenues and other income resulted from overall lower pricing partially offset by overall higher sales volumes and lower losses on derivative instruments. Higher lease operating expenses were related to higher sales volumes as well as additional costs for workover and maintenance activities at Gulf of Mexico operations. Higher exploration costs were the result of dry hole expense for the Chinook #7 (Walker Ridge 425) and Oso #1 (Atwater Valley 138) exploration wells, that did not find commercial hydrocarbons in the Gulf of Mexico, the purchase of seismic data for Côte d’Ivoire, and the expensing of previously suspended exploration costs for the Cholula-1EXP well in Mexico. No losses were recorded in 2023 on derivative instruments as no fixed price derivative swaps or collar contracts were in effect during the period. Lower other expenses were due to lower contingent consideration adjustments relating to prior acquisitions in the Gulf of Mexico. Lower income tax expense was the result of lower pre-tax income.

For the year ended December 31, 2023, total hydrocarbon production was 192,640 barrels of oil equivalent per day, an increase of 10% compared to 2022. The increase was principally due to new well production volumes in the Gulf of Mexico from the Khaleesi, Mormont, Samurai field development project, new well production from Tupper Montney and lower royalty rates, partially offset by lower production volumes at other fields in the Gulf of Mexico due to additional downtime.

Results of Operations

Murphy’s Net income (loss) by type of business and geographic segment is presented below.

1 The Company has presented its former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.

E&P Continuing Operations: 2023 vs 2022

The following section of Exploration and Production (E&P) continuing operations excludes the Corporate segment, unless otherwise noted.

Please also refer to Schedule 6 – Results of Operations for Oil and Natural Gas Producing Activities in the Supplemental Oil and Natural Gas Information section for additional supporting tables.

33

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The following are summarized income statements for E&P continuing operations.

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

Pricing

The following table contains the weighted average sales prices for the three years ended December 31, 2023.

1  Prices include the effect of noncontrolling interest in MP GOM.

2 U.S. dollar equivalent.

34

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The following table contains benchmark prices relevant to the Company for the three years ended December 31, 2023.

Production Volumes

The following table contains hydrocarbons produced during the three years ended December 31, 2023. For further discussion on volumes, please see Revenues from Production section on page 37.

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.

4 December 31, 2023, 2022 and 2021, include 15.5 MMBOE, 18.2 MMBOE and 18.4 MMBOE, respectively, relating to

noncontrolling interest.

35

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Sales Volumes

The following table contains hydrocarbons sold during the three years ended December 31, 2023. For further discussion on volumes, please see Revenues from Production section on page 37.

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.

36

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Revenues from Production

The Company’s production revenues by country and product were as follows:

Revenues from production in 2023 decreased by $661.9 million compared to 2022. Lower revenues from U.S. E&P was primarily attributable to lower realized prices in 2023 compared to 2022, partially offset by higher overall sales volumes from the Gulf of Mexico. Higher sales volumes were driven by new well performance from the Khaleesi, Mormont, Samurai field development project, and were partially offset by lower sales volumes at other fields. Lower revenues from Canadian E&P was primarily attributable to lower realized prices and lower sales volumes at Kaybob Duvernay partially offset by higher sales volumes at Tupper Montney. Lower sales volumes at Kaybob Duvernay were primarily due to the divestment of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets, as well as natural declines. Higher sales volumes at Tupper Montney were the result of new wells coming online in 2023, improved well performance, and lower royalty rates.

Natural gas is purchased and subsequently sold to third parties in order to provide operational flexibility and cost mitigation for transportation commitments. Sales of purchase natural gas is included in “Total revenues and other income” and cost to purchase natural gas is included in “Costs and Expenses” in the summarized income statements for E&P continuing operations on page 34.

Other Income

Other income was $8.0 million in 2023, a decrease of $18.7 million compared to 2022. Lower other income was primarily the result of a gain on sale of the Thunder Hawk field in the third quarter of 2022.

37

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Lease Operating and Transportation, Gathering and Processing Expenses

The Company’s total lease operating expenses and transportation, gathering and processing expenses by geographic area were as follows:

Lease operating expenses and transportation, gathering and processing expenses in 2023 increased by $105.1 million and $20.3 million, respectively, compared to 2022. Higher lease operating expenses and increased transportation, gathering and processing expenses from U.S. E&P were primarily due to increased sales volumes and higher operating expenses for additional workover and maintenance activities from the Gulf of Mexico operations.

Depreciation, Depletion and Amortization Expense

The Company’s depreciation, depletion and amortization expense by geographic area were as follows:

Depreciation, depletion and amortization expense (DD&A) in 2023 increased by $86.6 million compared to 2022. Higher DD&A was primarily the result of higher sales volumes and higher rates from the Gulf of Mexico. DD&A from Canadian E&P increased at Tupper Montney due to higher sales volumes and higher rates, substantially offset by lower sales volumes and lower rates at Kaybob Duvernay.

38

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Exploration Expenses

The Company’s exploration expenses were as follows:

Exploration expenses in 2023 increased by $101.7 million compared to 2022. Higher dry holes and previously suspended exploration costs primarily relate to the dry hole expense of Chinook #7 (Walker Ridge 425) and Oso #1 (Atwater Valley 138) exploration wells in the Gulf of Mexico, which encountered non-commercial hydrocarbons, and the write-off of previously suspended exploration costs for the Cholula-1EXP well in Mexico. Higher geological and geophysical expenses in 2023 relate to the purchased seismic data for Côte d’Ivoire. In 2022, dry holes and previously suspended exploration costs primarily relate to expensed costs for the Cutthroat-1 exploration well in block SEAL-M-428 in offshore Brazil and the Tulum-1EXP exploration well in Block 5 in offshore Mexico that did not encounter commercial hydrocarbons.

Other Expenses

Other expenses were $56.9 million in 2023, a decrease of $84.9 million compared to 2022. Other expenses were lower primarily due to a lower unfavorable contingent consideration adjustment of $7.1 million in 2023 (2022: $78.3 million), as a result of reaching contractual thresholds or time limitations that ended in 2022 (see Note O). In addition, there were lower asset retirement adjustments related to non-producing fields of $18.2 million in 2023 (2022: $35.0 million).

Income Taxes

Income taxes were $237.8 million in 2023, a decrease of $179.5 million compared to 2022. Lower income taxes were primarily the result of lower pre-tax income (see Note H).

Corporate: 2023 vs 2022

Corporate activities 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 E&P. Realized and unrealized losses on derivative instruments would result from increases in market oil prices relating to future periods whereby the swap contracts provided the Company with a fixed price, and the collar contracts provided for a minimum (floor) and a maximum (ceiling) price, with variability in between the floor and ceiling.

Corporate activities reported a loss of $156.0 million in 2023, a favorable variance of $282.2 million compared to 2022. The favorable variance was primarily due to no current period losses on derivative instruments in 2023, compared to a loss for the same period in 2022 ($320.4 million) and lower interest expense ($38.6 million), partially offset by lower income tax benefits ($66.0 million) and foreign exchange loss of $10.7 million in 2023 compared to foreign exchange gain of $23.0 million in 2022. Interest charges are lower in 2023 primarily due to lower overall debt levels as the Company reduced debt by $498.2 million and $647.7 million during 2023 and 2022, respectively. During 2023 and as of December 31, 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.

39

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

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 RCF. 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.

Cash Flows

The following table presents the Company’s cash flows for the periods presented.

Cash Provided by Continuing Operations Activities

Net cash provided by continuing operations activities in 2023 was $431.4 million lower compared to 2022. The decrease was primarily attributable to lower revenue from production ($661.9 million), higher payments of contingent consideration related to prior Gulf of Mexico acquisitions ($139.6 million), higher lease operating expenses ($105.1 million) and timing of working capital settlements ($33.6 million), partially offset by lower realized losses on derivative instruments ($535.2 million). Payments of contingent consideration are shown both in “Operating Activities” and “Financing Activities” in the Company’s Consolidated Statements 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 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 Statements of Cash Flows. As of the end of the second quarter of 2023, the Company had no further obligation payable for contingent consideration relating to prior Gulf of Mexico acquisitions. See Note O for further details.

The total reductions of operating cash flows for interest paid (which excludes debt redemption costs reported in “Financing Activities”) during the two years ended December 31, 2023, and 2022 were $108.9 million and $150.0 million, respectively. Lower cash interest paid in 2023 was primarily due to the early redemption, in whole or in part, of the 5.75% senior notes due 2025 (2025 Notes), the 5.875% senior notes due 2027 (2027 Notes), the 6.375% senior notes due 2028 (2028 Notes), and the 7.050% senior notes due 2029 (2029 Notes) in the aggregate amount of $498.2 million.

Cash Required by Investing Activities

Net cash required by investing activities in 2023 was $110.7 million lower compared to 2022. The decrease was primarily due to the proceeds from the sale of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets ($102.9 million) and lower acquisition capital ($93.0 million), partially offset by higher property additions and dry hole costs ($80.6 million).

40

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

A reconciliation of “Property additions and dry hole costs” in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.

1 Certain prior-period amounts have been reclassified to conform to the current period presentation.

Total accrual basis capital expenditures are shown below.

Lower capital expenditures in 2023 compared to 2022 were primarily attributable to lower development expenditures at the Khaleesi, Mormont, Samurai field development project, lower spend at the Kodiak and Lucius fields and lower acquisition capital, partially offset by higher exploratory drilling and higher development expenditures at the Dalmatian and St. Malo fields. Capital expenditures in 2023 primarily relate to development drilling and field development activities in the Eagle Ford Shale ($361.5 million); development activities in the Gulf of Mexico, primarily related to St. Malo, Dalmatian, Samurai and Marmalard fields ($310.1 million); development drilling and field development activities at the Tupper Montney field ($142.0 million); field development at Terra Nova for the asset life extension project ($44.7 million); and total exploration costs of $214.3 million. Exploration costs were primarily for activities at Chinook #7 (Walker Ridge 425), Oso #1 (Atwater Valley 138) and Longclaw #1 (Green Canyon 433) within the Gulf of Mexico and activities at Côte d’Ivoire. Costs of $169.8 million primarily associated with Chinook #7 (Walker Ridge 425) and Oso #1 (Atwater Valley 138) were expensed to dry hole costs in 2023 as the Company determined there were non-commercial hydrocarbons present.

Cash Required by Financing Activities

Net cash required by financing activities in 2023 decreased by $157.9 million compared to 2022. In 2023, cash used in financing activities was principally for the redemption of the remaining $248.7 million principal outstanding on its 2025 Notes and the tendering of $249.5 million of its 2027 Notes, 2028 Notes and 2029 Notes. In addition, the Company repurchased common shares ($150.0 million, excluding accrued excise tax), paid contingent consideration related to prior Gulf of Mexico acquisitions ($60.2 million) as discussed in the ‘Cash Provided by Continuing Operating Activities’ section, paid cash dividends to shareholders of $1.10 per share ($171.0 million), and distributed funds to the noncontrolling interest in the Gulf of Mexico ($29.4 million).

41

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Liquidity

At December 31, 2023, the Company had approximately $1.1 billion of liquidity consisting of $317.1 million in cash and cash equivalents and $796.2 million available on its committed senior unsecured RCF with a major banking consortium.

The Company’s $800 million senior unsecured RCF expires in November 2027 and as of December 31, 2023, the Company had no outstanding borrowings under the RCF and $3.8 million of outstanding letters of credit, which reduce the borrowing capacity of the senior unsecured RCF. Borrowings under the RCF are subject to certain interest rates, please refer to Note F for further details. At December 31, 2023, the interest rate in effect on borrowings under the facility would have been 7.70%. At December 31, 2023, the Company was in compliance with all covenants related to the RCF.

Cash and invested cash are maintained in several operating locations outside the U.S. As of December 31, 2023, cash and cash equivalents held outside the U.S. included U.S dollar equivalents of approximately $148.9 million (2022: $147.7 million), the majority of which was held in Canada ($105.2 million) and Mexico ($18.1 million). In addition, approximately $9.6 million and $8.3 million of cash was held in the U.K. and Spain, respectively. 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. See Note H for further information regarding potential tax expense that could be incurred upon distribution of foreign earnings back to the United States.

Working Capital

As of December 31, 2023, net working capital had a favorable increase of $191.2 million compared to December 31, 2022. The favorable increase was primarily attributable to lower other accrued liabilities ($302.8 million) and lower accounts payable ($96.9 million), partially offset by lower accounts receivable ($47.2 million) and a lower cash balance ($174.9 million). Lower accrued liabilities were primarily due to payments made for contingent consideration obligations from prior Gulf of Mexico acquisitions, payments for abandonment activities and incentive payments made in 2023. Lower accounts payable were primarily due to decreases in unrealized losses on derivative instruments (commodity price swaps and collars), decreases in royalties payable due to lower revenues, payments made for abandonment activities and drilling and completions activities. Lower unrealized losses on derivative instruments were as a result of no commodity derivative instrument contracts entered into or outstanding during 2023. Lower accounts receivable were primarily due to lower sales volumes for crude oil and natural gas liquids and lower pricing received for all crude oil, natural gas liquids and natural gas.

42

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Capital Employed

A summary of capital employed as of December 31, 2023 and 2022 follows.

As of December 31, 2023, long-term debt decreased by $494.0 million compared to December 31, 2022, as a result of the redemption and early redemption of, in whole or in part, the 2025 Notes, 2027 Notes, 2028 Notes, and 2029 Notes. The fixed-rate notes had a weighted average maturity of 8.1 years and a weighted average coupon of 6.2%.

Murphy’s shareholders’ equity increased by $368.0 million in 2023 primarily due to net income earned ($661.6 million), partially offset by cash dividends paid ($171.0 million) and shares repurchased ($150.0 million, including excise tax). A summary of transactions in stockholders’ equity accounts is presented in the Consolidated Statements of Stockholders’ Equity on page 69 of this Form 10-K report.

Other Balance Sheet Activity - Long-Term Assets and Liabilities

Other significant changes in Murphy’s balance sheet at the end of 2023, compared to 2022 are discussed below.

Property, plant and equipment, net of depreciation, decreased $2.8 million principally due to DD&A expense ($861.6 million) and divestment of certain non-core operated Kaybob Duvernay assets and all of the non-operated Placid Montney assets, substantially offset by capital expenditures in the year and foreign exchange rates applicable for the Canadian assets. Capital expenditures are discussed above in the ‘Cash Required for Investing Activities’ section.

Murphy had commitments for capital expenditures of approximately $209.8 million at December 31, 2023 (2022: $282.4 million). This amount includes $75.1 million for approved expenditures for capital projects relating to non-operated interests in deepwater U.S. Gulf of Mexico, principally at St. Malo ($61.7 million), non-operated Canada interests, mainly offshore ($11.6 million), non-operated Lucius ($13.3 million) and non-operated Eagle Ford Shale ($11.8 million).

Operating lease assets decreased $201.2 million principally due to depreciation on these assets.

Deferred Income tax assets decreased by $117.5 million as a result of the decrease in the U.S. net operating loss carryforward from $2.1 billion at year-end 2022 to $1.7 billion at year-end 2023.

Long term asset retirement obligations increased $86.8 million primarily due to accretion and additions and revisions related to Gulf of Mexico and Eagle Ford Shale operations.

Non-current operating lease liabilities decreased $190.8 million primarily due to 2023 annual payments reducing operating lease liabilities for drilling rig and vessel commitments.

Deferred income tax liabilities increased $61.7 million due to capital related tax deductions.

43

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Other Key Performance Metrics

The Company uses other operational performance and income metrics to review operational performance. Management uses adjusted net income, EBITDA and adjusted EBITDA internally to evaluate the Company’s operational performance and trends between periods and relative to its industry competitors. Adjusted net income also excludes certain items that management believes affect the comparability of results between periods. Management believes this information may be useful to investors and analysts to gain a better understanding of the Company’s financial results. Adjusted net income, EBITDA, adjusted EBITDA and 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.

The following table reconciles reported net income attributable to Murphy to adjusted net income from continuing operations attributable to Murphy.

1  Excludes amounts attributable to a noncontrolling interest in MP GOM.

2  Certain prior-period amounts have been reclassified to conform to the current period presentation.

44

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

The following table reconciles reported net income attributable to Murphy to EBITDA attributable to Murphy and adjusted EBITDA attributable to Murphy.

1  Excludes amounts attributable to a noncontrolling interest in MP GOM.

2  Depreciation, depletion and amortization expense, impairment of assets, loss (gain) on sale of sale of assets and accretion of asset retirement obligations used in the computation of adjusted EBITDA exclude the portion attributable to the noncontrolling interest.

45

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Environmental, Health and Safety Matters

Murphy faces various environmental, health and safety risks that are inherent in exploring for, developing and producing hydrocarbons. To help manage these risks, the Company has established a robust health, safety and environmental governance program comprised of a worldwide policy, guiding principles, annual goals and a management system incorporating oversight at each business unit, senior leadership and board levels. The Company strives to minimize these risks by continually improving its processes through design, operation and implementation of a comprehensive asset integrity plan, and through emergency and oil spill response planning to address any credible risks. These plans are presented to, reviewed and approved by a Health, Safety, Environment and Corporate Responsibility Committee consisting of certain members of the Board.

The oil and gas industry is subject to numerous international, foreign, national, state, provincial and local environmental, health and safety laws and regulations. Murphy allocates a portion of both its capital expenditures and its general and administrative budget toward compliance with existing and anticipated environmental, health and safety laws and regulations. These requirements affect virtually all operations of the Company and increase Murphy’s overall cost of business, including its capital costs to construct, maintain and upgrade equipment and facilities as well as operating costs for ongoing compliance.

The principal environmental, health and safety laws and regulations to which Murphy is subject address such matters as the generation, storage, handling, use, disposal and remediation of petroleum products, wastewater and hazardous materials; the emission and discharge of such materials to the environment, including GHG emissions; wildlife, habitat and water protection; the placement, operation and decommissioning of production equipment; and the health and safety of our employees, contractors and communities where our operations are located. These laws and regulations also generally require permits for existing operations, as well as the construction or development of new operations and the decommissioning facilities once production has ceased. Violations can give rise to sanctions including significant civil and criminal penalties, injunctions, construction bans and delays.

Further information on environmental, health and safety laws and regulations applicable to Murphy are contained in the Business section beginning page 10.

Climate Change and Emissions

The world’s population and standard of living is growing steadily along with the demand for energy. Murphy recognizes that this may generate increasing amounts of GHG, which could raise important climate change concerns. Murphy works to assess the Company’s governance, strategy, risk identification, and management and measurement of climate risks and opportunities in order to remain in alignment with the TCFD core elements. The TCFD was created by the Financial Stability Board to focus on climate-related financial disclosures to improve and increase reporting of climate-related financial information. Murphy’s disclosures related to its alignment with the TCFD are included in the Company’s 2023 Sustainability Report issued on August 2, 2023, which is not incorporated by reference hereto.

Other Matters

Impact of inflation – In 2023, many countries worldwide continued to experience a rise in inflation, including countries where the Company operates (this follows a sustained period of relatively low inflation prior to 2021). In the U.S., inflation continued as a result of ongoing supply constraints and increasing demand for goods and services as countries continue their recovery from the COVID-19 pandemic. The Company’s revenues, capital and operating costs are influenced to a larger extent by specific price changes in the oil and gas industry and allied industries rather than by changes in general inflation. Crude oil prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC+ production levels and/or attitudes of traders concerning supply and demand in the future. Costs for oil field goods and services are usually affected by the worldwide prices for crude oil.

To combat impacts of inflation and/or supply and demand factors, Murphy has dedicated personnel in marketing and procurement departments, focused on managing supply chain and input costs. Murphy also has certain transportation, processing and production handling services costs fixed through long-term contracts and commitments and therefore is partly protected from the increasing price of services. However, from time to time, Murphy will seek to enter new commitments, exercise options to extend contracts and retender contracts for rigs

46

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

and other industry services which could expose Murphy to the impact of higher costs. Murphy continues to strive toward safely executing our work in an ever-increasing efficient manner to mitigate possible inflationary pressures in our business.

Natural gas prices are also affected by supply and demand, which are often affected by the weather and by the fact that delivery of natural gas can be restricted to specific geographic areas. Natural gas demand is also impacted by demand driven by lower carbon emissions and a view that natural gas is one option to transition from higher carbon emitting fuels.

As a result of the overall volatility of oil and natural gas prices, it is not possible to predict the Company’s future cost of oil field goods and services.

Critical Accounting Estimates – In preparing the Company’s consolidated financial statements in accordance with GAAP, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Application of certain of the Company’s accounting policies requires significant estimates. The most significant of these accounting policies and estimates are described below.

Oil and natural gas proved reserves – Oil and natural gas proved reserves are defined by the SEC as those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations before the time at which contracts providing the right to operate expire (unless evidence indicates that renewal is reasonably certain). Proved developed reserves of oil and natural gas can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Although the Company’s engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. SEC rules require the Company to use an unweighted average of the oil and natural gas prices in effect at the beginning of each month of the year for determining quantities of proved reserves. These historical prices often do not approximate the average price that the Company expects to receive for its oil and natural gas production in the future. The Company often uses significantly different oil and natural gas prices and reserve assumptions when making its own internal economic property evaluations. Changes in oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserves quantities.

Estimated reserves are subject to future revision, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Reserves revisions inherently lead to adjustments of the Company’s depreciation rates and the timing of settlement of asset retirement obligations. Downward reserves revisions can also lead to significant impairment expense. The Company cannot predict the type of oil and natural gas reserves revisions that will be required in future periods.

The Company’s proved reserves of crude oil, natural gas liquids and natural gas are presented on pages 103 to 112 of this Form 10-K report. Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering, and economic data (including hydrocarbon prices, operating costs, and development costs), and commercially available technologies, to establish ‘reasonable certainty’ of economic producibility. As defined by the SEC, reasonable certainty of proved reserves describes a high degree of confidence that the quantities will be recovered. In estimating proved reserves, Murphy uses familiar industry-accepted methods for subsurface evaluations, including performance, volumetric, and analog-based studies.

Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves. Reliable geologic and engineering technology is a method or combination of methods that are field-tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. This integrated approach increases the quality of and confidence in Murphy’s proved reserves estimates. It was utilized in certain undrilled acreage at distances

47

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

greater than the directly offsetting development spacing areas, and in certain reservoirs developed with the application of improved recovery techniques. Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, historic production and pressure data, and commercially available seismic processing and numerical reservoir simulation programs. Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.

See further discussion of proved reserves and changes in proved reserves during the three years ended December 31, 2023 beginning on pages 4 and 103 of this Form 10-K report.

Property, Plant and Equipment - impairment of long-lived assets – The Company continually monitors its long-lived assets recorded in “Property, plant and equipment” in the Consolidated Balance Sheet to ensure that they are fairly presented. The Company must evaluate its property, plant and equipment for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable from future cash flows.

A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the amount of oil and natural gas that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, future capital, operating and abandonment costs and future inflation levels.

The need to test a long-lived asset for impairment can be based on several factors, including, but not limited to, a significant reduction in sales prices for oil and/or natural gas, unfavorable revisions of oil or natural gas reserves, or other changes to contracts, environmental, health and safety laws and regulations, tax laws or other regulatory changes. All of these factors must be considered when evaluating a property’s carrying value for possible impairment.

Due to the volatility of world oil and natural gas markets, the actual sales prices for oil and natural gas have often been different from the Company’s projections.

Estimates of future oil and natural gas production and sales volumes are based on a combination of proved and risked probable reserves. Although the estimation of reserves and future production is uncertain, the Company believes that its estimates are reasonable; however, there have been cases where actual production volumes were higher or lower than projected and the timing was different than the original projection. The Company adjusts reserves and production estimates as new information becomes available.

The Company generally projects future costs by using historical costs adjusted for both assumed long-term inflation rates and known or expected changes in future operations. Although the projected future costs are considered to be reasonable, at times, costs have been higher or lower than originally estimated.

There were no impairments recognized in 2023 or 2022.

Income taxes – The Company is subject to income and other similar taxes in all areas in which it operates. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of its annual accounting period; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; (c) future events often impact the timing of when income tax expenses and benefits are recognized by the Company; and (d) changes to regulations may be subject to different interpretations and require future clarification from issuing authorities or others.

The Company has deferred tax assets mostly relating to U.S net operating losses, liabilities for dismantlement, retirement benefit plan obligations and net deferred tax liabilities relating to tax and accounting basis differences for property, plant and equipment.

The Company routinely evaluates all deferred tax assets to determine the likelihood of their realization and reduce such assets to the expected realizable amount by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In assessing the need for valuation allowances, we consider all available positive and negative evidence. Positive evidence includes projected future taxable income and assessment of future business assumptions, a history of utilizing tax assets before expiration, significant proven and probable reserves and reversals of taxable temporary differences. Negative evidence includes losses in recent years.

48

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

As of December 31, 2023 the Company had a U.S. deferred tax asset associated with net operating losses of $357.5 million. In reviewing the likelihood of realizing this asset, the Company considered the reversal of taxable temporary differences, carryforward periods and future taxable income estimates based on projected financial information which, based on currently available evidence, we believe to be reasonably likely to occur. Certain estimates and assumptions are used in the estimation of future taxable income, including (but not limited to) (a) future commodity prices for crude oil and condensate, NGLs and natural gas, (b) estimated reserves for crude oil and condensate, NGLs and natural gas, (c) expected timing of production, (d) estimated lease operating costs and (e) future capital requirements. In the future, the underlying actual assumptions utilized in estimating future taxable income could be different and result in different conclusions about the likelihood of the future utilization of our net operating loss carryforwards.

Accounting for retirement and postretirement benefit plans – Murphy and certain of its subsidiaries maintain defined benefit retirement plans covering certain full-time employees. The Company also sponsors health care and life insurance benefit plans covering most retired U.S. employees. The expense associated with these plans is estimated by management based on a number of assumptions and with consultation assistance from qualified third-party actuaries. The most important of these assumptions for the retirement plans involve the discount rate used to measure future plan obligations and the expected long-term rate of return on plan assets. For the retiree medical and insurance plans, the most important assumptions are the discount rate for future plan obligations and the health care cost trend rate. Discount rates are based on the universe of high-quality corporate bonds that are available within each country. Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans. The discounted cash flows are used to determine an equivalent single rate which is the basis for selecting the discount rate within each country. Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics. Anticipated health care cost trend rates are determined based on prior experience of the Company and an assessment of near-term and long-term trends for medical and drug costs.

Based on bond yields as of December 31, 2023, the Company has used a weighted average discount rate of 5.15% at year-end 2023 for the primary U.S. plans. This weighted average discount rate is 0.3% lower than prior year, which increased the Company’s recorded liabilities for retirement plans compared to a year ago. The Company assumed a return on plan assets of 8.00% for the primary U.S. plan, it periodically reconsiders the appropriateness of this and other key assumptions. The Company’s retirement and postretirement plan (health care and life insurance benefit plans) expenses in 2024 are expected to be $0.7 million higher than in 2023 primarily due to the increase in the benefit obligations at December 31, 2023 compared to the prior year, which increases the interest cost recognized in net periodic benefit costs. Cash contributions to all plans are anticipated to be $2.9 million higher in 2024.

In 2023, the Company paid $37.5 million into various retirement plans and $2.0 million into postretirement plans. In 2024, the Company is expecting to fund payments of approximately $38.0 million into various retirement plans and $4.4 million for postretirement plans. The Company could be required to make additional and more significant funding payments to retirement plans in future years. Future required payments and the amount of liabilities recorded on the balance sheet associated with the plans could be unfavorably affected if the discount rate declines, the actual return on plan assets falls below the assumed return, or the health care cost trend rate increase is higher than expected.

Recent Accounting Pronouncements

See Note B in our Consolidated Financial Statements regarding the impact or potential impact of recent accounting pronouncements upon our financial position and results of operations.

49

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Contractual obligations and guarantees – The Company is obligated to make future cash payments under borrowing arrangements, operating leases, purchase obligations primarily associated with existing capital expenditure plans and other long-term liabilities. Total payments due after 2023 under such contractual obligations and arrangements are shown in the table below. Amounts are undiscounted and therefore may differ to those presented in the financial statements.

1 Other leases refers to a finance lease in Brunei (see Note T).

2 Capital expenditures, drilling rigs and other includes $51.6 million, $11.8 million, $11.6 million and $4.0 million, in 2024 for approved capital projects in non-operated interests in U.S. Gulf of Mexico, U.S. Onshore, Canada Offshore and Other Foreign Offshore, respectively. Capital expenditures, drilling rigs and other includes $23.5 million in 2025 for approved capital projects in non-operated interests in U.S. Gulf of Mexico.

Also includes $74.6 million (2024), $145.3 million (2025 - 2026), $140.2 million (2027 - 2028) and $308.1 million (After 2028) for pipeline transportation commitments in Canada.

Also includes $4.1 million (2024), $7.7 million (2025 - 2026), $7.7 million (2027 - 2028) and $22.5 million (After 2028) for long term take or pay commitments relating to natural gas processing in Canada.

3 Other long-term liabilities, including debt interest, includes future cash outflows for asset retirement obligations.

The Company has entered into agreements to lease production facilities for various producing oil fields as well as other arrangements that require future payments as described in the following section. The Company’s share of the contractual obligations under these leases and other arrangements has been included in the table above.

In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide letters of credit that may be drawn upon if the Company fails to perform under those contracts. Total outstanding letters of credit were $200.6 million as of December 31, 2023.

Material off-balance sheet arrangements – Certain U.S. transportation contracts require minimum monthly payments through 2045, while Onshore Canada transportation and processing contracts call for minimum monthly payments through 2051. Future required minimum annual payments under these arrangements are included in the contractual obligation table above.

50

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

Outlook

The oil and gas industry is impacted by global commodity pricing and as a result the prices for the Company’s primary products are often volatile and are affected by the levels of supply and demand for energy. As discussed in the Results of Operations section discussing revenues, on page 37, lower average crude oil price during in 2023 directly impacted the Company’s product sales revenue.

As of close on February 21, 2024, forward price curves for existing forward contracts for the remainder of 2024 and 2025 are shown in the table below:

In 2023, liquids from continuing operations represented approximately 60% of total hydrocarbons produced on an energy equivalent basis. In 2024, the Company’s ratio of hydrocarbon production represented by liquids is expected to be 59%. If the prices for crude oil and natural gas are lower in 2024 or beyond, this will have an unfavorable impact on the Company’s operating profits; likewise, if prices are higher, this will have a favorable impact. The Company, from time to time, may choose to use a variety of commodity hedge instruments to reduce commodity price risk, including forward sale fixed financial swaps and long-term fixed-price physical commodity sales.

The Company currently expects average daily production in 2024 to be between 187,100 and 195,100 barrels of oil equivalent per day (including noncontrolling interest of 7,100 BOEPD). If significant price declines occur, the Company will review the option of production curtailments to avoid incurring losses on certain produced barrels.

Similar to the overall inflation and higher interest rates in the wider economy, the oil and gas industry and the Company are observing higher costs for goods and services used in E&P operations. Murphy continues to manage input costs through its dedicated procurement department focused on managing supply chain and other costs to deliver cash flow from operations.

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.

The Company’s capital expenditure spend for 2024 is expected to be between $920 million and $1,020 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 2024 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 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. During 2023, the Board authorized a $300 million increase to the original share repurchase program announced in the Capital Allocation Framework, bringing the total amount allowed to be repurchased under the program to $600 million. As of December 31, 2023, the Company has $450 million remaining available to repurchase.

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).

51

Table of Contents

PART II

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued

As of February 21, 2024, 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:

Forward-Looking Statements

This Form 10-K 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; geopolitical concerns; 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, including inflation. 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 Item 1A. Risk Factors, which begins on page 15 of this Annual Report on Form 10-K. 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.

52

Table of Contents