EX-99.4 19 mur-20231231xex994.htm EX-99.4
Exhibit 99.4
Proved Hydrocarbon Reserves Statement for Murphy Oil Corporation in Relation to the Oil/Gas Lac Da Vang Field, Vietnam
as of December 31, 2023
Prepared for
Murphy Oil Corporation
January 26, 2024

| Gaffney, Cline & Associates (Consultants) Pte. Ltd. 150 Beach Road #20-01/02 Gateway West Singapore 189720 Tel: +65 6225 6951 UEN: 198701453N

January 26, 2024
Mr. Jeffrey Wilson
General Manager/Corporate Reserves
Murphy Oil Corporation
USA
Dear Mr. Wilson,
Proved Hydrocarbon Reserves Statement for Murphy Oil Corporation
in Relation to the Oil/Gas Lac Da Vang Field, Vietnam
as of December 31, 2023
This proved reserves statement has been prepared by Gaffney, Cline & Associates (Consultants) Pte Ltd (“GaffneyCline”) and issued on January 26, 2024 at the request of Murphy Oil Corporation (Murphy or “the Client”), in respect of an oil and gas reserves audit of the Lac Da Vang (“LDV”) Field in Vietnam where Murphy has a 40% operated participating interest. This report is intended for inclusion in Murphy’s filings (10-K) with the United States Securities and Exchange Commission (“SEC”).
The LDV Field is located in the south-east corner of Block 15-1/05 in the Cuu Long Basin on the continental shelf, offshore of southern Vietnam. It is about 120 km east-southeast of Vung Tau City. In the LDV area, the seawater depth ranges between 45 and 55 m. The location map is as shown in Appendix I.
GaffneyCline has conducted an independent audit examination as of December 31, 2023, of the hydrocarbon liquid and gas proved reserves of the LDV Field. On the basis of technical and other information made available to GaffneyCline concerning the field, we hereby provide the reserves statement in Table 1. Murphy’s proved reserves summarized in the table is considered reasonable and compared to GaffneyCline’s estimates are within the audit tolerance of not more than plus or minus 5 percent.
This report relates specifically and solely to the subject matter as defined in the scope of work in the Proposal for Services and is conditional upon the assumptions described herein. The report must be considered in its entirety and must only be used for the purpose for which it was intended.
GaffneyCline has been engaged to audit only the LDV Field as of December 31, 2023. As informed by Murphy, LDV Proved Reserves represent 1.7% of total Murphy’s year-end 2023 Proved Reserves on a BOE basis.
DP/jbi/PS-23-208110/L0005
Murphy Oil Corporation www.gaffneycline.com

The LDV gas is associated gas. The LDV gas is not reported in the LDV Field reserves as of December 31, 2023. The LDV gas sales agreement (GSA) with PetroVietnam/PetroVietnam Gas (PV/PVGas) is currently under discussion. Murphy plans to book the LDV gas reserves volumes only after the GSA is finalized.
Murphy provided documentation from March 2023 that shows the LDV gas sales process is progressing. PV/PVGas has accepted the receipt of LDV potential export gas through their pipeline system. Both Murphy and PV/PVGas are continuing to discuss tie-in options.
The gas will reach the market via the future trunkline. The trunkline CAPEX is part of the LDV oil field development CAPEX. Should the gas be monetized, gas will contribute only minor additional revenue to the LDV Field.
Table 1: Estimated Net Reserves
Murphy Oil Corporation for Oil/Gas Lac Da Vang Field, Block 15-1/05, Vietnam
as of December 31, 2023

Hydrocarbon | Oil (MMstb) | Gas (Bscf) | Total (MMboe)
Proved |  |  |
Developed | - | - | -
Undeveloped | 12.1 | 2.8 | 12.6
Total Proved | 12.1 | 2.8 | 12.6

Notes:
1.Murphy Net Reserves are Murphy’s net economic entitlement volume after the deduction of royalties and profit share under the PSC that governs the asset (i.e., Company’s share of cost oil/gas and profit oil/gas). The volumes shown above exclude the Government and partner share of production applicable under the PSC terms.
2.The above Reserves include production through to the end of the relevant PSC only and after considering the field economic limit.
3.Hydrocarbon liquid volumes represent crude oil estimated to be recovered during field separation and plant processing and are reported in millions of barrels at stock tank conditions (MMstb).
4.The above Gas Reserves represent only the volumes consumed in operations (CiO, or fuel). No gas reserves are reported related to the LDV gas sales since the gas sales agreement is still in negotiation with the buyer.
Murphy Oil Corporation
January 26, 2024 Page 2 of 6

Reserves Assessment
GaffneyCline’s audit of the Murphy reserves estimates was based on an independent review of the dynamic model and the underlying data such fluid laboratory tests and DST results and other pertinent information as provided by Murphy. The choice of a dynamic model to estimate production forecasts is appropriate for the LDV Field given that the field is undeveloped, the lack of direct analog fields and the complex interaction between matrix flow and fracture flow than cannot be captured with simpler models such as material balance. The underlying data set was comprehensive and questions were responded to in a timely and detailed manner by Murphy.
Particular scrutiny was paid to the history match of the model to the various DST’s as the only available “production data” where the matching technique followed good industry practice and the resulting match parameters were geologically reasonable.
The proposed development plan covers 100% of reserves in this report and has been accurately implemented in the dynamic model and the resulting production forecasts yielded a range of oil recovery factors consistent with the expectation for the type of reservoir. The range of production forecasts from the dynamic model were considered to not fully capture the possible range of outcomes given the limited number of exploration and appraisal wells and tests and so the proved estimate has been based upon the lowest production forecast from the dynamic model.
This audit examination was based on reserves estimates and other information provided by Murphy to GaffneyCline from November to December 2023 and included such tests, procedures and adjustments as were considered necessary under the circumstances to prepare the report. All questions that arose during the course of the audit process were resolved to our satisfaction.
The economic tests for the December 31, 2023 Proved Reserves volumes were based on an expected realized crude price of US$85.41/bbl as advised by Murphy. This is after taking into account of the crude transportation cost of US$2.0/bbl. LDV crude is expected to be sold at US$4.00/bbl premium to Brent crude price of US$83.41/bbl. Crude from the Cuu Long Basin is historically traded at a premium to Brent. Brent crude price was based on the SEC requirement i.e., 12-month averages of the prices of the first day of the month preceding the estimates. The Brent crude price is found reasonable and aligned with the industry assumption.
Future capital costs were derived from development program forecasts prepared by Murphy for the LDV Field. Recent historical operating expense data were utilized as the basis for operating cost projections. GaffneyCline has found that Murphy has projected sufficient capital investments and operating expenses to produce economically the projected volumes.
It is GaffneyCline’s opinion that the estimates of total remaining recoverable hydrocarbon liquid volumes at December 31, 2023, are, in the aggregate, reasonable and the reserves categorization is appropriate and consistent with the definitions for reserves set out in 17-CFR Part 210 Rule 4-10(a) of Regulation S-X of the United States Securities and Exchange Commission (as set out in Appendix II). GaffneyCline concludes that the methodologies employed by Murphy in the derivation of the volume estimates are appropriate and that the quality of the data relied upon, the depth and thoroughness of the estimation process are adequate.
Murphy Oil Corporation
January 26, 2024 Page 3 of 6

Basis of Opinion
This document reflects GaffneyCline’s informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by the Client, the limited scope of engagement, and the time permitted to conduct the evaluation.
In line with those accepted standards, this document does not in any way constitute or make a guarantee or prediction of results, and no warranty is implied or expressed that actual outcome will conform to the outcomes presented herein. GaffneyCline has not independently verified any information provided by, or at the direction of, the Client, and has accepted the accuracy and completeness of this data. GaffneyCline has no reason to believe that any material facts have been withheld but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose.
The opinions expressed herein are subject to and fully qualified by the generally accepted uncertainties associated with the interpretation of geoscience and engineering data and do not reflect the totality of circumstances, scenarios and information that could potentially affect decisions made by the report’s recipients and/or actual results. The opinions and statements contained in this report are made in good faith and in the belief that such opinions and statements are representative of prevailing physical and economic circumstances.
There are numerous uncertainties inherent in estimating reserves and resources, and in projecting future production, development expenditures, operating expenses and cash flows. Oil and gas resources assessments must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact way. Estimates of oil and gas resources prepared by other parties may differ, perhaps materially, from those contained within this report.
The accuracy of any resources estimate is a function of the quality of the available data and of engineering and geological interpretation. Results of drilling, testing and production that post-date the preparation of the estimates may justify revisions, some or all of which may be material.
Accordingly, resources estimates are often different from the quantities of oil and gas that are ultimately recovered, and the timing and cost of those volumes that are recovered may vary from that assumed.
GaffneyCline’s review and audit involved reviewing pertinent facts, interpretations and assumptions enable it to render an opinion on the appropriateness of the methodologies employed, adequacy and quality of the data relied on, depth and thoroughness of the reserves and resources estimation process, classification and categorization of reserves and resources appropriate to the relevant definitions used, and reasonableness of the estimates.
Definition of Reserves
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce, or a revenue interest in, the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Murphy Oil Corporation
January 26, 2024 Page 4 of 6

Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status. All categories of reserves volumes quoted herein have been derived within the context of an economic limit test (ELT) assessment (pre-tax and exclusive of accumulated depreciation amounts).
GaffneyCline is not aware of any potential changes in regulations applicable to these fields that could affect the ability of the Client to produce the estimated reserves.
GaffneyCline is not aware of any carbon pricing impost that is applicable to the evaluation of the assets that are the subject of this report. GaffneyCline has also not included the impact of any potential carbon pricing scheme that may be implemented in the future.
GaffneyCline has not undertaken a site visit and inspection because it was not part of the scope of work. As such, GaffneyCline is not in a position to comment on the operations or facilities in place, their appropriateness and condition, or whether they are in compliance with the regulations pertaining to such operations. Further, GaffneyCline is not in a position to comment on any aspect of health, safety, or environment of such operation.
This report has been prepared based on GaffneyCline’s understanding of the effects of petroleum legislation and other regulations that currently apply to these properties. However, GaffneyCline is not in a position to attest to property title or rights, conditions of these rights (including GaffneyCline (including planning permission, financial interest relationships, or encumbrances thereon for any part of the appraised properties).
Qualifications
In performing this study, GaffneyCline is not aware that any conflict of interest has existed. As an independent consultancy, GaffneyCline is providing impartial technical, commercial, and strategic advice within the energy sector. GaffneyCline’s remuneration was not in any way contingent on the contents of this report.
In the preparation of this document, GaffneyCline has maintained, and continues to maintain, a strict independent consultant-client relationship with the Client. Furthermore, the management and employees of GaffneyCline have no interest in any of the assets evaluated or related with the analysis performed, as part of this report.
Staff members who prepared this report hold appropriate professional and educational qualifications and have the necessary levels of experience and expertise to perform the work. The technical qualifications of the person primarily responsible for the preparation of the reserves estimates presented in this report are given in Appendix III.
Murphy Oil Corporation
January 26, 2024 Page 5 of 6

Notice
This report is intended for inclusion in its entirety in Murphy’s filings (10-K) with the United States Securities and Exchange Commission (SEC) in accordance with the disclosure requirements set forth in the SEC regulations. Murphy Oil Corporation will obtain GaffneyCline's prior written approval for any other use of any results, statements or opinions expressed to Murphy Oil Corporation in this report, which are attributed to GaffneyCline.
Yours sincerely,
Gaffney, Cline & Associates (Consultants) Pte Ltd

Project Manager
Doug Peacock, Senior Director

Appendices
Appendix I LDV Field Location Map
Appendix II SEC Reserves Definitions
Appendix III Statement of Qualifications
Appendix IV Glossary
Murphy Oil Corporation
January 26, 2024 Page 6 of 6

Appendix I
LDV Field Location Map
Murphy Oil Corporation
January 26, 2024

Figure 1: LDV Field Location Map
Source: Murphy
Murphy Oil Corporation
January 26, 2024 AI.1

Appendix II
SEC Reserves Definitions
Murphy Oil Corporation
January 26, 2024

U.S. SECURITIES AND EXCHANGE COMMISSION (SEC) MODERNIZATION OF OIL AND GAS REPORTING 1
Oil and Gas Reserves Definitions and Reporting
(a)Definitions
(1)Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.
(2)Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:
(i)Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii)Same environment of deposition;
(iii)Similar geological structure; and
(iv)Same drive mechanism.
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
(3)Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non- hydrocarbons. 2
(4)Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
(5)Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6)Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
1 Extracted from 17 CFR Parts 210, 211, 229, and 249 [Release Nos. 33-8995; 34-59192; FR-78; File No. S7-15-08] RIN 3235- AK00].
2

(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
(7)Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
(i)Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
(ii)Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
(iii)Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv)Provide improved recovery systems.
(8)Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
(9)Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
(10)Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(11)Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
(12)Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in pail as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
(i)Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
(ii)Costs of carrying and retaining undeveloped properties, such as delay rentals,

ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
(iii)Dry hole contributions and bottom hole contributions.
(iv)Costs of drilling and equipping exploratory wells.
(v)Costs of drilling exploratory-type stratigraphic test wells.
(13)Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.
(14)Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
(15)Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas- of-interest, etc.
(16)Oil and gas producing activities.
(i)Oil and gas producing activities include:
(A)The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;
(B)The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
(C)The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1)Lifting the oil and gas to the surface; and
(2)Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
(D)Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field
storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:
a.The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b.In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
(ii)Oil and gas producing activities do not include:
(A)Transporting, refining, or marketing oil and gas;
(B)Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
(C)Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
(D)Production of geothermal steam.
(17)Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i)When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi)Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be

established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
(18)Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
(i)When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii)Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv)See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
(19)Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
(20)Production costs.
(i)Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities, they become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
(A)Costs of labor to operate the wells and related equipment and facilities.
(B)Repairs and maintenance.
(C)Materials, supplies, arid fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
(D)Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
(E)Severance taxes.
(ii)Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of

oil and gas produced along with production (lifting) costs identified above.
(21)Proved area. The part of a property to which proved reserves has been specifically attributed.
(22)Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and 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 prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i)The area of the reservoir considered as proved includes:
(A)The area identified by drilling and limited by fluid contacts, if any, and
(B)Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A)Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B)The project has been approved for development by all necessary parties and entities, including governmental entities.
(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
(23)Proved properties. Properties with proved reserves.
(24)Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic

methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
(25)Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
(26)Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
(27)Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
(28)Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
(29)Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
(30)Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
(31)Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i)Reserves on undrilled acreage shall be limited to those directly offsetting

development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
(32)Unproved properties. Properties with no proved reserves.

Appendix III
Statement of Qualifications
Murphy Oil Corporation
January 26, 2024

Doug Peacock
Doug Peacock is a Senior Director with GaffneyCline and was the person primarily responsible for the preparation of the audit. Mr. Peacock has 40 years of diversified international industry
experience mainly in geology and reserves estimates, including classification and reporting of reserves and resources. He is a recent member of the SPE’s Oil & Gas Reserves Committee and routinely provides industry training courses on behalf of the SPE on the subject of reserves and resources assessment. He is a member of the Society of Petroleum Engineers (SPE) and holds a BSc degree in Geological Sciences from Leeds University, UK and a Master’s Degree in Petroleum Geology from Imperial College, London.
Murphy Oil Corporation
January 26, 2024 AIII. 1

Appendix IV
Glossary
Murphy Oil Corporation
January 26, 2024

GLOSSARY
List of Standard Oil Industry Terms and Abbreviations

ABEX | Abandonment Expenditure
ACQ | Annual Contract Quantity
o API | Degrees API (American Petroleum Institute)
AAPG | American Association of Petroleum Geologists
AVO | Amplitude versus Offset
A$ | Australian Dollars
B | Billion (10 9)
Bbl | Barrels
/Bbl | per barrel
BBbl | Billion Barrels
BHA | Bottom Hole Assembly
BHC | Bottom Hole Compensated
Bscf or Bcf | Billion standard cubic feet
Bscfd or Bcfd | Billion standard cubic feet per day
Bm 3 | Billion cubic metres
bcpd | Barrels of condensate per day
BHP | Bottom Hole Pressure
blpd | Barrels of liquid per day
bpd | Barrels per day
BOE | Barrels of oil equivalent @ xxx mcf/Bbl
boepd | Barrels of oil equivalent per day @ xxx mcf/Bbl
BOP | Blow Out Preventer
bopd | Barrels oil per day
bwpd | Barrels of water per day
BS&W | Bottom sediment and water
BTU | British Thermal Units
bwpd | Barrels water per day
CBM | Coal Bed Methane
CO 2 | Carbon Dioxide
CAPEX | Capital Expenditure
CCGT | Combined Cycle Gas Turbine
cm | centimetres
CMM | Coal Mine Methane
CNG | Compressed Natural Gas
Cp | Centipoise (a measure of viscosity)
CSG | Coal Seam Gas
CT | Corporation Tax
DCQ | Daily Contract Quantity
Deg C | Degrees Celsius
Deg F | Degrees Fahrenheit
DHI | Direct Hydrocarbon Indicator
DST | Drill Stem Test
DWT | Dead-weight ton
E&A | Exploration & Appraisal

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E&P | Exploration and Production
EBIT | Earnings before Interest and Tax
EBITDA | Earnings before interest, tax, depreciation and amortisation
EI | Entitlement Interest
EIA | Environmental Impact Assessment
EMV | Expected Monetary Value
EOR | Enhanced Oil Recovery
EUR | Estimated Ultimate Recovery
FDP | Field Development Plan
FEED | Front End Engineering and Design
FPSO | Floating Production, Storage and Offloading
FSO | Floating Storage and Offloading
ft | Foot/feet
Fx | Foreign Exchange Rate
g | gram
g/cc | grams per cubic centimetre
gal | gallon
gal/d | gallons per day
G&A | General and Administrative costs
GBP | Pounds Sterling
GDT | Gas Down to
GIIP | Gas initially in place
GJ | Gigajoules (one billion Joules)
GOR | Gas Oil Ratio
GTL | Gas to Liquids
GWC | Gas water contact
HDT | Hydrocarbons Down to
HSE | Health, Safety and Environment
HSFO | High Sulphur Fuel Oil
HUT | Hydrocarbons up to
H 2 S | Hydrogen Sulphide
IOR | Improved Oil Recovery
IPP | Independent Power Producer
IRR | Internal Rate of Return
J | Joule (Metric measurement of energy) I kilojoule = 0.9478 BTU)
k | Permeability
KB | Kelly Bushing
KJ | Kilojoules (one Thousand Joules)
kl | Kilolitres
km | Kilometres
km 2 | Square kilometres
kPa | Thousands of Pascals (measurement of pressure)
KW | Kilowatt
KWh | Kilowatt hour
LKG | Lowest Known Gas
LKH | Lowest Known Hydrocarbons

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LKO | Lowest Known Oil
LNG | Liquefied Natural Gas
LoF | Life of Field
LPG | Liquefied Petroleum Gas
LTI | Lost Time Injury
LWD | Logging while drilling
m | Metres
M | Thousand
m 3 | Cubic metres
Mcf or Mscf | Thousand standard cubic feet
MCM | Management Committee Meeting
MMcf or MMscf | Million standard cubic feet
m 3 d | Cubic metres per day
mD | Measure of Permeability in millidarcies
MD | Measured Depth
MDT | Modular Dynamic Tester
Mean | Arithmetic average of a set of numbers
Median | Middle value in a set of values
MFT | Multi Formation Tester
mg/l | milligrams per litre
MJ | Megajoules (One Million Joules)
Mm 3 | Thousand Cubic metres
Mm 3 d | Thousand Cubic metres per day
MM | Million
MMBbl | Millions of barrels
MMBTU | Millions of British Thermal Units
Mode | Value that exists most frequently in a set of values = most likely
Mscfd | Thousand standard cubic feet per day
MMscfd | Million standard cubic feet per day
MW | Megawatt
MWD | Measuring While Drilling
MWh | Megawatt hour
mya | Million years ago
NGL | Natural Gas Liquids
N 2 | Nitrogen
NPV | Net Present Value
OBM | Oil Based Mud
OCM | Operating Committee Meeting
ODT | Oil down to
OPEX | Operating Expenditure
OWC | Oil Water Contact
p.a. | Per annum
Pa | Pascals (metric measurement of pressure)
P&A | Plugged and Abandoned
PDP | Proved Developed Producing
PI | Productivity Index

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PJ | Petajoules (10 15 Joules)
PSDM | Post Stack Depth Migration
psi | Pounds per square inch
psia | Pounds per square inch absolute
psig | Pounds per square inch gauge
PUD | Proved Undeveloped
PVT | Pressure volume temperature
P10 | 10% Probability
P50 | 50% Probability
P90 | 90% Probability
Rf | Recovery factor
RFT | Repeat Formation Tester
RT | Rotary Table
RTA | Rate Transient Analysis
R w | Resistivity of water
SCAL | Special core analysis
cf or scf | Standard Cubic Feet
cfd or scfd | Standard Cubic Feet per day
scf/ton | Standard cubic foot per ton
SL | Straight line (for depreciation)
s o | Oil Saturation
SPE | Society of Petroleum Engineers
SPEE | Society of Petroleum Evaluation Engineers
ss | Subsea
stb | Stock tank barrel
STOIIP | Stock tank oil initially in place
s w | Water Saturation
T | Tonnes
TD | Total Depth
Te | Tonnes equivalent
THP | Tubing Head Pressure
TJ | Terajoules (10 12 Joules)
Tscf or Tcf | Trillion standard cubic feet
TCM | Technical Committee Meeting
TOC | Total Organic Carbon
TOP | Take or Pay
Tpd | Tonnes per day
TVD | True Vertical Depth
TVDss | True Vertical Depth Subsea
USGS | United States Geological Survey
US$ | United States Dollar
VSP | Vertical Seismic Profiling
WC | Water Cut
WI | Working Interest
WPC | World Petroleum Council
WTI | West Texas Intermediate

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wt% | Weight percent
1H05 | First half (6 months) of 2005 (example of date)
2Q06 | Second quarter (3 months) of 2006 (example of date)
2D | Two dimensional
3D | Three dimensional
4D | Four dimensional
1P | Proved Reserves
2P | Proved plus Probable Reserves
3P | Proved plus Probable plus Possible Reserves
% | Percentage

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