DeGolyer and MacNaughton 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244 This is a digital representation of a DeGolyer and MacNaughton report. This file is intended to be a manifestation of certain data in the subject report and as such is subject to the same conditions thereof. The information and data contained in this file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information. Exhibit 15.4 DeGo l y e r a n d MacN augh ton 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244 April 17, 2026 Dr. Víctor Rodríguez Padilla Director General de Petróleos Mexicanos Avenida Marina Nacional No. 329 Torre Ejecutiva, Piso 44 Colonia Verónica Anzures, C.P. 11300 Alcaldía Miguel Hidalgo Ciudad de Mexico, Mexico Dear Dr. Víctor Rodríguez Padilla: Pursuant to your request, this report of third party presents an independent evaluation, as of January 1, 2026, of the estimated net proved oil, condensate, gas, and oil equivalent reserves of certain properties that Dirección de Exploración y Extracción de Petróleos Mexicanos (DEE) has represented are owned by the United Mexican States. This evaluation was completed on April 17, 2026. These properties are located in the United Mexican States. DEE has represented that these properties account for 4.87 percent on a net oil equivalent barrel basis of DEE’s net proved reserves as of January 1, 2026. We have reviewed information provided by DEE that it represents to be DEE’s estimates of the net reserves, as of January 1, 2026, for the same properties as those which we evaluated. DEE has represented that its net proved reserves estimates were prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the United States Securities and Exchange Commission (SEC). It is our opinion that the procedures and methodologies employed by DEE for the preparation of its proved reserves estimates as of January 1, 2026, comply with the current requirements of the SEC. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by DEE. DEE has represented that all subsurface hydrocarbons belong to the United Mexican States as stated in the Mexican Hydrocarbon Law (Ley de Hidrocarburos). DeGolyer and MacNaughton 2 At the request of DEE, this report also presents estimates prepared by DEE of its natural gas liquids (plant liquids) reserves; however, DEE has represented that its management of the properties stops at the inlet of the gas processing plants; therefore, DEE has no right to those quantities presented herein. Reserves estimates included herein are expressed as net reserves as represented by DEE. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2025. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by the United Mexican States and held by DEE after deducting all interests held by others, without consideration of royalties and other fiscal or contractual terms. Estimates of reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information. Information used in the preparation of this report was obtained from DEE. In the preparation of this report we have relied, without independent verification, upon information furnished by DEE with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination was not considered necessary for the purposes of this report. DeGolyer and MacNaughton 3 Definition of Reserves Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using established production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows: 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,

DeGolyer and MacNaughton 4 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. 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 DeGolyer and MacNaughton 5 (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. 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 [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty. DeGolyer and MacNaughton 6 Methodology and Procedures Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019.” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. Based on the current stage of field development, production performance, the development plan provided by DEE, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The undeveloped reserves estimates were based on opportunities identified in the plan of development provided by DEE. DEE has represented that its senior management is committed to the development plan provided by DEE and that DEE has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities. When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance methods were used to estimate OOIP and OGIP. Estimates of ultimate recovery were obtained after applying recovery factors to OOIP and OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors based on an DeGolyer and MacNaughton 7 analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid properties. For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available. In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available. For cases where history-matched dynamic models were available and applicable, model results were used to estimate recovery factors and reserves production forecasts. Data provided by DEE from wells drilled through December 31, 2025, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available through December 2025. Cumulative production, as of December 31, 2025, was deducted from the estimated gross ultimate recovery to estimate gross reserves. Oil and condensate reserves estimated herein are to be recovered by normal field separation. Plant liquids reserves estimated herein include propane, butane, and pentanes and heavier fractions (C5+) and are the result of low-temperature plant processing. Oil, condensate, and plant liquids reserves included in this report are expressed in millions of barrels (106bbl). In these estimates, 1 barrel equals 42 United States gallons. Gas quantities estimated herein are expressed as natural gas, sales gas, and dry gas. Natural gas is the total gas produced from the reservoir prior to processing or separation and includes all nonhydrocarbon components. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the inlet to the processing plant, after reduction for injection, fuel usage, flare, and shrinkage resulting from field separation. Dry gas is defined as the total gas to be produced from the reservoirs, measured at the tailgate of the processing plant, after reduction

DeGolyer and MacNaughton 8 for injection, fuel usage, flare, and shrinkage resulting from field separation and plant processing. Gas reserves estimated herein are reported as sales gas and dry gas. Gas quantities are expressed at a temperature base of 20 degrees Celsius (◦C) and at a pressure base of 1 atmosphere (atm). Gas quantities included in this report are expressed in billions of cubic feet (109ft3). Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas. Condensate, sales gas, plant liquids, and dry gas reserves were estimated by applying yields and shrinkages, provided by DEE and modified according to historical data when applicable, to estimates of natural gas quantities. At the request of DEE, dry gas quantities estimated herein were converted to dry gas equivalent to liquids on a field-by-field basis using an energy equivalent factor based on the dry gas composition of each field, as provided by DEE. In addition, natural gas quantities estimated herein were converted to oil equivalent on a field-by-field basis using an energy equivalent factor reflecting the yields and shrinkages of each field, as provided by DEE and modified according to historical data when applicable. In certain cases, the energy equivalent factors, yields, and shrinkages provided by DEE were modified considering the recent historical data. Gas quantities and reserves were estimated by considering the historical use of gas from each field and the natural gas usage plan provided by DEE. DEE has represented that the development activities provided and evaluated herein were approved internally within DEE. In general, development activities provided by DEE are scheduled to initiate within 5 years of the as-of date of this report for activities associated with proved undeveloped reserves. However, certain development activities associated with proved undeveloped reserves are scheduled to be initiated more than 5 years after initial disclosure. DeGolyer and MacNaughton 9 Primary Economic Assumptions This report has been prepared using initial prices, expenses, and costs provided by DEE in United States dollars (U.S.$). Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the reserves reported herein: Oil and Condensate Prices DEE has represented that the oil and condensate prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. As represented by DEE, the reference price utilized is the Mexican Mix reference price, which is composed of the Istmo, Maya, and Olmeca reference prices and is calculated based on a formula that includes the West Texas Sour, Light Louisiana Sweet, Brent, Oman, and Dubai reference prices. DEE supplied differentials by field to an average Mexican Mix reference price of U.S.$64.10 per barrel and the prices were held constant thereafter. The volume-weighted average adjusted prices attributable to the estimated proved reserves over the lives of the properties were U.S.$71.62 per barrel of oil and U.S.$26.75 per barrel of condensate. These prices were not escalated for inflation. Gas Prices DEE has represented that the gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. Each field’s calorific value, which includes plant liquids, was used to determine each field’s gas price. The volume-weighted average adjusted price attributable to the estimated proved reserves over the lives of the properties was U.S.$4.58 per thousand cubic feet of gas. These prices were not escalated for inflation. DeGolyer and MacNaughton 10 Operating Expenses, Capital Costs, and Abandonment Costs Estimates of operating expenses and future capital expenditures, provided by DEE and based on existing economic conditions, were held constant for the lives of the properties. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by DEE and were not adjusted for inflation. Estimates of operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of the undeveloped reserves estimated herein. In our opinion, the information relating to estimated proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a)(1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC; provided, however, that (i) estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year and (ii) certain development activities associated with proved undeveloped reserves are scheduled to be initiated more than 5 years after initial disclosure. To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor. DeGolyer and MacNaughton 11 Summary of Conclusions DeGolyer and MacNaughton has performed an independent evaluation of the extent of the estimated net proved oil, condensate, and gas reserves of certain properties in which DEE has represented it holds an interest. DEE has represented that its estimated net proved reserves attributable to the evaluated properties were based on the definition of proved reserves of the SEC. DEE’s estimates of the net proved quantities and reserves, as of January 1, 2026, attributable to these properties, which represent 4.87 percent of DEE’s reserves on a net oil equivalent basis, are summarized as follows, expressed in millions of barrels (106bbl), billions of cubic feet (109ft3), and millions of barrels of oil equivalent (106boe): Estimated by DEE as of January 1, 2026 Net Proved Reserves Natural Dry Gas Gas Sales Plant Dry Equivalent Oil Properties Evaluated by Quantities Oil Condensate Gas Liquids Gas To Liquids Equivalent DeGolyer and MacNaughton (109ft3) (106bbl) (106bbl) (109ft3) (106bbl) (109ft3) (106boe) (106boe) Proved Developed 939.8 147.0 2.3 916.7 61.2 642.1 123.5 334.0 Proved Undeveloped 48.9 20.2 0.1 45.5 3.0 32.3 6.2 29.5 Total Proved 988.7 167.2 2.4 962.2 64.2 674.4 129.7 363.5 Notes: 1. Reserves were estimated to the economic limit and did not consider the expiration of the contracts. 2. Dry gas equivalent to liquids was calculated based on dry gas reserves. 3. Dry gas reserves estimated herein were converted to dry gas equivalent to liquids on a field-by-field basis using an energy equivalent factor reflecting the dry gas composition of each field. 4. Oil equivalent was calculated based on oil reserves and natural gas quantities. 5. Natural gas quantities estimated herein were converted to oil equivalent on a field-by-field basis using an energy equivalent factor reflecting the yields and shrinkages of each field. 6. DEE has represented that totals may vary due to rounding. In comparing the detailed net proved reserves estimates prepared by DeGolyer and MacNaughton and by DEE, differences have been found, both positive and negative, resulting in an aggregate difference of 9.31 percent when compared on the basis of net oil equivalent barrels. It is DeGolyer and MacNaughton’s opinion that the net proved reserves estimates prepared by DEE on the properties evaluated and referred to above, when compared on the basis of net equivalent barrels, in aggregate, are reasonable. While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the January 1, 2026, estimated reserves.

DeGolyer and MacNaughton 12 DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in DEE. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of DEE. DeGolyer and MacNaughton has used all assumptions, procedures, data, and methods that it considers necessary to prepare this report. Submitted, DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716 Rafael Cavero Huapaya, P.E. Vice President DeGolyer and MacNaughton DeGolyer and MacNaughton CERTIFICATE of QUALIFICATION I, Rafael Cavero, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas 75244, U.S.A., hereby certify: 1. That I am a Vice President of DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to DEE dated April 17, 2026, and that I, as Vice President, was responsible for the preparation of this report of third party. 2. That I attended National University of Engineering (UNI), and that I graduated with a degree in Petroleum Engineering in the year 2002, and graduated from Heriot-Watt University, where I received a master’s degree in Reservoir Evaluation and Management in 2015; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 21 years of experience in oil and gas reservoir studies and reserves evaluations. Rafael Cavero Huapaya, P.E. Vice President DeGolyer and MacNaughton