Under the Mexican Constitution, all crude oil and other hydrocarbon reserves located in the subsoil of Mexico are owned by the Mexican nation and not by PEMEX. In August 2014, through the Round Zero process, the Mexican Government granted PEMEX the right to extract, but not own, certain petroleum and other hydrocarbon reserves in Mexico through assignment deeds.

This note provides supplementary information on the oil and gas exploration, development and production activities of PEMEX in compliance with the U.S. Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 932 10-5 “Extractive Activities—Oil and Gas” (“ASC Topic 932”) and Accounting Standards Update 2010-03 (see Note 3-G).

As of the date of these consolidated financial statements, all exploration and production activities of PEMEX are conducted in Mexico. The supplemental data presented herein reflect information for all of PEMEX’s oil and gas producing activities.


	2025		2024	2023
Proved Properties	Ps.	3,273,348,015	3,182,017,349	2,992,418,072
Construction in progress	86,819,244		101,026,986	87,417,444
Accumulated depreciation and amortization	(2,421,521,619)		(2,346,799,094)	(2,246,990,816)
Net capitalized costs	Ps.	938,645,640	936,245,241	832,844,700

Exploration costs include costs of geological and geophysical studies of fields in the amount of Ps. 17,368,569, Ps.14,672,428 and Ps.16,589,953 for 2025, 2024 and 2023, respectively. These costs are accounted for as geological and geophysical exploration expenses, in accordance with the successful efforts method of accounting.


	2025		2024	2023
Revenues from sale of oil and gas	Ps.	364,098,725	895,464,369	931,509,764
Hydrocarbon duties	194,573,038		198,488,864	338,881,974
Production costs (excluding taxes)	237,304,196		321,010,191	347,603,900
Other costs and expenses	41,583,205		59,261,551	56,536,914
Exploration expenses	50,709,597		60,148,763	16,589,853
Depreciation, depletion, amortization and accretion	116,757,857		99,491,976	116,710,477
	640,927,893		738,401,345	876,323,118
Results of operations for oil and gas producing activities	Ps.	(276,829,168)	157,063,024	55,186,646


Description	2025	2024	2023
	U.S.$	U.S.$	U.S.$
Weighted average sales price per barrel of oil equivalent (boe) (1)	47.34	57.73	54.76
Crude oil, per barrel	57.31	70.44	65.89
Natural gas, per thousand cubic feet	3.47	3.63	3.87

Under the Mexican Constitution, all oil and other hydrocarbon reserves located in the subsoil of Mexico are owned by the Mexican nation and not by PEMEX. Under the Petróleos Mexicanos Law, PEMEX has the right to extract, but not own, these reserves, and to sell the resulting production. The exploration and development activities of PEMEX are limited to reserves located in Mexico.

Proved oil and natural gas reserves are those estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate 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.

Proved reserves estimates as of December 31, 2025 were prepared by the Exploration and Extraction segment and were reviewed by the Independent Engineering Firms (as defined below), which audit its estimates of hydrocarbon reserves. According to the Lineamientos que Regulan los Procedimientos de Cuantificación y Certificación de Reservas de la Nación (Guidelines for Regulating the Nation’s Reserves Quantification and Certification Procedures), the Ministry of Energy should review and approve Hydrocarbon Reserves reports submitted by Mexico’s operators in the month of April or in some unforeseen circumstances in September. As of the date of these consolidated financial statements, the proved reserves estimates as of December 31, 2025 have not been approved by the Ministry of Energy.

PEMEX estimates proved reserves based on generally accepted petroleum engineering and evaluation methods and procedures, which are based primarily on applicable SEC regulations and, as necessary, the SPE’s publication entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information, dated June 25, 2019 and other

SPE publications, including the SPE’s publication entitled Petroleum Resources Management System, as well as other technical sources, including Estimation and Classification of Reserves of Crude Oil, Natural Gas, and Condensate, by Chapman Cronquist, and Determination of Oil and Gas Reserves, Petroleum Society Monograph Number 1, published by the Canadian Institute of Mining and Metallurgy & Petroleum. The choice of method or combination of methods employed in the analysis of each reservoir is determined by:

Reserves data set forth herein represents only estimates. Reserves valuation is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserves estimate depends on the quality of available data, engineering and geological interpretation and professional judgment. As a result, estimates of different engineers may vary. In addition, the results of drilling, testing and producing subsequent to the date of an estimate may lead to the revision of an estimate.

In order to ensure the reliability of PEMEX’s reserves estimation efforts, it has undertaken the internal certification of its estimates of reserves since 1996. PEMEX has established certain internal controls in connection with the preparation of its proved reserves estimates. Initially, teams of geoscientists from PEMEX exploration and extraction business units (with each of these units covering several projects) prepare the reserves estimates, using different estimation processes for valuations relating to new discoveries and developed fields, respectively. Subsequently, the regional reserves offices collect these reserves estimates from the units and request that the Gerencia de Recursos y Reservas de Hidrocarburos, (Office of Hydrocarbon Resources and Reserves), the central hydrocarbon reserves management body of PEMEX, review and certify such valuations and the recording of the related reserves. This internal certification process is undertaken in accordance with internal guidelines for estimating and classifying hydrocarbon reserves, which are based on the SEC’s rules and definitions.

The Office of Hydrocarbon Resources and Reserves, which additionally oversees and conducts an internal audit of the above process, consists entirely of professionals with geological, geophysical, petrophysical and reservoir engineering backgrounds. The engineers who participate in PEMEX’s reserves estimation process are experienced in the following areas: reservoir numerical simulation; well drilling and completion; pressure, volume and temperature (PVT) analysis; analytical tools used in forecasting the performance of the various elements comprising the production system; and design strategies in petroleum field development. Furthermore, all of PEMEX’s personnel have been certified by the Secretaría de Educación Pública (Ministry of Public Education), most have earned master’s degrees in areas of study such as petroleum engineering, geology and geophysical engineering and they possess an average of over twenty years of professional experience.

In addition to this internal review process, PEMEX final reserves estimates are audited by independent engineering firms. Three independent engineering firms audited PEMEX estimates of proved reserves as of December 31, 2025 or January 1, 2026: DeGolyer and MacNaughton (“DeGolyer”), Ryder Scott Company L.P (“Ryder Scott”) and GLJ LTD. (“GLJ”), together, the “Independent Engineering Firms.” The reserves estimate reviewed by the Independent Engineering Firms totaled 76.1% of PEMEX’s estimated proved reserves. The remaining 23.9% of PEMEX’s estimated proved reserves consisted of reserves located, among others, in onshore fields in the northern region of Mexico, certain offshore fields and fields related to exploration and production contracts, in which a corresponding third party is responsible for assessing the volume of reserves.

GLJ audited the reserves in the Cantarell, Ku Maloob Zaap, Reynosa, Veracruz, Cinco Presidentes and Macuspana-Muspac, business units; Ryder Scott audited the reserves in the Poza Rica-Altamira, Bellota-Jujo, Samaria-Luna, Abkatún-Pol-Chuc and Litoral de Tabasco business units, and DeGolyer and MacNaughton audited the reserves in the fields recently added to our inventory registry. The audits conducted by the Independent Engineering Firms consisted primarily of: (1) analysis of historical static and dynamic reservoir data provided by PEMEX; (2) construction or updating of the Independent Engineering Firms’ own static and dynamic reservoir characterization models of some of the fields; (3) economic analysis of the fields; and (4) review of PEMEX production forecasts and reserves estimates.

Since reserves estimates are, by definition, only estimates, they cannot be reviewed for the purpose of verifying exactness. Instead, the Independent Engineering Firms conducted a detailed review of PEMEX reserves estimates so that they could express an opinion as to whether, in the aggregate, the reserves estimates that PEMEX furnished were reasonable and had been estimated and presented in conformity with generally accepted petroleum engineering and evaluation methods and procedures.

All questions, including any suggested modifications to proved reserves estimates, that arose during the Independent Engineering Firms’ review process were resolved by PEMEX to the satisfaction of the Independent Engineering Firms. The Independent Engineering Firms have concluded that PEMEX’s estimated total proved oil and natural gas reserve volumes set forth in this report are, in the aggregate, reasonable and have been prepared in accordance with Rule 4-10(a) are consistent with international reserves reporting practice and are in accordance with the revised oil and gas reserves disclosure provisions of ASC Topic 932.

PEMEX´s total proved developed and undeveloped reserves of crude oil, condensates and liquefiable hydrocarbons recoverable from field processing plants decreased by 2.6% in 2025, from 5,494.5 million barrels at December 31, 2024 to 5,351.9 million barrels at December 31, 2025. PEMEX’s proved developed reserves of crude oil, condensates and liquefiable hydrocarbons recoverable from processing plants decreased by 8.7% in 2025, from 3,463.9 million barrels on December 31, 2024 to 3,162.1 million barrels at December 31, 2025. The proved reserves of crude oil, condensates and liquefiable hydrocarbons added by PEMEX in 2025 through revisions, extensions and discoveries totaled 507.4 million barrels, which was not sufficient to offset total production for the year of 650.0 million barrels of crude oil, condensates and liquefiable hydrocarbons.

PEMEX’s total proved developed and undeveloped dry gas reserves increased by 8.4% in 2025, from 10,173.6 billion cubic feet as of December 31, 2024 to 11,025.9 billion cubic feet as of December 31, 2025. PEMEX’s proved developed dry gas reserves increased by 22.2% in 2025, from 5,773.4 billion cubic feet as of December 31, 2024 to 7,054.0 billion cubic feet as of December 31, 2025. This increase was principally due to an upsurge in proved developed dry gas reserves of Ixachi field. The amount of proved developed and undeveloped dry gas reserves added in 2025 was sufficient to offset the level of production in 2025, which amounted to 901.0 billion cubic feet of dry gas. PEMEX’s proved undeveloped dry gas reserves decreased by 9.7% in 2025, from 4,400.2 billion cubic feet as of December 31, 2024 to 3,971.9 billion cubic feet as of December 31, 2025. This decrease in proved undeveloped reserves was due to the development of the Ixachi field, mainly due to the drilling of development wells and revisions, which allowed these reserves to be classified as proven developed reserves.

During 2025, our exploration activities in shallow waters of the Gulf of Mexico and onshore regions resulted in the discovery of two new hydrocarbon fields (Konen and Iklum) and confirmed the extension of an existing field (Bakte) due to an appraisal well that was determined to be viables. Together, these discoveries led to the incorporation of 12.2 million barrels of oil equivalent of proved reserves.


	Crude oil and Condensates (2)	Dry Gas (3)
	(in millions of barrels)	(in billions of cubic feet)
Proved developed and undeveloped reserves:
Proved developed reserves	3,162.1	7,054.0
Proved undeveloped reserves	2,189.8	3,971.9
Total proved reserves	5,351.9	11,025.9

(3)Reserve volumes reported in this table are volumes of dry gas, although natural gas production reported in other tables refers to sour wet gas. There is a shrinkage in volume when natural gas liquids and impurities are extracted to obtain dry gas. Therefore, reported natural gas volumes are greater than dry gas volumes.


	2025	2024	2023
	(in millions of barrels)
Proved developed and undeveloped reserves:
At January 1,	5,494	5,894	6,089
Revisions (2)	498	271	529
Extensions and discoveries	10	26	16
Production	(650)	(705)	(744)
Farm outs & transfer to exploration and production contracts (CEE) & transfer of fields due to NHC bidding process	—	8	4
At December 31,	5,352	5,494	5,894
Proved developed reserves at December 31,	3,162	3,464	3,500
Proved undeveloped reserves at December 31,	2,190	2,031	2,394


	2025	2024	2023
	(in billions of cubic feet)
Proved developed and undeveloped reserves:
At January 1,	10,175	8,251	7,080
Revisions (1)	1,738	2,752	2,069
Extensions and discoveries	14	56	12
Production (2)	(901)	(888)	(917)
Farm outs & transfer to exploration and production contracts (CEE) & transfer of fields due to NHC bidding process	—	4	7
At December 31,	11,026	10,175	8,251
Proved developed reserves at December 31,	7,054	5,773	4,314
Proved undeveloped reserves at December 31,	3,972	4,400	3,936

(2)Production refers here to dry gas, although natural gas production reported in other tables refers to sour wet gas. There is a shrinkage in volume when natural gas liquids and impurities are extracted to obtain dry gas. Therefore, reported natural gas volumes are greater than dry gas volumes.

PEMEX reserve-replacement ratio, or RRR, for a given period is calculated by dividing the sum of proved reserves additions due to discoveries, developments, delineations and revisions by that period’s total production. During 2025, PEMEX obtained an increase of 844.5 million barrels of oil equivalent of proved reserves as aggregated from discoveries, revisions, delimitations and development and production, which represents a RRR of 102.6% in 2025, an increase as compared to a RRR of 96.6% in 2024.

PEMEX’s reserves production ratio, which is presented in terms of years, is calculated by dividing the estimated remaining reserves at the end of the relevant year by the total production of hydrocarbons for that year. As of December 31, 2025, this ratio is 9.1 years for proved reserves.

Estimated future cash inflows from production are computed by applying average prices of oil and gas on the first day of each month of 2025. Future development and production costs are those estimated future expenditures needed to develop and produce the year-end estimated proved reserves after a net cash flows discount factor of 10%, assuming constant year-end economic conditions.

Future tax expenses are computed by applying the appropriate year-end statutory tax rates with consideration of the tax rates of the new fiscal regime for PEMEX already legislated for 2025 to the future pre-tax net cash flows related to PEMEX’s proved oil and gas reserves.

The standardized measure provided below represents a comparative benchmark value rather than an estimate of expected future cash flows or fair market value of PEMEX’s production rights. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. Accordingly, reserve estimates may be materially different from the quantities of crude oil and natural gas that are ultimately recovered.


	2025	2024	2023
	(in millions of U.S. dollars)
Future cash inflows	292,248	325,024	362,836
Future production costs (excluding profit taxes)	(115,212)	(108,034)	(157,758)
Future development costs	(32,375)	(26,880)	(26,082)
Future cash flows before tax	144,661	190,110	178,996
Future production and excess gains taxes	(81,100)	(98,122)	(135,723)
Future net cash flows	63,561	91,988	43,273
Effect of discounting net cash flows by 10%	(26,789)	(37,864)	(15,421)
Standardized measure of discounted future net cash flows	36,772	54,124	27,852


	2025	2024	2023
	(in millions of U.S. dollars)
Sales of oil and gas produced, net of production costs	(38,587)	(34,933)	(41,751)
Net changes in prices and production costs	(24,622)	37,159	(96,667)
Extensions and discoveries	279	921	540
Development cost incurred during the year	5,229	6,011	8,657
Changes in estimated development costs	(6,704)	(7,629)	(6,012)
Reserves revisions and timing changes	12,147	13,860	16,737
Accretion of discount of pre-tax net cash flows	10,622	7,192	18,679
Net changes in production and excess gains taxes	24,284	3,691	64,747
Aggregate change in standardized measure of discounted future net cash flows	(17,352)	26,272	(35,070)
Standardized measure:
As of January 1	54,124	27,852	62,922
As of December 31	36,772	54,124	27,852
Change	(17,352)	26,272	(35,070)

In computing the amounts under each factor of change, the effects of variances in prices and costs are computed before the effects of changes in quantities. Consequently, changes in reserves are calculated as of December 31 prices and costs.