UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16 of the

Securities Exchange Act of 1934

For the month of March, 2026

Commission File Number 1-15106

PETRÓLEO BRASILEIRO S.A. – PETROBRAS

(Exact name of registrant as specified in its charter)

Brazilian Petroleum Corporation – PETROBRAS

(Translation of Registrant's name into English)

Avenida Henrique Valadares, 28 – 9th floor 
20231-030 – Rio de Janeiro, RJ
Federative Republic of Brazil

(Address of principal executive office)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F. 

Form 20-F ___X___ Form 40-F _______

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes _______ No___X____

INDEX

Petróleo Brasileiro S.A. – Petrobras

Consolidated Statements of Financial Position

PETROBRAS

As of December 31, 2025 and December 31, 2024 (Expressed in millions of US Dollars, unless otherwise indicated)

Consolidated Statements of Income

PETROBRAS

Years ended December 31, 2025, 2024 and 2023 (Expressed in millions of US Dollars, unless otherwise indicated)

Consolidated Statements of Comprehensive Income

PETROBRAS

Years ended December 31, 2025 and 2024 and 2023 (Expressed in millions of US Dollars, unless otherwise indicated)

Consolidated Statements of Cash Flows

PETROBRAS

Years ended December 31, 2025 and 2024 and 2023 (Expressed in millions of US Dollars, unless otherwise indicated)

Consolidated Statements of Changes in Shareholders’ Equity

PETROBRAS

Years ended December 31, 2025 and 2024 and 2023 (Expressed in millions of US Dollars, unless otherwise indicated)

Petróleo Brasileiro S.A. (Petrobras), hereinafter referred to as “Petrobras” or “Company,” is a partially state-owned enterprise, controlled by the Brazilian Federal Government, of indefinite duration, governed by the terms and conditions under the Brazilian Corporate Law (Law 6,404 of December 15, 1976), Law 13,303 of June 30, 2016 and its Bylaws.

Petrobras’ shares are listed on the Brazilian stock exchange (B3) in the Level 2 of Corporate Governance special listing segment and, therefore, the Company, its shareholders, its managers and fiscal council members are subject to provisions under its regulation (Level 2 Regulation - Regulamento de Listagem do Nível 2 de Governança Corporativa da Brasil Bolsa Balcão – B3). The provisions of the Level 2 Regulation shall prevail over statutory provisions in the event of harm to the rights of public offers investors provided for in the Company's Bylaws, except when otherwise determined by other regulation.

The Company is dedicated to prospecting, drilling, refining, processing, trading and transporting crude oil from producing onshore and offshore oil fields and from shale or other rocks, as well as oil products, natural gas and other liquid hydrocarbons. In addition, Petrobras carries out energy related activities, such as research, development, production, transport, distribution and trading of all forms of energy, including activities related to the treatment and storage of carbon dioxide, energy transition and the low-carbon economy, as well as other related or similar activities.

Petrobras may perform any of the activities related to its corporate purpose, directly, through its wholly-owned subsidiaries, controlled companies, alone or through joint ventures with third parties, in Brazil or abroad.

The economic activities linked to its business purpose shall be undertaken by the Company in free competition with other companies according to market conditions, in compliance with the other principles and guidelines of Laws no. 9,478/97 and 14,134/21 (oil and gas regulations, respectively). However, Petrobras may have its activities, provided they are in compliance with its corporate purpose, guided by the Brazilian Federal Government to contribute to the public interest that justified its creation, aiming to meet national energy policy objectives when:

I – established by law or regulation, as well as provided for under a contract, covenant, or adjustment agreed upon with a public entity that is competent to establish such obligation, abiding by the broad publicity of such instruments; and

II – the cost and revenues thereof have been broken down and disseminated in a transparent manner.

In this case, the Company’s Investment Committee and Minority Shareholders Committee, exercising their advisory role to the Board of Directors, shall assess and measure the difference between such market conditions and the operating result or economic return of the transaction, based on technical and economic criteria for investment valuation and specific operating costs and results under the Company's operations. In case a difference is identified, for every financial year, the Brazilian Federal Government shall compensate the Company.

These consolidated financial statements have been prepared and are being presented in accordance with the IFRS accounting standards as issued by the International Accounting Standards Board (IASB).

The consolidated financial statements have been prepared under the historical cost convention, except when otherwise indicated. The significant accounting policies used in the preparation of these financial statements are set out in their respective explanatory notes.

The preparation of the financial statements requires the use of estimates based on assumptions and judgements, which may affect the application of accounting policies and reported amounts of assets, liabilities, revenues and expenses. Actual results may differ from these estimates. Relevant estimates and judgments with a higher level of complexity are disclosed in explanatory note 4.

To enhance the understanding of its financial position, the Company made certain changes to the presentation of the consolidated financial statements for the previous years, and applied to the current year, as follows:

These consolidated financial statements were approved and authorized for issue by the Company’s Board of Directors in a meeting held on March 5, 2026.

The functional currency of Petrobras and all of its Brazilian subsidiaries is the Brazilian Real. The functional currency of the Petrobras direct subsidiaries that operate outside Brazil is the U.S. dollar.

Petrobras has selected the U.S. dollar as its presentation currency to facilitate a more direct comparison to other oil and gas companies. The financial statements have been translated from the functional currency (Brazilian real) into the presentation currency (U.S. dollar). All assets and liabilities are translated into U.S. dollars at the closing exchange rate at the date of the financial statements; income and expenses, as well as cash flows are translated into U.S. dollars using the average exchange rates prevailing during the period. All exchange differences arising from the translation of the consolidated financial statements from the functional currency into the presentation currency are recognized as cumulative translation adjustments (CTA) within accumulated other comprehensive income in the consolidated statements of changes in shareholders’ equity.

To aid cohesion and comprehension, the significant accounting policies are set out at the end of each explanatory note to which they relate.

The preparation of the consolidated financial information requires the use of estimates and judgments for certain transactions. The following are the key judgments and the main sources of estimation uncertainty with a significant risk of causing material adjustments to the Company's key accounting estimates over the next fiscal year.

After obtaining the legal rights to explore a specific area, the Company uses the successful efforts method to recognize costs incurred in connection with the exploration and evaluation of mineral resources, before demonstrating technical and commercial feasibility of extracting those resources. This method requires a direct relationship between costs incurred and mineral resources for these costs to be characterized as assets. The types of exploration costs and their respective recognition are presented in note 26.

The moment in which the technical and commercial feasibility of extracting a mineral resource is determined requires management judgments. An internal commission of technical executives of the Company periodically reviews the conditions of each well, by analysis of geological, geophysical and engineering data, as well as economic conditions, operating methods and government regulations.

The Company considers that the technical and commercial feasibility of a mineral resource can be demonstrated when the project has all the necessary information to characterize the reservoir as a proved reserve. Costs associated with non-commercial mineral resources are recognized as expenses in the period when identified.

According to the definitions prescribed by the SEC, proved oil and natural 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 feasible from a given date, from known reservoirs and under existing economic conditions, operating methods and government regulation.

The Company also determines reserves according to the criteria of the National Agency for Petroleum, Natural Gas and Biofuels / Society of Petroleum Engineers (ANP/SPE). The main differences between these criteria and the SEC criterion are related to the use of different economic assumptions and the possibility of considering as reserves, in the ANP/SPE criteria, the volumes expected to be produced beyond the concession contract expiration date in fields in Brazil, according to the ANP technical reserves regulations.

Impairment testing of non-financial assets involves uncertainties mainly related to: (a) the average Brent prices and to the Brazilian real/U.S. dollar average exchange rate, whose estimates are relevant to virtually all of the Company's operating segments; (b) discount rates; and (c) estimated proved and probable reserves (according to the criteria established by the ANP/SPE, as described in note 4.1). A significant number of interdependent variables used to determine value in use are derived from these key assumptions, and their application in impairment testing involves a high degree of complexity. Value in use represents the present value of estimated future cash flows originating from an asset or a cash-generating units (CGU).

A sensitivity analysis for assets or CGUs most sensitive to future impairment losses or reversals in the next year is presented in note 25.

Average Brent prices and average exchange rate

The markets for crude oil and natural gas have a history of significant price volatility and, although prices can drop or increase precipitously, industry prices over the long term tend to be driven by market supply and demand fundamentals.

Brent prices and exchange rate projections are derived from the Business Plan and are consistent with market evidence, such as independent macro-economic forecasts, industry analysts and experts. Backtesting analysis and feedback processes in order to continually improve forecast techniques are also performed.

The Company’s oil price forecast model is based on a nonlinear relationship between variables reflecting market supply and demand fundamentals. This model also takes into account other relevant factors, such as the effects of the Organization of the Petroleum Exporting Countries (OPEC) decisions on the oil market, industry costs, idle capacity, oil and gas production forecasted by specialized firms, and the relationship between the oil price and the Brazilian Real/U.S. dollar exchange rate.

The process of projecting Brazilian real/U.S. dollar exchange rate is based on econometric models that consider long-term assumptions involving observable inputs, such as commodity prices, country risk, interest rates in the U.S. and the value of the U.S. dollar relative to a basket of foreign currencies (U.S. dollar Index – USDX).

Changes in the economic environment may result in changing assumptions and, consequently, the recognition of impairment losses or reversals on certain assets or CGUs. For example, the Company’s sales revenues and refining margins are directly impacted by Brent price variations, as well as Brazilian Real/U.S. dollar exchange rate variations, which also impacts our capital and operating expenditures.

Note 25 presents Brent prices and exchange rate estimates of the Company.

Discount rates

The discount rates used in impairment tests reflect specific risks associated with the estimated cash flows of the assets or CGUs. For example, changes in the economic and political environment may result in higher country risk projections, causing increases in the discount rates used in impairment tests, as well as investment decisions that result in the postponement or interruption of projects considering specific risks related to non-completion or delayed start of operations.

Note 25 presents the main discount rates applied in impairment tests.

Estimated proved and probable reserves

Reserves estimates, according to the criteria established by the ANP/SPE (as set out in note 4.1) are revised at least annually, based on updated geological and production data of reservoirs, as well as on changes in prices and costs used in these estimates. Revisions may also result from significant changes in the Company’s strategy for development projects or in the production capacity.

Although the Company is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a sort of factors including completion of production development projects, reservoir performance, regulatory aspects and significant changes in long-term oil and gas price levels.

A cash-generating unit (CGU) represents the smaller identifiable group of assets that generate cash inflows, which are largely independent of the cash inflows of other assets or groups of assets. Identifying CGUs requires management assumptions and judgment, based on the Company’s business and management model.

Changes in CGUs resulting from the review of investment, strategic or operational factors, may result in changes in the interdependencies of assets and, consequently, alter the aggregation or breakdown of assets that were part of certain CGUs, which may influence their ability to generate cash and cause additional losses or reversals in the recovery of such assets. If the approval for the sale of a CGU’s component occurs between the reporting date and the date of the issuance of the consolidated financial statements, the Company reassesses whether the value in use of this component, estimated with the information existing at the reporting date, reasonably represents its fair value, net of disposal expenses. Such information must include evidence of the stage at which management was committed to the sale of the CGU’s component.

The primary considerations in identifying the CGUs are set out as follows:

Further information on impairment testing is set out in note 25.

As presented in note 23, assets directly related to the oil and gas production are depleted using the units of production method, calculated by monthly production over the respective developed proved reserves, except for the signature bonuses, which are calculated over total proved reserves.

Proved developed reserves are those for which recovery can be expected: (i) through existing wells, 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 (ii) through extraction equipment and operational infrastructure installed at the time of the reserves estimate, if the extraction is carried out by means that do not involve a well.

Estimates of proved reserves volumes used in the units of production method are prepared by Company’s technicians according to the SEC definitions (as described in note 4.1). Revisions to the Company’s proved developed and undeveloped reserves impact prospectively the amounts of depreciation, depletion and amortization recognized in the statement of income and the carrying amounts of oil and gas properties assets. Information on uncertainties related to reserve volume estimates are presented in note 4.1.

Therefore, assuming all other variables remain constant, a decrease in estimated proved reserves would increase, prospectively, depreciation, depletion and amortization expense, while an increase in reserves would reduce depreciation, depletion and amortization.

The net actuarial liability represents the Company's actuarial obligations, net of fair value of plan assets (when applicable), at present value, as described in note 19.3.2.

The actuarial obligations and net expenses related to defined benefit pension and health care post-employment plans are computed based on several financial and demographic assumptions, of which the most significant are:

a) Discount rate: comprises the projected future inflation in addition to an equivalent discounted interest rate that matches the duration of the pension and health care obligations with the future yield curve of long-term Brazilian Government Bonds; and

b) Medical and hospital costs changes rate: comprise the projected growth rates based on per capita health care benefits paid over the last five years, which are used as a basis for projections, converged to the general price inflation index within 30 years.

These and other actuarial assumptions are revised at least annually and may differ materially from actual results due to changes in market and economic conditions.

The measurement uncertainties associated with the defined benefit obligation and a sensitivity analysis of discount rates and changes in medical costs are disclosed in notes 19.3.6 and 19.3.7, respectively.

The Company is part in arbitrations and in legal and administrative proceedings involving civil, tax, labor and environmental issues arising from the normal course of its business and makes use of estimates to recognize the amounts and the probability of outflow of resources, based on reports and technical assessments from legal advisors and on management’s assessment.

These estimates are performed individually, or aggregated if there are cases with similar characteristics, primarily considering factors such as assessment of the plaintiff’s demands, consistency of the existing evidence, jurisprudence on similar cases and doctrine on the subject. Specifically for lawsuits by outsourced employees, the Company estimates the expected loss based on a statistical procedure, due to the number of actions with similar characteristics.

Arbitral, legal and administrative decisions against the Company, new jurisprudence and changes of existing evidence can result in changes on the probability of outflow of resources and on the estimated amounts, according to the assessment of the legal basis.

Note 20 provides further detailed information about contingencies and legal proceedings.

The Company has legal obligations to remove equipment and restore onshore and offshore areas at the end of operations, in the E&P segment. Its most significant asset removal obligations relate to offshore areas. Estimates of costs for future environmental cleanup and remediation activities are based on current information about costs and expected plans for remediation. The timing of abandonment and dismantling of areas is based on the length of reserves depletion, in accordance with the ANP/SPE definitions (as described in note 4.1). Therefore, revisions to reserves estimates that result in changes in the timing of reserves depletion may impact the provision for decommissioning cost. For additional information about revisions to the Company’s reserves estimates, see note 4.1.

These obligations are recognized at present value, using a risk-free discount rate, adjusted to the Company's credit risk. Changes in the discount rate can cause significant variations in the recognized amount, due to the long-term nature until abandonment. A sensitivity analysis of discount rates used in the calculation of the provision for decommissioning costs is presented in note 20.

The calculation to determine the amounts to be provisioned are complex, since: i) the obligations are long-term; ii) the contracts and regulations contain subjective definitions of the removal and remediation practices and criteria involved when the events occur; and iii) asset removal technologies and costs are constantly changing, along with regulations, environmental, safety and public relations considerations. Additionally, abandonment costs are mostly denominated in U.S. dollars, which may result in significant changes in the estimates due to changes in the exchange rates overtime.

The Company constantly conducts studies to incorporate technologies and procedures to optimize the process of abandonment, considering industry best practices. However, the timing and amounts of future cash flows are subject to significant uncertainty.

In the event of a total or partial sale of interest in E&P contracts, the Company remains jointly liable for decommissioning costs after its production has ceased, if the purchaser fails to comply with this obligation, as determined by the ANP.

Provisions for decommissioning costs associated with the Company’s Refining, Transportation and Marketing (RT&M) and Gas and Low Carbon Energy (G&EBC) segments are not recognized as there is no legal or contractual obligation, nor any agreement with third parties for the decommissioning of assets in these segments. Changes in circumstances may require the recognition of provisions for decommissioning costs for such assets. However, such changes are not expected by the Company.

Note 21 provides further information about provision for decommissioning costs.

The Company uses incremental borrowing rates to determine the present value of the lease payments, when the interest rate implicit in the lease cannot be readily determined.

The determination of incremental rates requires estimates based on corporate funding rates (obtained from the yields on bonds issued by Petrobras), which take into account the risk-free rate and the Company's credit risk premium, adjusted to reflect the specific conditions and characteristics of the lease, such as the risk of the country's economic environment, guarantees, currency and duration of the payment flow.

The present value of lease liabilities is determined based on the incremental rates estimated at the start date of each lease. Therefore, even in cases where lease agreements have similar characteristics, their cash flows may be discounted at significantly different incremental rates depending on the Company's corporate funding rates on the start date of each lease.

Note 31 presents information on lease arrangements by class of underlying assets.

The Company determines its “highly probable future exports” based on its current Business Plan and on short-term estimates on a monthly basis. The highly probable future exports are determined by a percentage of projected export revenues.

The estimate of the amount of highly probable future exports considers future uncertainty regarding the Brent oil prices, oil production and demand for products in a model which optimizes the Company's operations and investments, in addition to considering the historical profile of exported volume in relation to total oil production.

As described in note 33.3.1, foreign exchange gains and losses relating to the effective portion of hedging instruments are recognized in other comprehensive income and reclassified to the statement of income within finance income (expense) in the periods when the hedged item affects the statement of income. However, if future exports for which foreign exchange gains and losses hedging relationship has been designated is no longer expected to occur, any related cumulative foreign exchange gains or losses that have been recognized in other comprehensive income from the date the hedging relationship was designated to the date the Company revoked the designation is immediately recycled from other comprehensive income to the statement of income.

For the long term, future exports forecasts are reviewed whenever the Company reviews its Business Plan assumptions, while for the short-term future exports are reviewed monthly. The approach for determining highly probable future exports is reviewed annually, at least.

See note 33.3.1 for more detailed information about cash flow hedge accounting and a sensitivity analysis of the cash flow hedge involving future exports.

Income taxes rules and regulations may be interpreted differently by tax authorities, and situations may arise in which these interpretations differ from the Company's understanding.

Uncertainties over income taxes treatments represent the risks that the tax authority does not accept a certain tax treatment applied by the Company, mainly related to different interpretations of deductions and additions to the income taxes calculation basis. The Company evaluates each uncertain tax treatment separately or in a group where there is interdependence in relation to the expected result.

The Company estimates the probability of acceptance of an uncertain tax treatment by the tax authority based on technical assessments by its legal advisors, considering precedent jurisprudence applicable to current tax legislation, which may be impacted mainly by changes in tax rules or court decisions which may affect the analysis of the fundamentals of uncertainty. The tax risks identified are evaluated, treated and, when applicable, follows a pre-determined tax risk management methodology.

If it is probable that the tax authorities will accept an uncertain tax treatment, the amounts recorded in the financial statements are consistent with the tax records and, therefore, no uncertainty is reflected in the measurement of current or deferred income taxes. If it is not probable that the tax authorities will accept an uncertain tax treatment, the uncertainty is reflected in the measurement of current or deferred income taxes in the financial statements.

The effect of uncertainty for each uncertain tax treatment is estimated by using the method that provides the best prediction of the resolution of the uncertainty. The most probable amount method provides as an estimate the single most probable amount in a set of possible outcomes, while the expected amount method represents the sum of the amounts weighted by the probability in relation to a range of possible outcomes.

Additional information on uncertainty over income taxes treatments is disclosed in Note 18.1.

Credit losses correspond to the difference between all contractual cash flows owed to the Company and all cash flows that the entity expects to receive, discounted at the original effective interest rate. The expected credit loss of a financial asset corresponds to the average of expected credit losses weighted by the respective default risks.

Expected credit losses on financial assets are based on assumptions relating to risk of default, the determination of whether there has been a significant increase in credit risk, expectation of recovery, among others. The Company uses judgment for such assumptions in addition to information from credit rating agencies and inputs based on collection delays.

Notes 14.2 and 14.3 provide details on the expected credit losses recognized by the Company.

As a result of the Second Bidding Round for the Surplus Volume of the Transfer of Rights Agreement under the Production Sharing regime, the Company signed amendments and new agreements in 2022 with partners in the Atapu and Sépia fields. These agreements provide, in addition to the compensation already received upon signature, possible additional amounts receivable that may be owed to the Company, linked to Brent price, according to the conditions described in note 29.2.

Additionally, over the last few years the Company has sold assets considered non-strategic and established partnerships in E&P assets aiming, among other objectives, at sharing risks and developing new technologies. Such transactions were carried out through partnerships (note 27) and divestments, with procedures aligned with current legislation and regulatory bodies. In some of these transactions, contingent receipts are also provided for, subject to contractual clauses, linked to Brent price (note 29.2).

Climate change may result in both negative and positive effects for the Company. Potential negative effects of climate change for the Company are referred to as climate-related risks. Inversely, potential positive effects of climate change for the Company are referred to as climate-related opportunities.

Climate risks are categorized as: (i) climate-related transition risks (transition risks); and (ii) climate-related physical risks (physical risks).

The Company’s Business Plan 2026-2030 incorporates actions and goals related to the transition towards a low-carbon economy. These initiatives include, among others, decarbonization projects for operations aimed at achieving the Company’s carbon sustainability commitments.

Accounting estimates are monetary amounts in financial statements that are subject to measurement uncertainty.

The following information used in relevant accounting estimates of the Company is largely determined based on the assumptions and projections of the Business Plan 2026-2030:

As presented in the following topic, the Company considered the effects related to climate risks in its Business Plan approved by the Board of Directors, which is updated annually, including actions to achieve its climate commitments and its long-term ambition to neutralize Greenhouse Gas (GHG) emissions of scopes 1^[1] and 2^[2] by 2050.

The aforementioned ambition and commitments are not guarantees of future performance by the Company and are subject to assumptions that may prove incorrect and to risks and uncertainties that are difficult to predict.

Transition risks arise from efforts associated with the transition to a low-carbon economy. In this category, the Company has identified the following risks that can reasonably be expected to affect its cash flows, access to financing or cost of capital:

The risks above were considered in the development of the Company's Business Plan 2026-2030. Such consideration was based on the following external environment assumptions that reflect the dynamics of the energy sector:

^[1] direct GHG emissions, which occur from energy sources that are owned or controlled by the Company.

^[2] Indirect GHG emissions, which come from energy sources purchased and consumed by the Company, which occur at the facilities where the energy sources are generated.

As a result of this, demand and prices, both domestic and international, of the main products considered in Business Plan 2026-2030 are negatively affected.

In 2025, the Company adopted three distinct scenarios that are used for different purposes in its planning activities. These scenarios are called Adaptation, Negotiation and Commitment. In all of them, there is a slowdown and subsequent contraction of fossil fuel sources, as well as an increase in demand for renewables and low-carbon solutions, in a different manner between developed and developing markets. The Negotiation scenario, which is used as a reference scenario for quantifying the Company's Business Plan, considers that fossil fuels, which currently represent approximately 80% of the world’s primary energy sources, will represent around 48% by 2050. The share of oil will decrease from the current 30% to around 20% of the world’s primary energy sources. Despite this reduction, oil demand is expected to remain significant over this time horizon.

The Brent price considered in the reference scenario of the Business Plan for 2050 increased from US$ 65 per barrel in Business Plan 2025-2029 to US$ 70 per barrel in Business Plan 2026-2030. For additional information about the behavior of the Brent price considered in the Company's Business Plans, see note 25. The following table compares the oil price used in the reference scenario for the years 2035 and 2050 with those projected in the Announced Pledges Scenario (APS) and Net Zero Emission (NZE) scenarios by the International Energy Agency (IEA), even though they are not directly used by the Company:

According to the IEA, the APS scenario^[3] released in 2024 considers that all climate commitments made by governments around the world, including Nationally Determined Contributions (NDCs), as well as long-term net-zero targets, will be met in full and on time, with an increase of approximately 1.7^oC in temperature by 2100 (with a 50% probability of occurrence). Regarding the NZE scenario^[4] released in 2025, according to the IEA, it presents a pathway for the global energy sector to achieve net-zero CO₂ emissions by 2050, consistent with limiting the temperature increase to 1.5 °C (with at least a 50% probability of occurrence).

The Company's accounting estimates did not incorporate the effect of carbon pricing. Currently, due to uncertainties regarding the implementation and dynamics of the carbon market in Brazil, the Company considers it necessary to await the regulation of Law No. 15,042 in 2024, which establishes the SBCE. This regulation will provide the necessary and sufficient details to reliably and reasonably assess the impact on the cash flows of Petrobras's assets and its CGUs. In October 2025, the Extraordinary Secretariat for the Carbon Market was established to organize the SBCE, which will issue the necessary additional regulation to implement Law No. 15,042 of 2024.

a.1) Potential effects on the value in use in impairment tests

When measuring the value in use of its assets, the Company bases its cash flow projections on reasonable and supportable assumptions that represent management's best estimate of the range of economic conditions.

^[3] The APS scenario, which was included in previous editions, was not addressed in the World Energy Outlook 2025 (WEO 2025). This scenario, which assumes the full and timely implementation of major national energy and climate targets—such as countries’ Nationally Determined Contributions (NDCs) - was not analyzed by the IEA because several countries had not released updated NDCs in 2025. Therefore, for comparison purposes, Petrobras continue to use the APS projections published in the WEO 2024 report.

^[4] The NZE scenario presented in the WEO 2025 outlines a pathway to achieve net zero energy-related CO₂ emissions by 2050. To this end, the agency highlights, for the first time, the trajectory of non-energy-related emissions, emphasizing the need to reduce deforestation as well as to expand the deployment of emissions-removal technologies.

The Company’s actions and goals for its transition to a low-carbon economy have not indicated that any assets may have been impaired.

A faster transition to a low-carbon economy than foreseen in Business Plan could result in Brent prices and demand for the Company’s products that are lower than the ones considered to estimate the value in use of the Company’s assets for impairment testing purposes.

The reduction in the value in use of the Company's assets may result in the recognition of losses due to the non-recoverability of the carrying amounts of these assets.

Given that the oil price is a variable that decisively influences the recoverable amount of assets, the Company carried out a sensitivity analysis of the effect of using the Brent prices considered in the APS and NZE scenarios, for the impairment test of the Company's E&P assets in Brazil.

Using the prices in the APS and NZE scenarios to perform a sensitivity analysis on projected gross revenues deducted of production taxes, net of income taxes, and keeping unchanged all other components, variables, assumptions and data for calculating the recoverable amount, the Company's E&P segment, regarding the impairment loss recognized by the Company, as disclosed in note 25, would have additional impairment reversal of US$ 303 in the APS scenario and additional impairment losses US$ 17,874 in the NZE scenario, concentrated in the Campos basin fields.

The Company does not consider this sensitivity analysis based on APS and NZE Brent price scenarios to be the best estimates to determine expected effects on the recoverable amount of assets, sales revenues or net income.

Considering that the Company did not incorporate in its accounting estimates the carbon price effects, the Company carried out a sensitivity analysis of the effect of GHG emissions pricing costs on the impairment test of assets in the E&P segment in Brazil, considering a monetary charge per ton of CO₂ equivalent emission starting from 2030, and the existence of free emission allowances.

In this context, using a base price of US$ 10/CO₂ in 2030, US$ 35.3/CO₂ in 2035, US$ 60.6/CO₂ in 2040, US$ 85.9/CO₂ in 2045, and US$ 111.2/CO₂ in 2050, considering emission allowances to be distributed free of charge, with gradual reduction, to simulate additional cash outflows (net of income taxes), and keeping all other components, variables, assumptions and data for the calculation of recoverable amount unchanged, the E&P segment would have an additional US$ 69 impairment loss.

The Company does not consider this sensitivity analysis of the effect of greenhouse gas emissions pricing costs on the impairment test of assets to be the best estimate to determine expected effects on the recoverable amount, neither the estimated effects on expenses nor net income.

a.2) Potential effects on decommissioning costs

Due to its operations, the Company has legal obligations to remove equipment and restore onshore and offshore areas. On December 31, 2025, the provision for decommissioning costs recognized by the Company, relating to E&P segment in Brazil, totaled US$ 28,400, as set out in note 21. On an undiscounted basis the nominal amount would be US$ 57,030.

The estimated timing used by the Company to account for decommissioning costs are consistent with the useful lives of the related assets. The average decommissioning period of oil and gas assets weighted by the carrying amounts of such assets is 14 years.

The Company’s actions and goals for its transition to a low-carbon economy have not materially affected the amount and period of its provision for decommissioning costs.

During 2025, there were no issuances of government regulations related to climate matters that changed or had potential to change the amount and period for decommissioning the Company's assets.

A transition to a low-carbon economy that is faster than anticipated by the Company may accelerate the timing to remove equipment and restore onshore or offshore areas. Such acceleration would increase the present value of the decommissioning obligations recognized by the Company.

To illustrate the effect of a possible acceleration of the transition to a low-carbon economy, the Company estimates that the provision for decommissioning costs would increase by US$ 1,318, US$ 4,067 and US$ 6,532 if the timing currently used were brought forward by one, three and five years, respectively. This sensitivity analysis assumed that all other components, variables, assumptions and data for calculating the provision remained unchanged. The year ranges used are not intended to be predictions of likely future events or outcomes.

a.3) Potential effects on “highly probable future exports” used in cash flow hedge accounting involving the Company's future exports

A transition to a low-carbon economy that is faster than it was anticipated by the Company may negatively effect the Company's future exports. Such effect may result in certain exports, whose foreign exchange gains or losses were designated for hedge accounting, no longer be considered highly probable, but remain forecasted, or, depending on the magnitude of the transition and its speed, cease to be considered forecasted. The consequences of such effects are described in the accounting policy of note 33.3.1 (a) involving the Company's future exports.

The calculation of “highly probable future exports” is based on the projected exports in Business Plan 2026-2030, as set out in note 4.8. The Company considers only a portion of its projected exports as “highly probable future exports”. When determining future exports as highly probable, and therefore eligible as a hedged item for application of cash flow hedge accounting, the Company considers the effects related to the transition to a low-carbon economy. Carbon prices were not incorporated in such estimates.

The Company’s actions and goals for its transition to a low-carbon economy have not materially affected its highly probable future exports.

Using the prices in the APS and NZE scenarios we carried out a sensitivity analysis to simulate the need to reclassify the foreign exchange gains or losses recorded in equity to the statement of income. Such analysis simulated a new future cash flow from exports, changing only the oil price, keeping all other components, variables, assumptions and data unchanged. In such an analysis, it would be necessary to reclassify the foreign exchange losses, in the amount of US$ 16, recorded in equity to the statement of income in the NZE scenario.

The simulations used to perform such sensitivity analysis, based on Brent prices of the scenarios APS and NZE, are not considered by the Company as the best estimates to determine expected effects of the reclassification of foreign exchange variation recorded in equity to the statement of income.

a.4) Potential effects on the useful lives of PP&E

A transition to a low-carbon economy that is faster than the Company anticipates may reduce the useful life of its assets, which could lead to an increase in annual depreciation, depletion and amortization expenses.

Assets directly related to the production of oil and gas in a contracted area are depleted using the units of production method and depreciated or amortized using the straight-line method. As of December 31, 2025, the carrying amount of these assets in operation in Brazil is US$ 108,424. Based on this carrying amount and assuming current depreciation and amortization rates are maintained, the balance of these assets would not be material by 2050. This simulation is not considered by the Company to represent an expectation of carrying amounts in 2050.

As mentioned in item “Transition risk to low carbon economy”, the reference scenario of the Strategic Plan indicates that there will be persistent global demand for oil in the coming decades. Additionally, calculations of expected production and oil and gas reserves in this scenario consider the effects of the transition to a low-carbon economy.

The Company's refining plants consist of 11 refineries and 2 fertilizer plants in Brazil. Based on the current depreciation rates of the assets in operation applied to the respective carrying amounts at December 31, 2025, which amounts to US$ 9,702, and assuming no additional investment, these refineries would have no material depreciation amounts after 2050. This simulation is not considered by the Company to represent an expectation of carrying amounts in 2050.

The Company estimates persistent demand for oil products in the coming decades, although decreasing, which should be progressively supplied by models with lower carbon intensity. Thus, the depreciation rates used by the Company for the refining plants are in line with the transition to a low-carbon economy.

The Gas and Energy assets in Brazil, including thermoelectric power plants, are depreciated using the linear method. Based on the current depreciation rates of the assets in operation applied to their respective carrying amounts as of December 31, 2025, totaling US$ 3,813, and assuming no additional investment, these assets would have no material depreciation amounts after 2050. This simulation is not considered by the Company to represent an expectation of carrying amounts in 2050.

In this context, based on available information, the Company does not foresee significant changes in the useful life of its refineries, assets directly related to oil and gas production and those related to the Gas and Energy arising from the transition to a low-carbon economy. Such assets represent 93% of the Company's total assets in operation.

Physical risks result from climate change that can be event-driven (acute physical risk) or from long-term shifts in climate patterns (chronic physical risk). In this category, the Company does not foresee that changes caused by climate change will have a material effect on accounting estimates, considering the risks currently identified.

The Company systematically identifies opportunities to decarbonize its operations and, in line with its strategy focused on oil and gas with economic and environmental resilience, has been investing in initiatives aimed at reducing or avoiding greenhouse gas emissions.

The following table presents the balance of expenditures capitalized in the carrying amounts of long-term assets related to investments made in decarbonization initiatives within the Company’s operational activities:

The Company estimated expenditures on decarbonization asset projects for the fiscal year 2025 in the amounts of US$ 507 for E&P, US$ 55 for RT&M and US$ 27 for G&LCE, with actual expenditures in 2025 totaling US$ 503, US$ 67 and US$ 23, respectively.

The main investments made refer to decarbonization technologies in new production systems to be used in the pre-salt layer, which are being incorporated into seven FPSOs (Floating Production, Storage and Offloading units) associated with production development projects in oil and gas fields where Petrobras acts in partnerships, as presented below:

As these technologies are inseparable from the FPSOs, the amounts related to decarbonization technologies are determined by multiplying the total expenditures incurred under the contract by an index representing the construction cost of the FPSO with and without the technology.

These fields integrate CGUs with no impairment loss recognized in the consolidated financial statements of 2025.

The incorporation of these decarbonization technologies ensures that the new units present lower carbon intensities, which is crucial for achieving the GHG emissions reduction targets set out in Business Plan 2026-2030.

As described in Business Plan 2026-2030, the Company has 5 commitments to reduce GHG emissions under operational control (scopes 1 and 2) by 2030. One of the commitments involves reducing absolute operational emissions by 30% by 2030, when compared to 2015.

The commitments to reduce GHG emissions do not constitute guarantees of future performance by the Company and are subject to assumptions that may not materialize, as well as to risks and uncertainties that are difficult to predict. Furthermore, current and planned investments also do not constitute guarantees of achieving these commitments.

Emission offsets through carbon credits may be used as a complementary tool in the Company’s decarbonization initiatives. Transactions involving assets linked to GHG reduction, such as the acquisition and retirement of carbon credits, are not material for these consolidated financial statements. The use of carbon credits for this purpose does not constitute a guarantee of the Company’s performance.

Regarding the amendment effective as of January 1, 2026, according to the assessment made, the Company estimates that there will be no significant effects arising from the initial application on its consolidated financial statements.

In relation to the amendments effective as of January 1, 2027, the Company is assessing the effects that they will have on its consolidated financial statements.

The Company’s objective in its capital management is to maintain its capital structure at an adequate level in order to continue as a going concern, maximizing value to shareholders and investors. Its main source of funding is cash provided by operating activities.

The financial strategy of the Business Plan 2026-2030 consists of consolidating capital discipline measures focused on cost optimization, increased productivity and operational efficiency, for the benefit of the Company's long-term sustainability. The main assumptions for the plan's viability are:

As of December 31, 2025, gross debt increased to US$ 69,793 from US$ 60,311 as of December 31, 2024, remaining within the range defined in the Company’s Business Plan.

This measure is not defined according to the IFRS accounting standards and should not be considered in isolation or as a replacement for debt metrics under those standards, nor should it be used as a basis for comparison with the indicators of other companies.

They include cash, available bank deposits and financial investments with high liquidity, which meet the definition of cash equivalents.

Financial investments classified as cash equivalents have maturities of up to three months from the date of their acquisition. In Brazil, it primarily consists of repurchase agreements and investments in funds holding Brazilian Federal Government Bonds, as well as floating rate Bank Deposit Certificates with daily liquidity. Short-term financial investments abroad mainly comprise time deposits, as well as investments with daily liquidity.

Cash and cash equivalents were mainly provided by operating activities (US$ 36,047), proceeds from finance debt (US$ 5,320), divestments in financial investments (US$ 2,784), proceeds from disposal of assets - divestment (US$ 613) and financial compensation from co-participation agreements (US$ 355).

The main use of these funds in 2025 were for acquisition of PP&E and intangible assets in the amount of US$ 19,521, repayment of principal and interests related to finance debt and repayment of lease liability, amounting to US$ 14,571, as well as for payment of dividends of US$ 8,154.

Accounting policy for cash and cash equivalents

Cash and cash equivalents comprise cash on hand, term deposits with banks and short-term highly-liquid financial investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and have a maturity of three months or less from the date of acquisition.

Financial investments (not classified as cash equivalents) have maturities of more than three months. Financial investments classified as fair value through profit or loss refer mainly to investments in Brazilian Federal Government Bonds (level 1 of the fair value hierarchy). Financial investments classified as amortized cost mainly refer to investments in Brazil in floating rate Bank Deposit Certificates with daily liquidity, with initial maturities between one and two years, and to investments abroad in time deposits and government bonds.

Accounting policy for financial investments

The amounts invested in operations with terms of more than three months, as from the date of the agreement, are initially measured at fair value and subsequently according to their respective classifications, which are based on the way in which these funds are managed and their features of contractual cash flows:

Revenues from contracts with customers derive from different products sold by the Company’s operating segments, taking into consideration specific characteristics of the markets where they operate. For additional information about the operating segments of the Company, its activities and its respective products sold, see note 13.

The determination of transaction prices derives from methodologies and policies based on the parameters of these markets, reflecting operating risks, level of market share, changes in exchange rates and international commodity prices, including Brent oil prices, oil products such as diesel and gasoline, and the Henry Hub Index.

As of December 31, 2025, the composition of sales revenues by shipping destination is presented as follows:

In 2025, sales to two clients of the refining, transportation and marketing (RT&M) segment represented individually 14% and 10% of the Company’s sales revenues; in 2024, sales to two clients of the RT&M segment represented individually 15% and 10% of the Company’s sales revenues; in 2023, sales to two clients of the RT&M segment represented individually 16% and 11% of the Company’s sales revenues. For more information about RT&M segment, see note 13 – Information by operating segment.

Certain sales contracts signed through December 31, 2025, with original expected duration of equal to or more than 1 year, define the volume and timing of goods or services to be delivered during the term of the contract, and the payment terms for these future sales.

The estimated remaining values of these contracts in 2025 presented below are based on the contractually agreed future sales volumes, as well as prices prevailing at December 31, 2025 or practiced in recent sales reflecting more directly observable information:

Revenues are recognized once goods are transferred and services are provided to the customers and their measurement and timing of recognition will be subject to future demands, changes in commodities prices, exchange rates and other market factors.

The table above does not include information on contracts with original expected duration of less than one year, such as spot-market contracts, variable considerations which are constrained, and information on contracts only establishing general terms and conditions (Master Agreements), for which volumes and prices will only be defined in subsequent contracts.

In addition, electricity sales are mainly driven by demands to generate electricity from thermoelectric power plants, as and when requested by the Brazilian National Electric System Operator (ONS). These requests are substantially affected by Brazilian hydrological conditions. Thus, the table above presents mainly fixed amounts for the electricity to be available to customers in these operations.

The balance of contract liabilities carried on the statement of financial position in 2025 amounted to US$ 76 (US$ 64 in 2024). This amount is classified in current liabilities and primarily comprises advances from customers in take or pay contracts to be recognized as revenue based on future sales of natural gas or following the non-exercise of the right by the customer.

Accounting policy for revenues

The Company evaluates contracts with customers for the sale of oil and oil products, natural gas, electricity, services and other products, which will be subject to revenue recognition, and identifies the distinct goods and services promised in each of them.

Sales revenues are recognized when control is transferred to the client, which usually occurs upon delivery of the product or when the service is provided. At this moment, the Company satisfies the performance obligation.

Performance obligations are considered to be promises to transfer to the client: (i) good or service (or group of goods or services) that is distinct; and (ii) a series of distinct goods or services that have the same characteristics or are substantially the same and that have the same pattern of transfer to the client.

Revenue is measured based on the amount of consideration to which the Company expects to be entitled in exchange for transfers of promised goods or services to the customer, excluding amounts collected on behalf of third parties. Transaction prices are based on contractually stated prices, which reflect the Company's pricing methodologies and policies based on market parameters.

Invoicing occurs in periods very close to deliveries and rendering of services, therefore, significant changes in transaction prices are not expected to be recognized in revenues for periods subsequent to satisfaction of the performance obligation, except for some exports in which final price formation occurs after the transfer of control of the products and are subject to the variation in the value of the commodity.

Sales are carried out in short terms of receipt, thus there are no significant financing components.

The amount of depreciation, depletion and amortization by segment is set forth as follows: